10-Q/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

Amendment No. 1

x     QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2012

OR

o    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, states of incorporation, addresses of principal executive offices, and telephone numbers	I.R.S. Employer Identification Number
1-15929	Progress Energy, Inc. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone:   (919) 546-6111 State of Incorporation: North Carolina	56-2155481
1-3382	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	56-0165465
1-3274	Florida Power Corporation d/b/a Progress Energy Florida, Inc. 299 First Avenue North St. Petersburg, Florida  33701 Telephone:   (727) 820-5151 State of Incorporation: Florida	59-0247770

NONE

(Former name, former address and former fiscal year, 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.

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

Indicate by check mark whether each registrant has submitted electronically and posted to its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).

Progress Energy	Yes	x	No	o
PEC	Yes	x	No	o
PEF	Yes	x	No	o

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Progress Energy	Large accelerated filer	x	Accelerated filer	o
	Non-accelerated filer	o	Smaller reporting company	o
PEC	Large accelerated filer	o	Accelerated filer	o
	Non-accelerated filer	x	Smaller reporting company	o
PEF	Large accelerated filer	o	Accelerated filer	o
	Non-accelerated filer	x	Smaller reporting company	o

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Progress Energy	Yes	o	No	x
PEC	Yes	o	No	x
PEF	Yes	o	No	x

At May 3, 2012, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Without Par Value)	296,021,515
PEC	Common Stock (Without Par Value)	159,608,055 (all of which were held directly by Progress Energy, Inc.)
PEF	Common Stock (Without Par Value)	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 (collectively, the Progress Registrants). 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.

EXPLANATORY NOTE

This Amendment No. 1 on Form 10−Q/A (this Amendment) amends the Quarterly Report on Form 10-Q of Progress Energy, Inc., Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF) (collectively, the Progress Registrants) for the quarterly period ended March 31, 2012, originally filed with the Securities and Exchange Commission on May 8, 2012 (the Original Filing). This Amendment is being filed solely to include certain Extensible Business Reporting Language (XBRL) information in Exhibit 101 that was inadvertently excluded from the timely filed Original Filing, in accordance with Rule 405 of Regulation S−T.

Exhibit 101 provides the following financial statements and notes thereto for the Progress Registrants from the Original Filing, formatted in XBRL: (i) the Unaudited Condensed Consolidated Statements of Comprehensive Income, (ii) the Unaudited Condensed Consolidated Balance Sheets, (iii) the Unaudited Condensed Consolidated Statement of Cash Flows, and (iv) the Notes to Unaudited Condensed Interim Financial Statements, which are tagged as blocks of text in respect to PEC and PEF’s disclosures.

In accordance with Rule 406T of Regulation S-T, the XBRL-related information for PEC and PEF in Exhibit 101 is deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

Except as described above, no other changes have been made to the Original Filing, and this Amendment does not modify or update the other disclosures presented in the Original Filing, including, without limitation, the financial statements. This Amendment speaks as of the date of the Original Filing and does not reflect any events that occurred at a date subsequent to the filing of the Original Filing. Accordingly, this Amendment should be read in conjunction with the Original Filing and the Progress Registrants’ other filings made with the Securities and Exchange Commission subsequent to the filing of the Original Filing.

3

ITEM 6.                 EXHIBITS

(a)   Exhibits

Exhibit Number	Description	Progress Energy	PEC	PEF
*10(a)	Progress Energy, Inc. Amended and Restated Credit Agreement dated as of February 15, 2012 (filed as Exhibit 10.1 to Current Report on Form 8-K dated February 15, 2012, File No. 1-15929).	X
**10(b)	Amendment, adopted on March 14, 2012, to the Supplemental Senior Executive Retirement Plan of Progress Energy, Inc.	X	X	X
**31(a)	302 Certifications of Chief Executive Officer	X
**31(b)	302 Certifications of Chief Financial Officer	X
**31(c)	302 Certifications of Chief Executive Officer		X
**31(d)	302 Certifications of Chief Financial Officer		X
**31(e)	302 Certifications of Chief Executive Officer			X
**31(f)	302 Certifications of Chief Financial Officer			X
**32(a)	906 Certifications of Chief Executive Officer	X
**32(b)	906 Certifications of Chief Financial Officer	X
**32(c)	906 Certifications of Chief Executive Officer		X
**32(d)	906 Certifications of Chief Financial Officer		X
**32(e)	906 Certifications of Chief Executive Officer			X
**32(f)	906 Certifications of Chief Financial Officer			X
101.INS	XBRL Instance Document***	X	X	X
101.SCH	XBRL Taxonomy Extension Schema Document	X	X	X
101.CAL	XBRL Taxonomy Calculation Linkbase Document	X	X	X
101.LAB	XBRL Taxonomy Label Linkbase Document	X	X	X
101.PRE	XBRL Taxonomy Presentation Linkbase Document	X	X	X
101.DEF	XBRL Taxonomy Definition Linkbase Document	X	X	X

* Incorporated herein by reference as indicated.

4

** Previously filed with the Registrants’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, filed on May 8, 2012.

*** Attached as Exhibit 101 in this Form 10-Q are the following financial statements and notes thereto for Progress Energy, PEC and PEF from the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, formatted in Extensible Business Reporting Language (XBRL): (i) the Unaudited Condensed Consolidated Statements of Comprehensive Income, (ii) the Unaudited Condensed Consolidated Balance Sheets, (iii) the Unaudited Condensed Consolidated Statement of Cash Flows, and (iv) the Notes to Unaudited Condensed Interim Financial Statements, which are tagged as blocks of text in respect to PEC and PEF’s disclosures.

In accordance with Rule 406T of Regulation S-T, the XBRL-related information for PEC and PEF in Exhibit 101 to this Quarterly Report on Form 10-Q is deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act, is deemed not filed for purposes of Section 18 of the Exchange Act and otherwise is not subject to liability under these sections.

5

SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

	PROGRESS ENERGY, INC.
	CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
	FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
Date: August 8, 2012	(Registrants)
	By: /s/ Steven K. Young
	Steven K. Young
	Vice President, Chief Accounting Officer and Controller

6

XML

Benefit Plans - Costs of Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Pension Benefits
Defined benefit plan disclosure
Service cost	$ 16		$ 13
Interest cost	33		35
Expected return on plan assets	(46)		(45)
Amortization of actuarial loss	23	[1]	14	[1]
Other amortization, net	2	[1]	2	[1]
Net periodic cost	28		19
Other Postretirement Benefits
Defined benefit plan disclosure
Service cost	3		3
Interest cost	10		10
Expected return on plan assets	0		0
Amortization of actuarial loss	6	[1]	3	[1]
Other amortization, net	1	[1]	1	[1]
Net periodic cost	$ 20		$ 17

[1] Adjusted to reflect PEF’s rate treatment. See Note 17B in the 2011 Form 10-K.

XML

Condensed Consolidating Statements (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011	Dec. 31, 2010
Operating revenues
Operating revenues	$ 2,092	$ 2,167
Affiliate revenues	0	0
Total revenues	2,092	2,167
Operating expenses
Fuel used in electric generation	685	718
Purchased power	210	220
Operation and maintenance	529	494
Depreciation, amortization and accretion	166	154
Taxes other than on income	138	140
Other	0	(10)
Total operating expenses	1,728	1,716
Operating (loss) income	364	451
Other income (expense)
Interest income	1	1
Allowance for equity funds used during construction	24	29
Other, net	13	3
Total other income (expense), net	38	33
Interest charges
Interest charges	194	199
Allowance for borrowed funds used during construction	(9)	(9)
Total interest charges, net	185	190
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries	217	294
Income tax (benefit) expense	76	107
Income from continuing operations	141	187
Discontinued operations, net of tax	11	(2)
Net income (loss)	152	185
Net income attributable to noncontrolling interests, net of tax	(2)	(1)
Net income attributable to controlling interests	150	184
Comprehensive income
Comprehensive income	157	189
Comprehensive (income) loss attributable to noncontrolling interests, net of tax	(2)	(1)
Comprehensive income attributable to controlling interests	155	188
ASSETS
Utility plant, net	22,805		22,497
Current assets
Cash and cash equivalents	565	172
Receivables, net	758		889
Notes receivable from affiliated companies	0		0
Regulatory assets	250		275
Derivative collateral posted	166		147
Prepayments and other current assets	2,096		1,942
Total current assets	3,835		3,483
Deferred debits and other assets
Investment in consolidated subsidiaries	0		0
Regulatory assets	3,123		3,025
Goodwill	3,655		3,655
Nuclear decommissioning trust funds	1,762		1,647
Other assets and deferred debits	795		752
Total deferred debits and other assets	9,335		9,079
Total assets	35,975		35,059
Equity
Common stock equity	10,009		10,021
Noncontrolling interests	2		4
Total equity	10,011	10,050	10,025	10,027
Preferred stock of subsidiaries	93		93
Long-term debt, affiliate	273		273
Long-term debt, net	11,742		11,718
Total capitalization	22,119		22,109
Current liabilities
Current portion of long-term debt	1,375		950
Short-term debt	1,056		671
Notes payable to affiliated companies	0		0
Derivative liabilities	484		436
Other current liabilities	1,847		2,028
Total current liabilities	4,762		4,085
Deferred credits and other liabilities
Noncurrent income tax liabilities	2,637		2,355
Regulatory liabilities	2,684		2,700
Other liabilities and deferred credits	3,773		3,810
Total deferred credits and other liabilities	9,094		8,865
Total capitalization and liabilities	35,975		35,059
Condensed Consolidating Statement of Cash Flows
Net cash provided (used) by operating activities	356	446
Investing activities
Gross property additions	(562)	(501)
Nuclear fuel additions	(51)	(57)
Purchases of available-for-sale securities and other investments	(363)	(1,817)
Proceeds from available-for-sale securities and other investments	359	1,809
Other investing activities	65	46
Net cash provided (used) by investing activities	(552)	(520)
Financing activities
Issuance of common stock, net	3	8
Dividends paid on common stock	(260)	(183)
Proceeds from issuance of short-term debt with original maturities greater than 90 days	65	0
Net increase (decrease) in short-term debt	320	79
Proceeds from issuance of long-term debt, net	444	494
Retirement of long-term debt	0	(700)
Other financing activities	(41)	(63)
Net cash provided (used) by financing activities	531	(365)
Net increase (decrease) in cash and cash equivalents	335	(439)
Cash and cash equivalents at beginning of period	230	611
Cash and cash equivalents at end of period	565	172
Parent
Operating revenues
Operating revenues	0	0
Affiliate revenues	0	0
Total revenues	0	0
Operating expenses
Fuel used in electric generation	0	0
Purchased power	0	0
Operation and maintenance	1	3
Depreciation, amortization and accretion	0	0
Taxes other than on income	0	0
Other	0	0
Total operating expenses	1	3
Operating (loss) income	(1)	(3)
Other income (expense)
Interest income	1	0
Allowance for equity funds used during construction	0	0
Other, net	8	0
Total other income (expense), net	9	0
Interest charges
Interest charges	66	73
Allowance for borrowed funds used during construction	0	0
Total interest charges, net	66	73
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries	(58)	(76)
Income tax (benefit) expense	(22)	(31)
Equity in earnings of consolidated subsidiaries	186	229
Income from continuing operations	150	184
Discontinued operations, net of tax	0	0
Net income (loss)	150	184
Net income attributable to noncontrolling interests, net of tax	0	0
Net income attributable to controlling interests	150	184
Comprehensive income
Comprehensive income	155	188
Comprehensive (income) loss attributable to noncontrolling interests, net of tax	0	0
Comprehensive income attributable to controlling interests	155	188
ASSETS
Utility plant, net	0		0
Current assets
Cash and cash equivalents	511	3
Receivables, net	0		0
Notes receivable from affiliated companies	63		53
Regulatory assets	0		0
Derivative collateral posted	0		0
Prepayments and other current assets	135		128
Total current assets	709		298
Deferred debits and other assets
Investment in consolidated subsidiaries	13,968		14,043
Regulatory assets	0		0
Goodwill	0		0
Nuclear decommissioning trust funds	0		0
Other assets and deferred debits	116		140
Total deferred debits and other assets	14,084		14,183
Total assets	14,793		14,481
Equity
Common stock equity	10,009		10,021
Noncontrolling interests	0		0
Total equity	10,009		10,021
Preferred stock of subsidiaries	0		0
Long-term debt, affiliate	0		0
Long-term debt, net	3,992		3,543
Total capitalization	14,001		13,564
Current liabilities
Current portion of long-term debt	450		450
Short-term debt	255		250
Notes payable to affiliated companies	0		0
Derivative liabilities	0		38
Other current liabilities	65		161
Total current liabilities	770		899
Deferred credits and other liabilities
Noncurrent income tax liabilities	0		0
Regulatory liabilities	0		0
Other liabilities and deferred credits	22		18
Total deferred credits and other liabilities	22		18
Total capitalization and liabilities	14,793		14,481
Condensed Consolidating Statement of Cash Flows
Net cash provided (used) by operating activities	227	280
Investing activities
Gross property additions	0	0
Nuclear fuel additions	0	0
Purchases of available-for-sale securities and other investments	0	0
Proceeds from available-for-sale securities and other investments	0	0
Changes in advances to affiliated companies	(10)	(75)
Contributions to consolidated subsidiaries	0	(10)
Other investing activities	(14)	0
Net cash provided (used) by investing activities	(24)	(85)
Financing activities
Issuance of common stock, net	3	8
Dividends paid on common stock	(260)	(183)
Dividends paid to parent	0	0
Proceeds from issuance of short-term debt with original maturities greater than 90 days	0
Net increase (decrease) in short-term debt	5	79
Proceeds from issuance of long-term debt, net	444	494
Retirement of long-term debt	0	(700)
Changes in advances from affiliated companies	0	0
Contributions from parent	0	0
Other financing activities	(1)	0
Net cash provided (used) by financing activities	191	(302)
Net increase (decrease) in cash and cash equivalents	394	(107)
Cash and cash equivalents at beginning of period	117	110
Cash and cash equivalents at end of period	511	3
Subsidiary Guarantor
Operating revenues
Operating revenues	1,007	1,034
Affiliate revenues	0	0
Total revenues	1,007	1,034
Operating expenses
Fuel used in electric generation	336	355
Purchased power	145	153
Operation and maintenance	160	211
Depreciation, amortization and accretion	27	25
Taxes other than on income	82	85
Other	0	(10)
Total operating expenses	750	819
Operating (loss) income	257	215
Other income (expense)
Interest income	0	1
Allowance for equity funds used during construction	9	9
Other, net	1	5
Total other income (expense), net	10	15
Interest charges
Interest charges	73	75
Allowance for borrowed funds used during construction	(4)	(4)
Total interest charges, net	69	71
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries	198	159
Income tax (benefit) expense	73	60
Equity in earnings of consolidated subsidiaries	0	0
Income from continuing operations	125	99
Discontinued operations, net of tax	11	(1)
Net income (loss)	136	98
Net income attributable to noncontrolling interests, net of tax	(1)	(1)
Net income attributable to controlling interests	135	97
Comprehensive income
Comprehensive income	137	99
Comprehensive (income) loss attributable to noncontrolling interests, net of tax	(1)	(1)
Comprehensive income attributable to controlling interests	136	98
ASSETS
Utility plant, net	10,596		10,523
Current assets
Cash and cash equivalents	33	55
Receivables, net	346		372
Notes receivable from affiliated companies	7		0
Regulatory assets	225		244
Derivative collateral posted	136		123
Prepayments and other current assets	960		852
Total current assets	1,707		1,683
Deferred debits and other assets
Investment in consolidated subsidiaries	0		0
Regulatory assets	1,659		1,602
Goodwill	0		0
Nuclear decommissioning trust funds	599		559
Other assets and deferred debits	255		242
Total deferred debits and other assets	2,513		2,403
Total assets	14,816		14,609
Equity
Common stock equity	4,759		4,728
Noncontrolling interests	2		4
Total equity	4,761		4,732
Preferred stock of subsidiaries	34		34
Long-term debt, affiliate	309		309
Long-term debt, net	4,057		4,482
Total capitalization	9,161		9,557
Current liabilities
Current portion of long-term debt	425		0
Short-term debt	360		233
Notes payable to affiliated companies	198		238
Derivative liabilities	335		268
Other current liabilities	836		839
Total current liabilities	2,154		1,578
Deferred credits and other liabilities
Noncurrent income tax liabilities	990		837
Regulatory liabilities	967		1,071
Other liabilities and deferred credits	1,544		1,566
Total deferred credits and other liabilities	3,501		3,474
Total capitalization and liabilities	14,816		14,609
Condensed Consolidating Statement of Cash Flows
Net cash provided (used) by operating activities	166	257
Investing activities
Gross property additions	(197)	(218)
Nuclear fuel additions	(13)	(7)
Purchases of available-for-sale securities and other investments	(225)	(1,661)
Proceeds from available-for-sale securities and other investments	226	1,661
Changes in advances to affiliated companies	(7)	21
Contributions to consolidated subsidiaries	0	0
Other investing activities	15	43
Net cash provided (used) by investing activities	(201)	(161)
Financing activities
Issuance of common stock, net	0	0
Dividends paid on common stock	0	0
Dividends paid to parent	(108)	(328)
Proceeds from issuance of short-term debt with original maturities greater than 90 days	65
Net increase (decrease) in short-term debt	62	0
Proceeds from issuance of long-term debt, net	0	0
Retirement of long-term debt	0	0
Changes in advances from affiliated companies	(40)	11
Contributions from parent	0	10
Other financing activities	(3)	(4)
Net cash provided (used) by financing activities	(24)	(311)
Net increase (decrease) in cash and cash equivalents	(59)	(215)
Cash and cash equivalents at beginning of period	92	270
Cash and cash equivalents at end of period	33	55
Non-Guarantor Subsidiaries
Operating revenues
Operating revenues	1,085	1,133
Affiliate revenues	59	74
Total revenues	1,144	1,207
Operating expenses
Fuel used in electric generation	349	363
Purchased power	65	67
Operation and maintenance	422	351
Depreciation, amortization and accretion	139	129
Taxes other than on income	58	59
Other	0	0
Total operating expenses	1,033	969
Operating (loss) income	111	238
Other income (expense)
Interest income	0	0
Allowance for equity funds used during construction	15	20
Other, net	2	(2)
Total other income (expense), net	17	18
Interest charges
Interest charges	55	51
Allowance for borrowed funds used during construction	(5)	(5)
Total interest charges, net	50	46
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries	78	210
Income tax (benefit) expense	27	80
Equity in earnings of consolidated subsidiaries	0	0
Income from continuing operations	51	130
Discontinued operations, net of tax	0	(1)
Net income (loss)	51	129
Net income attributable to noncontrolling interests, net of tax	0	0
Net income attributable to controlling interests	51	129
Comprehensive income
Comprehensive income	55	132
Comprehensive (income) loss attributable to noncontrolling interests, net of tax	0	0
Comprehensive income attributable to controlling interests	55	132
ASSETS
Utility plant, net	12,124		11,887
Current assets
Cash and cash equivalents	21	114
Receivables, net	412		517
Notes receivable from affiliated companies	172		219
Regulatory assets	25		31
Derivative collateral posted	30		24
Prepayments and other current assets	1,134		1,049
Total current assets	1,794		1,861
Deferred debits and other assets
Investment in consolidated subsidiaries	0		0
Regulatory assets	1,464		1,423
Goodwill	0		0
Nuclear decommissioning trust funds	1,163		1,088
Other assets and deferred debits	869		856
Total deferred debits and other assets	3,496		3,367
Total assets	17,414		17,115
Equity
Common stock equity	5,536		5,646
Noncontrolling interests	0		0
Total equity	5,536		5,646
Preferred stock of subsidiaries	59		59
Long-term debt, affiliate	0		0
Long-term debt, net	3,693		3,693
Total capitalization	9,288		9,398
Current liabilities
Current portion of long-term debt	500		500
Short-term debt	441		188
Notes payable to affiliated companies	44		34
Derivative liabilities	149		130
Other current liabilities	1,084		1,112
Total current liabilities	2,218		1,964
Deferred credits and other liabilities
Noncurrent income tax liabilities	2,062		1,976
Regulatory liabilities	1,632		1,543
Other liabilities and deferred credits	2,214		2,234
Total deferred credits and other liabilities	5,908		5,753
Total capitalization and liabilities	17,414		17,115
Condensed Consolidating Statement of Cash Flows
Net cash provided (used) by operating activities	245	337
Investing activities
Gross property additions	(365)	(283)
Nuclear fuel additions	(38)	(50)
Purchases of available-for-sale securities and other investments	(138)	(156)
Proceeds from available-for-sale securities and other investments	133	148
Changes in advances to affiliated companies	47	42
Contributions to consolidated subsidiaries	0	0
Other investing activities	64	5
Net cash provided (used) by investing activities	(297)	(294)
Financing activities
Issuance of common stock, net	0	0
Dividends paid on common stock	0	0
Dividends paid to parent	(175)	(100)
Proceeds from issuance of short-term debt with original maturities greater than 90 days	0
Net increase (decrease) in short-term debt	253	0
Proceeds from issuance of long-term debt, net	0	0
Retirement of long-term debt	0	0
Changes in advances from affiliated companies	11	0
Contributions from parent	0	0
Other financing activities	(37)	(60)
Net cash provided (used) by financing activities	52	(160)
Net increase (decrease) in cash and cash equivalents	0	(117)
Cash and cash equivalents at beginning of period	21	231
Cash and cash equivalents at end of period	21	114
Other
Operating revenues
Operating revenues	0	0
Affiliate revenues	(59)	(74)
Total revenues	(59)	(74)
Operating expenses
Fuel used in electric generation	0	0
Purchased power	0	0
Operation and maintenance	(54)	(71)
Depreciation, amortization and accretion	0	0
Taxes other than on income	(2)	(4)
Other	0	0
Total operating expenses	(56)	(75)
Operating (loss) income	(3)	1
Other income (expense)
Interest income	0	0
Allowance for equity funds used during construction	0	0
Other, net	2	0
Total other income (expense), net	2	0
Interest charges
Interest charges	0	0
Allowance for borrowed funds used during construction	0	0
Total interest charges, net	0	0
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries	(1)	1
Income tax (benefit) expense	(2)	(2)
Equity in earnings of consolidated subsidiaries	(186)	(229)
Income from continuing operations	(185)	(226)
Discontinued operations, net of tax	0	0
Net income (loss)	(185)	(226)
Net income attributable to noncontrolling interests, net of tax	(1)	0
Net income attributable to controlling interests	(186)	(226)
Comprehensive income
Comprehensive income	(190)	(230)
Comprehensive (income) loss attributable to noncontrolling interests, net of tax	(1)	0
Comprehensive income attributable to controlling interests	(191)	(230)
ASSETS
Utility plant, net	85		87
Current assets
Cash and cash equivalents	0	0
Receivables, net	0		0
Notes receivable from affiliated companies	(242)		(272)
Regulatory assets	0		0
Derivative collateral posted	0		0
Prepayments and other current assets	(133)		(87)
Total current assets	(375)		(359)
Deferred debits and other assets
Investment in consolidated subsidiaries	(13,968)		(14,043)
Regulatory assets	0		0
Goodwill	3,655		3,655
Nuclear decommissioning trust funds	0		0
Other assets and deferred debits	(445)		(486)
Total deferred debits and other assets	(10,758)		(10,874)
Total assets	(11,048)		(11,146)
Equity
Common stock equity	(10,295)		(10,374)
Noncontrolling interests	0		0
Total equity	(10,295)		(10,374)
Preferred stock of subsidiaries	0		0
Long-term debt, affiliate	(36)		(36)
Long-term debt, net	0		0
Total capitalization	(10,331)		(10,410)
Current liabilities
Current portion of long-term debt	0		0
Short-term debt	0		0
Notes payable to affiliated companies	(242)		(272)
Derivative liabilities	0		0
Other current liabilities	(138)		(84)
Total current liabilities	(380)		(356)
Deferred credits and other liabilities
Noncurrent income tax liabilities	(415)		(458)
Regulatory liabilities	85		86
Other liabilities and deferred credits	(7)		(8)
Total deferred credits and other liabilities	(337)		(380)
Total capitalization and liabilities	(11,048)		(11,146)
Condensed Consolidating Statement of Cash Flows
Net cash provided (used) by operating activities	(282)	(428)
Investing activities
Gross property additions	0	0
Nuclear fuel additions	0	0
Purchases of available-for-sale securities and other investments	0	0
Proceeds from available-for-sale securities and other investments	0	0
Changes in advances to affiliated companies	(30)	12
Contributions to consolidated subsidiaries	0	10
Other investing activities	0	(2)
Net cash provided (used) by investing activities	(30)	20
Financing activities
Issuance of common stock, net	0	0
Dividends paid on common stock	0	0
Dividends paid to parent	283	428
Proceeds from issuance of short-term debt with original maturities greater than 90 days	0
Net increase (decrease) in short-term debt	0	0
Proceeds from issuance of long-term debt, net	0	0
Retirement of long-term debt	0	0
Changes in advances from affiliated companies	29	(11)
Contributions from parent	0	(10)
Other financing activities	0	1
Net cash provided (used) by financing activities	312	408
Net increase (decrease) in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	$ 0	$ 0

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Guarantees (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Guarantee Obligations [Abstract]
Guarantee obligations maximum exposure	$ 234
Guarantee obligations unlimited exposure	Certain indemnifications related to discontinued operations have no limitations as to time or maximum potential future payments
Guarantee obligations current carrying value	43	63
Guarantee Obligations Related Party	$ 300

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Regulatory Matters - Retail Rate Matters (Details) (USD $)	3 Months Ended			30 Months Ended				3 Months Ended		12 Months Ended	3 Months Ended
	Mar. 31, 2012 PEC Demand Side Management and Energy Efficiency Cost Recovery Regulatory Costs Not Yet Approved South Carolina Rate	Mar. 31, 2012 PEF Base Rate Settlement Agreement Regulatory Costs Approved	Mar. 31, 2012 PEF Nuclear Cost Recovery Regulatory Costs Not Yet Approved	Mar. 31, 2012 PEF Nuclear Cost Recovery CR3 Outage weeks		Mar. 31, 2012 PEF Nuclear Cost Recovery Levy Units 1 And 2	Mar. 31, 2012 PEF Environmental Cost Recovery Clause Regulatory Costs Not Yet Approved	Mar. 31, 2012 PEF 2012 Settlement Agreement Regulatory Costs Approved	Mar. 31, 2012 PEF 2012 Settlement Agreement Regulatory Costs Approved Base Rates Customer Refund And Other	Dec. 31, 2011 PEF 2012 Settlement Agreement Regulatory Costs Approved Base Rates Customer Refund And Other	Mar. 31, 2012 PEF 2012 Settlement Agreement Regulatory Costs Approved Crystal River Three	Mar. 31, 2012 PEF 2012 Settlement Agreement Regulatory Costs Approved Proposed Levy Member
Public utilities, disclosure of date of regulatory filing	March 1, 2012		April 30, 2012
Increase in rates total	$ 5,000,000								$ 150,000,000
Public utilities, disclosure of effective date									January 2013			January 2013
Increase in rates per 1,000 kWH	1.37		2.23					4.93				3.45
Percent increase in rates								4.00%
Repair costs, range of possible costs, minimum				900,000,000
Repair costs, range of possible costs, maximum				1,300,000,000
Property, return to service date				2014
Replacement power insurance coverage weeks, primary				52
Replacement power insurance coverage amount per week, primary				4,500,000
Replacement power insurance coverage weeks, additional				71
Replacement power insurance coverage amount per week, additional				3,600,000
Replacement power insurance coverage amount, total				490,000,000
NEIL coverage per company at each nuclear plant				2,250,000,000
Insurance deductible per claim				10,000,000
Replacement power costs incurred				506,000,000
NEIL insurance recoveries related to replacement power costs				(162,000,000)
Estimated insurance recoveries, replacement power				(55,000,000)
Amount included in deferred fuel regulatory asset, replacement power costs				289,000,000	[1]
Amount of repair costs incurred				279,000,000
NEIL insurance recoveries related to repair costs				(143,000,000)
Estimated insurance recoveries, repair costs				0
Repair costs to be recovered				136,000,000	[1]
Public utilities, cost of removal reserve, reduction taken subject to regulatory order		58,000,000
Public utilities, cost of removal reserve, amount subject to regulatory order		216,000,000
Public utilities, rate of returns, authorized									11.50%
Public utilities, rate of returns below threshold, subject to regulatory order									9.50%
Amount for recovery of prior year deferral in future periods			88,000,000
Allowance for funds used during construction rate current									7.40%
Annual cost recovery			152,000,000
Public utilities, disclosure of end date								December 2016
2015 pro rata replacement power refund											40,000,000
2016 pro rata replacement power refund											60,000,000
Repair overrun maximum											400,000,000
Authorized ROE on retired plant											70.00%
Public utilities, rate of returns below threshold, subject to regulatory order, escalated									9.70%
Public utilities, rate of returns, authorized, escalated									11.70%
2013 Customer refunds									129,000,000
2014 Customer refunds									129,000,000
2014 Residential and small commercial customer refunds									10,000,000
2015 Residential and small commercial customer refunds									10,000,000
2016 Residential and small commercial customer refunds									10,000,000
Refund to customers recorded as a reduction to revenue										288,000,000
Property, Plant and Equipment, Additions, Proposed							79,000,000
Amount of Reduction to Carrying Amount of Regulatory Liabilities									47,000,000
Construction project cost estimates range, high end						24,000,000,000
Construction project cost estimates range, low end						$ 19,000,000,000
Plant in-service date, projected						2024

[1] See "2012 Settlement Agreement" below for discussion of PEF's ability to recover prudently incurred fuel and purchased power costs and CR3 repair costs.

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Fair Value Disclosures (Tables)

3 Months Ended

Mar. 31, 2012

Fair Value Disclosures Tables [Abstract]

Available for sale securities

(in millions)		Fair Value		Unrealized Losses		Unrealized Gains
March 31, 2012
Common stock equity		$	1,160	$	16	$	508
Preferred stock and other equity			43		-		14
Corporate debt			90		-		7
U.S. state and municipal debt			124		2		7
U.S. and foreign government debt			293		-		14
Money market funds and other			55		1		1
	Total	$	1,765	$	19	$	551
December 31, 2011
Common stock equity		$	1,033	$	29	$	401
Preferred stock and other equity			29		-		11
Corporate debt			86		-		6
U.S. state and municipal debt			128		2		7
U.S. and foreign government debt			284		-		18
Money market funds and other			70		-		1
	Total	$	1,630	$	31	$	444

Available for sale debt securities by contractual maturity

(in millions)
Due in one year or less	$	34
Due after one through five years		217
Due after five through 10 years		175
Due after 10 years		94
Total	$	520

Sales of available for sale securities

(in millions)	2012		2011
Proceeds	$	304	$	1,744
Realized gains		7		9
Realized losses		3		4

Fair value measurements- assets and liabilities

PROGRESS ENERGY
(in millions)			Level 1		Level 2		Level 3		Total
March 31, 2012
Assets
	Nuclear decommissioning trust funds
		Common stock equity	$	1,160	$	-	$	-	$	1,160
		Preferred stock and other equity		33		10		-		43
		Corporate debt		-		90		-		90
		U.S. state and municipal debt		-		124		-		124
		U.S. and foreign government debt		129		164		-		293
		Money market funds and other		1		51		-		52
	Total nuclear decommissioning trust funds			1,323		439		-		1,762
	Derivatives
		Commodity forward contracts		-		8		-		8
	Other marketable securities
		Money market and other		18		-		-		18
		Total assets	$	1,341	$	447	$	-	$	1,788
Liabilities
	Derivatives
		Commodity forward contracts	$	-	$	769	$	27	$	796
		Interest rate contracts		-		49		-		49
		Contingent value obligations derivatives		-		3		-		3
		Total liabilities	$	-	$	821	$	27	$	848
(in millions)				Level 1		Level 2		Level 3		Total
December 31, 2011
Assets
	Nuclear decommissioning trust funds
		Common stock equity	$	1,033	$	-	$	-	$	1,033
		Preferred stock and other equity		28		1		-		29
		Corporate debt		-		86		-		86
		U.S. state and municipal debt		-		128		-		128
		U.S. and foreign government debt		87		197		-		284
		Money market funds and other		-		87		-		87
	Total nuclear decommissioning trust funds			1,148		499		-		1,647
	Derivatives
		Commodity forward contracts		-		5		-		5
	Other marketable securities
		Money market and other		20		-		-		20
		Total assets	$	1,168	$	504	$	-	$	1,672
Liabilities
	Derivatives
		Commodity forward contracts	$	-	$	668	$	24	$	692
		Interest rate contracts		-		93		-		93
		Contingent value obligations derivatives		-		14		-		14
		Total liabilities	$	-	$	775	$	24	$	799

Fair value, liabilities measured on recurring basis, unobservable input reconciliation

PROGRESS ENERGY
(in millions)	2012		2011
Derivatives, net at January 1	$	24	$	36
Total unrealized losses (gains) deferred as regulatory assets and liabilities, net		3		(4)
Derivatives, net at March 31	$	27	$	32

Fair Value Inputs Liabilities Quantitative Information [Table Text Block]

PROGRESS ENERGY
(in millions)	Fair Value		Valuation Technique	Unobservable Input		Range (price per MMBtu)
March 31, 2012
Commodity natural gas hedges	$	27	Discounted cash flow	Forward natural gas curves	$	4.111	-	4.528

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Risk Management Activities and Derivatives Transactions (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								3 Months Ended								3 Months Ended																						3 Months Ended
	Mar. 31, 2012 years gal MMBTU	Dec. 31, 2011	Mar. 31, 2012 Derivatives designated as hedging instruments	Dec. 31, 2011 Derivatives designated as hedging instruments	Mar. 31, 2012 Derivatives not designated as hedging instruments	Dec. 31, 2011 Derivatives not designated as hedging instruments	Mar. 31, 2012 Fair value of derivatives not designated as hedging instruments Derivatives not designated as hedging instruments	Dec. 31, 2011 Fair value of derivatives not designated as hedging instruments Derivatives not designated as hedging instruments	Mar. 31, 2012 Interest rate derivatives Derivatives designated as hedging instruments		Mar. 31, 2011 Interest rate derivatives Derivatives designated as hedging instruments		Mar. 31, 2012 Interest rate derivatives Derivative liabilities, current Derivatives designated as hedging instruments	Dec. 31, 2011 Interest rate derivatives Derivative liabilities, current Derivatives designated as hedging instruments	Mar. 31, 2012 Interest rate derivatives Derivative liabilities, long-term Derivatives designated as hedging instruments	Dec. 31, 2011 Interest rate derivatives Derivative liabilities, long-term Derivatives designated as hedging instruments	Mar. 31, 2012 Commodity derivatives Derivatives not designated as hedging instruments		Mar. 31, 2011 Commodity derivatives Derivatives not designated as hedging instruments		Mar. 31, 2012 Commodity derivatives Prepayments and other current assets Derivatives not designated as hedging instruments		Dec. 31, 2011 Commodity derivatives Prepayments and other current assets Derivatives not designated as hedging instruments		Mar. 31, 2012 Commodity derivatives Other assets and deferred debits Derivatives not designated as hedging instruments		Mar. 31, 2012 Commodity derivatives Derivative liabilities, current Derivatives designated as hedging instruments	Dec. 31, 2011 Commodity derivatives Derivative liabilities, current Derivatives designated as hedging instruments	Mar. 31, 2012 Commodity derivatives Derivative liabilities, current Derivatives not designated as hedging instruments		Dec. 31, 2011 Commodity derivatives Derivative liabilities, current Derivatives not designated as hedging instruments		Mar. 31, 2012 Commodity derivatives Derivative liabilities, long-term Derivatives designated as hedging instruments	Dec. 31, 2011 Commodity derivatives Derivative liabilities, long-term Derivatives designated as hedging instruments	Mar. 31, 2012 Commodity derivatives Derivative liabilities, long-term Derivatives not designated as hedging instruments		Dec. 31, 2011 Commodity derivatives Derivative liabilities, long-term Derivatives not designated as hedging instruments		Mar. 31, 2012 CVOs Derivatives not designated as hedging instruments		Dec. 31, 2011 CVOs Other liabilities, current Derivatives not designated as hedging instruments		Mar. 31, 2012 CVOs Other liabilities and deferred credits Derivatives not designated as hedging instruments		Mar. 31, 2012 Fair value loss transition adjustment Derivative liabilities, current Derivatives not designated as hedging instruments	Dec. 31, 2011 Fair value loss transition adjustment Derivative liabilities, current Derivatives not designated as hedging instruments	Mar. 31, 2012 Fair value loss transition adjustment Derivative liabilities, long-term Derivatives not designated as hedging instruments	Dec. 31, 2011 Fair value loss transition adjustment Derivative liabilities, long-term Derivatives not designated as hedging instruments
Economic derivatives
Cash collateral posted	$ 166	$ 147
Notional MMBtu of natural gas	402,800,000
Notional gallons of oil	10,200,000
Interest rate cash flow hedges
Open interest rate hedges mandatory termination dates	2
After-tax (gains) losses in accumulated other comprehensive income	136	141
Next 12 months amount of (gains) losses to reclass to interest expense	13
Notional amount of interest rate cash flow hedges	300	500
Contingent features
Aggregate fair value of instruments in liability position	455
Additional collateral to post	289
Derivatives Fair Value [Line Items]
Derivative asset fair value	8	5			8	5	8	5													7	[1]	5	[1]	1	[1]
Derivative liability fair value	851	802	52	96	799	706	796	703					42	76	7	17											2	2	439	[1]	357	[1]	1	1	354	[1]	332	[1]			14	[2]	3	[2]	1	1	2	2
Derivatives Designated as Hedging Instruments
Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives									2	[3],[4],[5]	2	[3],[4],[5]
Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income									(3)	[3],[4],[5]	(1)	[3],[4],[5]
Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives											(1)	[3],[4],[6]
Derivatives Not Designated As Hedging Instruments
Realized Gain or (Loss)																	(105)	[7]	(52)	[7]
Unrealized Gain or (Loss)																	(206)	[8]	23	[8]
Amount of Gain or (Loss) Recognized in Income on Derivatives																																							$ 8	[9]
Fair Value Of Derivative Instruments Parenthetical Information
CVO's in connection with the acquisition of Florida Progress during 2000	98.6
CVO's repurchased in connection with the negotiated settlement agreement and subsequent tender offer	83.4

[1] Substantially all of these contracts receive regulatory treatment.

[2] As discussed in Note 16 in the 2011 Form 10-K, the Parent issued 98.6 million CVOs in connection with the acquisition of Florida Progress during 2000. Through a negotiated settlement agreement and subsequent tender offer between October 2011 and February 2012, we repurchased and continue to hold 83.4 million CVOs.

[3] Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.

[4] Amounts recorded on the Consolidated Statements of Comprehensive Income are classified in interest charges.

[5] Effective portion.

[6] Related to ineffective portion and amount excluded from effectiveness testing.

[7] After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.

[8] Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.

[9] Amounts recorded in the Consolidated Statements of Comprehensive Income are classified in other, net.

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Debt and Credit Facilities - Debt and Credit Facilities (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Long-term debt [Line Items]
Current portion of long-term debt	$ (1,375)	$ (950)
Long-term debt, net	11,742	11,718
Long-term debt, affiliate	273	273
RCAs and available capacity [Line Items]
RCA expiration date	May 3, 2013
RCA total	1,978
Short Term Debt [Line Items]
Short-term debt	1,056	671
Parent
RCAs and available capacity [Line Items]
RCA amendment date	February 15, 2012
RCA total	478
Parent | Senior Notes Due April 15, 2012
Long-term debt [Line Items]
Maturity date	Apr. 15, 2012
Maturities of debt	450
Debt instrument, interest rate stated percentage	6.85%
Parent | Senior Notes Due April 1, 2022
Long-term debt [Line Items]
Debt instrument, face amount	450
Maturity date	Apr. 01, 2022
Debt instrument issuance date	March 8, 2012
Debt instrument, interest rate stated percentage	3.15%
PEC
Long-term debt [Line Items]
Current portion of long-term debt	(500)	(500)
Long-term debt, net	3,693	3,693
Short Term Debt [Line Items]
Short-term debt	441	188
PEF
Long-term debt [Line Items]
Current portion of long-term debt	(425)	0
Long-term debt, net	4,057	4,482
Short Term Debt [Line Items]
Short-term debt	$ 360	$ 233

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Other Commitments and Contingencies (Details) (Synthetic fuels matters, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2009
Synthetic fuels matters
Loss Contingencies [Line Items]
Judgment award	$ 78
Prejudgment interest	55
Total judgment	133
After-tax loss contingency, loss in period	74
Judgment payment	$ 154

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Divestitures

3 Months Ended

Mar. 31, 2012

Disposal Groups Including Discontinued Operations Disclosure [Abstract]

Divestitures

4.       DIVESTITURES

We have completed our business strategy of divesting nonregulated businesses to reduce our business risk and focus on core operations of the Utilities. Included in discontinued operations, net of tax are amounts related to adjustments of our prior sales of diversified businesses. These adjustments are generally due to guarantees and indemnifications provided for certain legal, tax and environmental matters. See Note 14B for further discussion of our guarantees. The ultimate resolution of these matters could result in additional adjustments in future periods.

During the three months ended March 31, 2012 and 2011, earnings (loss) from discontinued operations, net of tax was $11 million and $(2) million, respectively. Earnings for the three months ended March 31, 2012, relates primarily to an $18 million pre-tax gain from the reversal of certain environmental indemnification liabilities for which the indemnification period has expired.

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Financial Information by Business Segment (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Segment Reporting Information [Line Items]
Unaffiliated	$ 2,092	$ 2,167
Intersegment	0	0
Total revenues	2,092	2,167
Depreciation, amortization and accretion	166	154
Interest income	1	1
Total interest charges, net	185	190
Ongoing Earnings	143	202
Total assets	35,975		35,059
PEC
Segment Reporting Information [Line Items]
Unaffiliated	1,085	1,133
Intersegment	0	0
Total revenues	1,085	1,133
Ongoing Earnings	60	139
Total assets	16,424
PEF
Segment Reporting Information [Line Items]
Unaffiliated	1,005	1,032
Intersegment	0	0
Total revenues	1,005	1,032
Ongoing Earnings	130	111
Total assets	14,732
Corporate and Other
Segment Reporting Information [Line Items]
Unaffiliated	2	2
Intersegment	59	74
Total revenues	61	76
Ongoing Earnings	(47)	(48)
Total assets	21,248
Eliminations
Segment Reporting Information [Line Items]
Unaffiliated	0	0
Intersegment	(59)	(74)
Total revenues	(59)	(74)
Ongoing Earnings	0	0
Total assets	$ (16,429)

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Environmental Matters (Tables)

3 Months Ended

Mar. 31, 2012

Disclosure Environmental Matters Tables [Abstract]

Environmental remediation accruals [Tables]

PROGRESS ENERGY
(in millions)		MGP and Other Sites		Remediation of Distribution and Substation Transformers		Total
Balance, December 31, 2011		$	17	$	6	$	23
Amount accrued for environmental loss contingencies			3		2		5
Expenditures for environmental loss contingencies			(2)		(2)		(4)
Balance, March 31, 2012(a)		$	18	$	6	$	24
Balance, December 31, 2010		$	20	$	15	$	35
Amount accrued for environmental loss contingencies			-		-		-
Expenditures for environmental loss contingencies			(1)		(5)		(6)
Balance, March 31, 2011(a)		$	19	$	10	$	29
(a)	Expected to be paid out over one to 12 years.

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Financial Information by Business Segment (Tables)

3 Months Ended

Mar. 31, 2012

Segment Reporting [Abstract]

Segment [Tables]

(in millions)		PEC		PEF		Corporate and Other		Eliminations		Totals
At and for the three months ended March 31, 2012
Revenues
	Unaffiliated	$	1,085	$	1,005	$	2	$	-	$	2,092
	Intersegment		-		-		59		(59)		-
	Total revenues		1,085		1,005		61		(59)		2,092
Ongoing Earnings			60		130		(47)		-		143
Total assets			16,424		14,732		21,248		(16,429)		35,975
For the three months ended March 31, 2011
Revenues
	Unaffiliated	$	1,133	$	1,032	$	2	$	-	$	2,167
	Intersegment		-		-		74		(74)		-
	Total revenues		1,133		1,032		76		(74)		2,167
Ongoing Earnings			139		111		(48)		-		202

Ongoing to Net Income Attributable to Controlling Interests [Tables]

(in millions)		2012		2011
Ongoing Earnings		$	143	$	202
Tax levelization			(7)		(2)
CVO mark-to-market			8		-
Merger and integration costs, net of tax benefit of $2 and $- (Note 2)			(5)		(14)
Continuing income attributable to noncontrolling interests, net of tax			2		1
Income from continuing operations			141		187
Discontinued operations, net of tax			11		(2)
Net income attributable to noncontrolling interests, net of tax			(2)		(1)
	Net income attributable to controlling interests	$	150	$	184

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Reconciliation of Ongoing Earnings (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Reconciliation Ongoing Earnings To Net Income Attributable To Controlling Interests [Abstract]
Ongoing Earnings	$ 143	$ 202
Tax levelization	(7)	(2)
CVO mark-to-market, net of tax	8	0
Merger and integration costs, net of tax (Note 2)	(5)	(14)
Change in tax treatment of the Medicare Part D subsidy	0	0
Continuing income attributable to noncontrolling interests, net of tax	2	1
Income from continuing operations	141	187
Discontinued operations, net of tax	11	(2)
Net income attributable to noncontrolling interests, net of tax	(2)	(1)
Net income attributable to controlling interests	150	184
Tax information [Details]
Merger and integration costs, tax benefit (expense)	$ 2

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Organization and Summary of Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Excise taxes
Excise taxes	$ 69	$ 73
Consolidation of variable interest entities
Miscellaneous other property and investments	12		12
Cash and cash equivalents	1		1
VIE - exposure to loss from capital lease agreements	7.5
VIE - activity with VIE related to lease payments	$ 1	$ 1

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Merger Agreement (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Business Combinations [Abstract]
Business Acquisition, Date Of Acquisition Agreement	January 8, 2011
Merger, Description	Duke Energy Corporation (Duke Energy) and Progress Energy entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Progress Energy will be acquired by Duke Energy in a stock-for-stock transaction and become a wholly owned subsidiary of Duke Energy. The Merger Agreement originally had a termination date of January 8, 2012, which has been extended to July 8, 2012. The Merger Agreement can be extended past July 8, 2012, only by mutual agreement of Progress Energy and Duke Energy.
Merger share exchange ratio	2.6125
Merger Share Exchange Ratio, Adjusted	0.87083
Settlement Agreement, Description	Under the settlement agreement with the North Carolina Public Staff, Progress Energy and Duke Energy will provide $650 million in system fuel cost savings for customers in North Carolina and South Carolina over the five years following the close of the merger, maintain their current level of community support in North Carolina for the next four years, and provide $15 million for low-income energy assistance and workforce development in North Carolina. The settlement agreement also provides that direct merger-related expenses will not be recovered from customers; however, PEC may request recovery of costs incurred to create operational savings.
Settlement Agreement, Fuel Savings	$ 650
Loss Contingencies [Line Items]
Settlement Agreement, Low Income And Workforce Assistance	15
Exit cost liability recognized	3
Estimated exit cost liability	17
Merger and integration costs, net of tax	5	14
Merger Dividend Restriction	$ 0.62
Merger Termination Fee, Aquirer	675
Merger Termination Fee, Aquiree	400
Merger Cost Indemnification	30
Property, Plant and Equipment, Additions, Proposed, Settlement	110
Exit cost liability	8
Employee Rentention Member
Loss Contingencies [Line Items]
Loss Contingency Unrecorded Estimate Of Possible Loss	14
Special Termination Benefits [Member]
Loss Contingencies [Line Items]
Loss Contingency Unrecorded Estimate Of Possible Loss Range Low	90
Loss Contingency Unrecorded Estimate Of Possible Loss Range High	$ 100
Number of accepted VSP requests	650

XML

New Accounting Standards

3 Months Ended

Mar. 31, 2012

Schedule Of New Accounting Pronouncements And Changes In Accounting Principles Disclosure [Line Items]

Description Of New Accounting Pronouncements [Text Block]

3.       NEW ACCOUNTING STANDARDS

Fair Value Measurement and Disclosures

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which amends Accounting Standards Codification (ASC) 820 to develop a single, converged fair value framework between GAAP and International Financial Reporting Standards (IFRS). ASU 2011-04 was effective prospectively for us on January 1, 2012. The adoption of ASU 2011-04 resulted in additional disclosures in the notes to the financial statements but did not have an impact on our or the Utilities' financial position, results of operations or cash flows.

GOODWILL IMPAIRMENT TESTING

In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment,” which amends the guidance in ASC 350 on testing goodwill for impairment. Under the revised guidance, we have the option of performing a qualitative assessment before calculating the fair value of our reporting units. If it were determined in the qualitative assessment that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we would proceed to the two-step goodwill impairment test. Otherwise, no further impairment testing would be required. ASU 2011-08 was effective for us on January 1, 2012 for both prospective interim and annual goodwill tests and will give us the option to perform the qualitative assessment to determine the need for a two-step goodwill impairment test. The prospective impact of the adoption is not expected to be significant to our or the Utilities' financial position, results of operations or cash flows.

DISCLOSURES ABOUT OFFSETTING ASSETS AND LIABILITIES

In December 2011, the FASB issued ASU 2011-11, “Disclosures About Offsetting Assets and Liabilities,” which requires new disclosures to help financial statement users better understand the impact of offsetting arrangements on our balance sheet. The adoption of ASU 2011-11 will add disclosures showing both gross and net information about instruments and transactions eligible for offset in the balance sheet and instruments and transactions subject to an agreement similar to a master netting arrangement. ASU 2011-11 is effective for us on January 1, 2013, and will be retroactively applied.

PEC

Schedule Of New Accounting Pronouncements And Changes In Accounting Principles Disclosure [Line Items]

Description Of New Accounting Pronouncements [Text Block]

3.       NEW ACCOUNTING STANDARDS

Fair Value Measurement and Disclosures

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which amends Accounting Standards Codification (ASC) 820 to develop a single, converged fair value framework between GAAP and International Financial Reporting Standards (IFRS). ASU 2011-04 was effective prospectively for us on January 1, 2012. The adoption of ASU 2011-04 resulted in additional disclosures in the notes to the financial statements but did not have an impact on our or the Utilities' financial position, results of operations or cash flows.

GOODWILL IMPAIRMENT TESTING

In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment,” which amends the guidance in ASC 350 on testing goodwill for impairment. Under the revised guidance, we have the option of performing a qualitative assessment before calculating the fair value of our reporting units. If it were determined in the qualitative assessment that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we would proceed to the two-step goodwill impairment test. Otherwise, no further impairment testing would be required. ASU 2011-08 was effective for us on January 1, 2012 for both prospective interim and annual goodwill tests and will give us the option to perform the qualitative assessment to determine the need for a two-step goodwill impairment test. The prospective impact of the adoption is not expected to be significant to our or the Utilities' financial position, results of operations or cash flows.

DISCLOSURES ABOUT OFFSETTING ASSETS AND LIABILITIES

In December 2011, the FASB issued ASU 2011-11, “Disclosures About Offsetting Assets and Liabilities,” which requires new disclosures to help financial statement users better understand the impact of offsetting arrangements on our balance sheet. The adoption of ASU 2011-11 will add disclosures showing both gross and net information about instruments and transactions eligible for offset in the balance sheet and instruments and transactions subject to an agreement similar to a master netting arrangement. ASU 2011-11 is effective for us on January 1, 2013, and will be retroactively applied.

PEF

Schedule Of New Accounting Pronouncements And Changes In Accounting Principles Disclosure [Line Items]

Description Of New Accounting Pronouncements [Text Block]

3.       NEW ACCOUNTING STANDARDS

Fair Value Measurement and Disclosures

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which amends Accounting Standards Codification (ASC) 820 to develop a single, converged fair value framework between GAAP and International Financial Reporting Standards (IFRS). ASU 2011-04 was effective prospectively for us on January 1, 2012. The adoption of ASU 2011-04 resulted in additional disclosures in the notes to the financial statements but did not have an impact on our or the Utilities' financial position, results of operations or cash flows.

GOODWILL IMPAIRMENT TESTING

In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment,” which amends the guidance in ASC 350 on testing goodwill for impairment. Under the revised guidance, we have the option of performing a qualitative assessment before calculating the fair value of our reporting units. If it were determined in the qualitative assessment that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we would proceed to the two-step goodwill impairment test. Otherwise, no further impairment testing would be required. ASU 2011-08 was effective for us on January 1, 2012 for both prospective interim and annual goodwill tests and will give us the option to perform the qualitative assessment to determine the need for a two-step goodwill impairment test. The prospective impact of the adoption is not expected to be significant to our or the Utilities' financial position, results of operations or cash flows.

DISCLOSURES ABOUT OFFSETTING ASSETS AND LIABILITIES

In December 2011, the FASB issued ASU 2011-11, “Disclosures About Offsetting Assets and Liabilities,” which requires new disclosures to help financial statement users better understand the impact of offsetting arrangements on our balance sheet. The adoption of ASU 2011-11 will add disclosures showing both gross and net information about instruments and transactions eligible for offset in the balance sheet and instruments and transactions subject to an agreement similar to a master netting arrangement. ASU 2011-11 is effective for us on January 1, 2013, and will be retroactively applied.

XML

Divestitures (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Discontinued operations attributable to controlling interests
Discontinued operations, net of tax	$ 11	$ (2)
Discontinued operations, pre-tax gain from indemnification reversals	$ 18

XML

Benefit Plans - Assets of Benefit Plans (Details) (Pension Benefits, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Pension Benefits
Assets Of Benefit Plans [Line Items]
Employer contributions made directly to pension plan assets	$ 18

XML

Unaudited Condensed Consolidated Statements of Comprehensive Income (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Statement of Comprehensive Income [Line Items]
Operating revenues	$ 2,092	$ 2,167
Operating expenses
Fuel used in electric generation	685	718
Purchased power	210	220
Operation and maintenance	529	494
Depreciation, amortization and accretion	166	154
Taxes other than on income	138	140
Other	0	(10)
Total operating expenses	1,728	1,716
Operating income	364	451
Other income (expense)
Interest income	1	1
Allowance for equity funds used during construction	24	29
Other, net	13	3
Total other income, net	38	33
Interest charges
Interest charges	194	199
Allowance for borrowed funds used during construction	(9)	(9)
Total interest charges, net	185	190
Income from continuing operations before income tax	217	294
Income tax expense	76	107
Income from continuing operations	141	187
Discontinued operations, net of tax	11	(2)
Net income	152	185
Net income attributable to noncontrolling interests, net of tax	(2)	(1)
Net income attributable to controlling interests	150	184
Average common shares outstanding - basic	297	295
Basic and diluted earnings per common share
Income from continuing operations attributable to controlling interests, net of tax	$ 0.47	$ 0.63
Discontinued operations attributable to controlling interests, net of tax	$ 0.04	$ (0.01)
Net income attributable to controlling interests	$ 0.51	$ 0.62
Dividends declared per common share	$ 0.620	$ 0.620
Net income amounts attributable to controlling interests
Income from continuing operations, net of tax	139	186
Discontinued operations, net of tax	11	(2)
Net income attributable to controlling interests	150	184
Comprehensive income
Comprehensive income	157	189
Comprehensive (income) loss attributable to noncontrolling interests, net of tax	(2)	(1)
Comprehensive income attributable to controlling interests	155	188
PEC
Statement of Comprehensive Income [Line Items]
Operating revenues	1,085	1,133
Operating expenses
Fuel used in electric generation	349	363
Purchased power	65	67
Operation and maintenance	374	295
Depreciation, amortization and accretion	134	124
Taxes other than on income	56	56
Other	(1)	0
Total operating expenses	977	905
Operating income	108	228
Other income (expense)
Allowance for equity funds used during construction	15	20
Other, net	4	(2)
Total other income, net	19	18
Interest charges
Interest charges	56	50
Allowance for borrowed funds used during construction	(5)	(5)
Total interest charges, net	51	45
Income from continuing operations before income tax	76	201
Income tax expense	24	70
Net income	52	131
Preferred stock dividend requirement	(1)	(1)
Net income available to parent	51	130
Comprehensive income
Comprehensive income attributable to controlling interests	57	133
PEF
Statement of Comprehensive Income [Line Items]
Operating revenues	1,005	1,032
Operating expenses
Fuel used in electric generation	336	355
Purchased power	145	153
Operation and maintenance	160	210
Depreciation, amortization and accretion	27	25
Taxes other than on income	82	85
Other	0	(12)
Total operating expenses	750	816
Operating income	255	216
Other income (expense)
Allowance for equity funds used during construction	9	9
Other, net	0	3
Total other income, net	9	12
Interest charges
Interest charges	67	69
Allowance for borrowed funds used during construction	(4)	(4)
Total interest charges, net	63	65
Income from continuing operations before income tax	201	163
Income tax expense	73	61
Net income	128	102
Preferred stock dividend requirement	(1)	(1)
Net income available to parent	127	101
Comprehensive income
Comprehensive income attributable to controlling interests	$ 129	$ 102

XML

Environmental Matters (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended										3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011		Mar. 31, 2012 MGP And Other Sites		Mar. 31, 2011 MGP And Other Sites		Mar. 31, 2012 MGP And Other Sites PEC	Dec. 31, 2011 MGP And Other Sites PEC	Mar. 31, 2012 Remediation Of Distribution And Substation Transformers		Mar. 31, 2011 Remediation Of Distribution And Substation Transformers		Mar. 31, 2012 Orlando MGP OU1 PEF
Disclosure Environmental Matters Details [Line Items]
Beginning Balance	$ 23		$ 35		$ 17		$ 20				$ 6		$ 15
Amount accrued for environmental loss contingencies	5		0		3		0				2		0
Expenditures for environmental loss contingencies	(4)		(6)		(2)		(1)				(2)		(5)
Ending Balance	24	[1]	29	[1]	18	[1]	19	[1]			6	[1]	10	[1]
Period expected to be paid out over	one to 12 years		one to 12 years
(Ward) site recorded liability									5	5
Site contingency, loss exposure not accrued									6
Site contingency, loss exposure not accrued, reimbursement									1
Site contingency, loss exposure in excess of accrual, high estimate															$ 4

[1] Expected to be paid out over one to 12 years.

XML

Organization and Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2012

Organization Consolidation And Presentation Of Financial Statements Disclosure [Line Items]

Organization and Summary of Significant Accounting Policies

1.       ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.       ORGANIZATION

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,” “us” or “our.” When discussing Progress Energy's financial information, it necessarily includes the results of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (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 these 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.

PROGRESSENERGY

The Parent is a holding company headquartered in Raleigh, N.C., subject to regulation by the Federal Energy Regulatory Commission (FERC).

Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 12 for further information about our segments.

PEC

PEC is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. PEC's subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory jurisdiction of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (SCPSC), the United States Nuclear Regulatory Commission (NRC) and the FERC.

PEF

PEF is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in west central Florida. PEF is subject to the regulatory jurisdiction of the Florida Public Service Commission (FPSC), the NRC and the FERC.

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. The December 31, 2011 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. 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 Progress Registrants' annual report on Form 10-K for the fiscal year ended December 31, 2011 (2011 Form 10-K).

The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary to fairly present the Progress Registrants' financial position and results of operations for the interim periods. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to seasonal weather variations, the impact of regulatory orders received, 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 to GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.

Certain amounts for 2011 have been reclassified to conform to the 2012 presentation.

The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for sales and use tax on a net basis and gross receipts tax, franchise taxes and other excise taxes on a gross basis.

The amount of gross receipts tax, franchise taxes and other excise taxes included in operating revenues and taxes other than on income in the statements of comprehensive income were as follows:

	Three months ended March 31
(in millions)	2012		2011
Progress Energy	$	69	$	73
PEC		26		28
PEF		43		45

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 (VIEs) for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder hasthe controlling financial interest in the VIE. The variable interest holder who has both of the following has the controlling financial interest and is the primary beneficiary: (1) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (2) the obligation to absorb losses of, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. In performing our analysis, we consider all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the nature of the VIE's variable interests issued and how they were negotiated with or marketed to potential investors, and which parties participated significantly in the design or redesign of the entity.

PROGRESS ENERGY

Progress Energy, through its subsidiary PEC, is the primary beneficiary of, and consolidates an entity that qualifies for rehabilitation tax credits under Section 47 of the Internal Revenue Code. Our variable interests are debt and equity investments in the VIE. There were no changes to our assessment of the primary beneficiary for this VIE during 2011 or for the period ended March 31, 2012. No financial or other support has been provided to the VIE during the periods presented.

The following table sets forth the carrying amount and classification of our investment in the VIE as reflected in the Consolidated Balance Sheets:

(in millions)	March 31, 2012		December 31, 2011
Miscellaneous other property and investments	$	12	$	12
Cash and cash equivalents		1		1

The assets of the VIE are collateral for, and can only be used to settle, its obligations. The creditors of the VIE do not have recourse to our general credit or the general credit of PEC, and there are no other arrangements that could expose us to losses.

Progress Energy, through its subsidiary PEC, is the primary beneficiary of two VIEs that were established to lease buildings to PEC under capital lease agreements. Our maximum exposure to loss from these leases is a $7.5 million mandatory fixed price purchase option for one of the buildings. Total lease payments to these counterparties under the lease agreements were $1 million for each of the three months ended March 31, 2012 and 2011. We have requested the necessary information to consolidate these entities; both entities from which the necessary financial information was requested declined to provide the information to us, and, accordingly, we have applied the information scope exception provided by GAAP to the entities. We believe the effect of consolidating the entities would have an insignificant impact on our common stock equity, net earnings or cash flows. However, because we have not received any financial information from the counterparties, the impact cannot be determined at this time.

PEC

See discussion of PEC's variable interests within the Progress Energy section.

PEF

PEF has no significant variable interests in VIEs.

PEC

Organization Consolidation And Presentation Of Financial Statements Disclosure [Line Items]

Organization and Summary of Significant Accounting Policies

1.       ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.       ORGANIZATION

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,” “us” or “our.” When discussing Progress Energy's financial information, it necessarily includes the results of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (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 these 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.

PROGRESSENERGY

The Parent is a holding company headquartered in Raleigh, N.C., subject to regulation by the Federal Energy Regulatory Commission (FERC).

Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 12 for further information about our segments.

PEC

PEC is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. PEC's subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory jurisdiction of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (SCPSC), the United States Nuclear Regulatory Commission (NRC) and the FERC.

PEF

PEF is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in west central Florida. PEF is subject to the regulatory jurisdiction of the Florida Public Service Commission (FPSC), the NRC and the FERC.

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. The December 31, 2011 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. 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 Progress Registrants' annual report on Form 10-K for the fiscal year ended December 31, 2011 (2011 Form 10-K).

The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary to fairly present the Progress Registrants' financial position and results of operations for the interim periods. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to seasonal weather variations, the impact of regulatory orders received, 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 to GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.

Certain amounts for 2011 have been reclassified to conform to the 2012 presentation.

The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for sales and use tax on a net basis and gross receipts tax, franchise taxes and other excise taxes on a gross basis.

The amount of gross receipts tax, franchise taxes and other excise taxes included in operating revenues and taxes other than on income in the statements of comprehensive income were as follows:

	Three months ended March 31
(in millions)	2012		2011
Progress Energy	$	69	$	73
PEC		26		28
PEF		43		45

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 (VIEs) for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder hasthe controlling financial interest in the VIE. The variable interest holder who has both of the following has the controlling financial interest and is the primary beneficiary: (1) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (2) the obligation to absorb losses of, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. In performing our analysis, we consider all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the nature of the VIE's variable interests issued and how they were negotiated with or marketed to potential investors, and which parties participated significantly in the design or redesign of the entity.

PROGRESS ENERGY

Progress Energy, through its subsidiary PEC, is the primary beneficiary of, and consolidates an entity that qualifies for rehabilitation tax credits under Section 47 of the Internal Revenue Code. Our variable interests are debt and equity investments in the VIE. There were no changes to our assessment of the primary beneficiary for this VIE during 2011 or for the period ended March 31, 2012. No financial or other support has been provided to the VIE during the periods presented.

The following table sets forth the carrying amount and classification of our investment in the VIE as reflected in the Consolidated Balance Sheets:

(in millions)	March 31, 2012		December 31, 2011
Miscellaneous other property and investments	$	12	$	12
Cash and cash equivalents		1		1

The assets of the VIE are collateral for, and can only be used to settle, its obligations. The creditors of the VIE do not have recourse to our general credit or the general credit of PEC, and there are no other arrangements that could expose us to losses.

Progress Energy, through its subsidiary PEC, is the primary beneficiary of two VIEs that were established to lease buildings to PEC under capital lease agreements. Our maximum exposure to loss from these leases is a $7.5 million mandatory fixed price purchase option for one of the buildings. Total lease payments to these counterparties under the lease agreements were $1 million for each of the three months ended March 31, 2012 and 2011. We have requested the necessary information to consolidate these entities; both entities from which the necessary financial information was requested declined to provide the information to us, and, accordingly, we have applied the information scope exception provided by GAAP to the entities. We believe the effect of consolidating the entities would have an insignificant impact on our common stock equity, net earnings or cash flows. However, because we have not received any financial information from the counterparties, the impact cannot be determined at this time.

PEC

See discussion of PEC's variable interests within the Progress Energy section.

PEF

PEF has no significant variable interests in VIEs.

PEF

Organization Consolidation And Presentation Of Financial Statements Disclosure [Line Items]

Organization and Summary of Significant Accounting Policies

1.       ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.       ORGANIZATION

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,” “us” or “our.” When discussing Progress Energy's financial information, it necessarily includes the results of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (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 these 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.

PROGRESSENERGY

The Parent is a holding company headquartered in Raleigh, N.C., subject to regulation by the Federal Energy Regulatory Commission (FERC).

Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity. The Corporate and Other segment primarily includes amounts applicable to the activities of the Parent and Progress Energy Service Company, LLC (PESC) and other miscellaneous nonregulated businesses (Corporate and Other) that do not separately meet the quantitative disclosure requirements as a reportable business segment. See Note 12 for further information about our segments.

PEC

PEC is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. PEC's subsidiaries are involved in insignificant nonregulated business activities. PEC is subject to the regulatory jurisdiction of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (SCPSC), the United States Nuclear Regulatory Commission (NRC) and the FERC.

PEF

PEF is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in west central Florida. PEF is subject to the regulatory jurisdiction of the Florida Public Service Commission (FPSC), the NRC and the FERC.

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. The December 31, 2011 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. 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 Progress Registrants' annual report on Form 10-K for the fiscal year ended December 31, 2011 (2011 Form 10-K).

The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary to fairly present the Progress Registrants' financial position and results of operations for the interim periods. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to seasonal weather variations, the impact of regulatory orders received, 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 to GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.

Certain amounts for 2011 have been reclassified to conform to the 2012 presentation.

The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for sales and use tax on a net basis and gross receipts tax, franchise taxes and other excise taxes on a gross basis.

The amount of gross receipts tax, franchise taxes and other excise taxes included in operating revenues and taxes other than on income in the statements of comprehensive income were as follows:

	Three months ended March 31
(in millions)	2012		2011
Progress Energy	$	69	$	73
PEC		26		28
PEF		43		45

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 (VIEs) for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder hasthe controlling financial interest in the VIE. The variable interest holder who has both of the following has the controlling financial interest and is the primary beneficiary: (1) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (2) the obligation to absorb losses of, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. In performing our analysis, we consider all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the nature of the VIE's variable interests issued and how they were negotiated with or marketed to potential investors, and which parties participated significantly in the design or redesign of the entity.

PROGRESS ENERGY

Progress Energy, through its subsidiary PEC, is the primary beneficiary of, and consolidates an entity that qualifies for rehabilitation tax credits under Section 47 of the Internal Revenue Code. Our variable interests are debt and equity investments in the VIE. There were no changes to our assessment of the primary beneficiary for this VIE during 2011 or for the period ended March 31, 2012. No financial or other support has been provided to the VIE during the periods presented.

The following table sets forth the carrying amount and classification of our investment in the VIE as reflected in the Consolidated Balance Sheets:

(in millions)	March 31, 2012		December 31, 2011
Miscellaneous other property and investments	$	12	$	12
Cash and cash equivalents		1		1

The assets of the VIE are collateral for, and can only be used to settle, its obligations. The creditors of the VIE do not have recourse to our general credit or the general credit of PEC, and there are no other arrangements that could expose us to losses.

Progress Energy, through its subsidiary PEC, is the primary beneficiary of two VIEs that were established to lease buildings to PEC under capital lease agreements. Our maximum exposure to loss from these leases is a $7.5 million mandatory fixed price purchase option for one of the buildings. Total lease payments to these counterparties under the lease agreements were $1 million for each of the three months ended March 31, 2012 and 2011. We have requested the necessary information to consolidate these entities; both entities from which the necessary financial information was requested declined to provide the information to us, and, accordingly, we have applied the information scope exception provided by GAAP to the entities. We believe the effect of consolidating the entities would have an insignificant impact on our common stock equity, net earnings or cash flows. However, because we have not received any financial information from the counterparties, the impact cannot be determined at this time.

PEC

See discussion of PEC's variable interests within the Progress Energy section.

PEF

PEF has no significant variable interests in VIEs.

XML

Equity - Common Stock (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Common Stock [Details]
Common shares, authorized	500		500
Common shares, outstanding	296		295
Total issuances - shares	0.8	1.0
Issuance through 401(k) and or IPP - shares	0	0
Total issuances - net proceeds	$ 3	$ 8
Issuances through 401(k) and or IPP - net proceeds	$ 0	$ 1

XML

Organization and Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2012

Disclosure Organization And Summary Of Significant Accounting Policies Tables [Abstract]

Schedule of excise taxes [Tables]

	Three months ended March 31
(in millions)	2012		2011
Progress Energy	$	69	$	73
PEC		26		28
PEF		43		45

Schedule of consolidated variable interest entity [Tables]

(in millions)	March 31, 2012		December 31, 2011
Miscellaneous other property and investments	$	12	$	12
Cash and cash equivalents		1		1

XML

Preferred Stock of Subsidiaries (Details) (USD $)	Mar. 31, 2012
Disclosure Preferred Stock Of Subsidiaries Details [Abstract]
Preferred stock liquidation preference per share	$ 100

XML

Equity (Tables)

3 Months Ended

Mar. 31, 2012

Equity [Abstract]

Common stock

	Three months ended March 31
	2012			2011
(in millions)	Shares		Net Proceeds	Shares		Net Proceeds
Total issuances	0.8	$	3	1.0	$	8
Issuances through IPP	-		-	-		1

Reconciliation of total equity

(in millions)		Total Common Stock Equity		Noncontrolling Interests		Total Equity
Balance, December 31, 2011		$	10,021	$	4	$	10,025
Net income(a)			150		0		150
Other comprehensive income			5		0		5
Issuance of shares through offerings and stock- based compensation plans (See Note 6C)			17		0		17
Dividends declared			(184)		0		(184)
Distributions to noncontrolling interests			0		(2)		(2)
Balance, March 31, 2012		$	10,009	$	2	$	10,011
Balance, December 31, 2010		$	10,023	$	4	$	10,027
Net income(a)			184		(1)		183
Other comprehensive income			4		0		4
Issuance of shares through offerings and stock- based compensation plans (See Note 6C)			19		0		19
Dividends declared			(183)		0		(183)
Distributions to noncontrolling interests			0		(2)		(2)
Other			0		2		2
Balance, March 31, 2011		$	10,047	$	3	$	10,050
(a)	For the three months ended March 31, 2012, consolidated net income of $152 million includes $2 million attributable to preferred shareholders of subsidiaries. For the three months ended March 31, 2011, consolidated net income of $185 million includes $2 million attributable to preferred shareholders of subsidiaries. Income attributable to preferred shareholders of subsidiaries is not a component of total equity and is excluded from the table above.

XML

Merger Agreement

3 Months Ended

Mar. 31, 2012

Merger Agreement [Line Items]

Proposed Business Combination Disclosure [Text Block]

2.MERGER AGREEMENT

On January 8, 2011, Duke Energy Corporation (Duke Energy) and Progress Energy entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Progress Energy will be acquired by Duke Energy in a stock-for-stock transaction and become a wholly owned subsidiary of Duke Energy. The Merger Agreement originally had a termination date of January 8, 2012, which has been extended to July 8, 2012. The Merger Agreement can be extended past July 8, 2012, only by mutual agreement of Progress Energy and Duke Energy.

Under the terms of the Merger Agreement, each share of Progress Energy common stock will be cancelled and converted into the right to receive 2.6125 shares of Duke Energy common stock. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock will be converted into an option to acquire, or an equity award relating to, 2.6125 shares of Duke Energy common stock. The board of directors of Duke Energy approved a reverse stock split, at a ratio of 1-for-3, subject to completion of the merger. Accordingly, the adjusted exchange ratiois expected to be 0.87083 of a share of Duke Energy common stock, options and equity awards for each Progress Energy common share, option and equity award.

The combined company, to be called Duke Energy, will have an 18-member board of directors. The board will be comprised of, subject to their ability and willingness to serve, all 11 current directors of Duke Energy and seven current directors of Progress Energy. At the time of the merger, William D. Johnson, Chairman, President and CEO of Progress Energy, will be President and CEO of Duke Energy, and James E. Rogers, Chairman, President and CEO of Duke Energy, will be the Executive Chairman of the board of directors of Duke Energy, subject to their ability and willingness to serve.

Consummation of the merger is subject to customary conditions, including, among others things, approval by the shareholders of each company, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and receipt of approvals, to the extent required, from the FERC, the Federal Communications Commission, the NRC, the NCUC, the Kentucky Public Service Commission and the SCPSC. Although there are no merger-specific regulatory approvals required in Indiana, Ohio or Florida, the companies will continue to update the public service commissions in those states on the merger, as applicable and as required. The status of these matters is as follows, and we cannot predict the outcome of pending approvals:

Shareholder Approval

• On August 23, 2011, the merger was approved by the shareholders of Progress Energy and Duke Energy.

  Federal Regulatory Approvals

• Progress Energy and Duke Energy met their obligations under the Hart-Scott-Rodino Act with their March 28, 2011 filing with the U.S. Department of Justice (DOJ) for review under U.S. antitrust laws. Because the merger was not anticipated to close before the April 26,2012 expiration of the original filing, Progress Energy and Duke Energy filed a new Hart-Scott-Rodino filing on March 22, 2012, in order to be able to close the merger and continue to meet their obligations under the Hart-Scott-Rodino Act. The 30-day waiting period required by the Hart-Scott-Rodino Act expired without Progress Energy or Duke Energy having received requests for additional information. Progress Energy and Duke Energy have met their obligations under the Hart-Scott-Rodino Act.
• On January 5, 2012, the Federal Communications Commission extended its approval of the Assignment of Authorization filings to transfer control of certain licenses. The extended approval expires on July 12, 2012.
• On September 30, 2011, the FERC, which assesses market power-related issues, conditionally approved the merger application filed by Progress Energy and Duke Energy. The approval is subject to the FERC's acceptance of market power mitigation measures to address the FERC's finding that the combined company could have an adverse effect on competition in the North Carolina and South Carolina wholesale power markets. Progress Energy and Duke Energy filed a market power mitigation plan with the FERC on October 17, 2011,that proposed a “virtual divestiture” under which power up to a certain amount would have been offered into the wholesale market rather than the sale or divestiture of physical assets. A virtual divestiture is one option the FERC indicated could be used to mitigate its market power concerns. On December 14, 2011, the FERC affirmed its conditional approval of the merger, but the FERC rejected the proposed market power mitigation plan. On March 26, 2012, Progress Energy and Duke Energy filed a second market power mitigation plan with the FERC. The revised mitigation plan consists of both interim and permanent components. The two- to three-year interim component consists of several power purchase agreements whereby the companies propose to sell capacity and firm energy during the summer (June – August) and winter (December – February) to new market participants. Together, the companies would sell 800 megawatts (MWs) during summer off-peak hours, 475 MWs during summer peak hours, 225 MWs during winter off-peak hours, and 25 MWs during winter peak hours. The agreements have been executed, contingent on the closing of the merger, and will be in effect upon the closing of the merger and remain in effect until the permanent component is operational. The permanent component consists of seven transmission projects to be constructed, estimated to cost approximately $110 million. The transmission projects significantly increase power import capabilities into the PEC and Duke Energy Carolinas service territories and enhance competitive power supply options for the region.Progress Energy and Duke Energy have requested that the FERC issue orders approving the revised mitigation plan within 60 days of the filing date, but no later than June 8, 2012. There is no statutory requirement that the FERC act within a specified timeframe. On April 10, 2012, Progress Energy and Duke Energy received a request from the FERC for additional information on the transmission-related models provided by Progress Energy and Duke Energy in the revised mitigation plan. On April 13, 2012, Progress Energy and Duke Energy responded to the FERC's request. In the response, the companies reaffirmed their request that the FERC approve the revised mitigation plan within 60 days of the original filing date, but no later than June 8, 2012. Fourparticipants to the proceedings filed comments before the April 25, 2012 filing deadline.On May 1, 2012, the companies filed a response to the comments with the FERC. The companies are working with the North Carolina Public Staff and the South Carolina Office of Regulatory Staff (ORS) on appropriate state ratemaking treatment associated with the measures in the revised market mitigation plan and other merger-related issues. The companies' decision to close the merger will be subject to the companies obtaining acceptable resolution of various state ratemaking issues.
• On April 4, 2011, Progress Energy and Duke Energy made two additional filings with the FERC. The first filing is a joint dispatch agreement, pursuant to which PEC and Duke Energy Carolinas will agree to jointly dispatch their generation facilities in order to achieve certain of the operating efficiencies expected to result from the merger. The second filing is a joint open access transmission tariff (OATT) pursuant to which PEC and Duke Energy Carolinas will agree to provide transmission service over their transmission facilities under a single transmission rate. On December 14, 2011, in conjunction with the aforementioned decision on the proposed market power mitigation plan, the FERC dismissed the applications for approval of the joint dispatch agreement and the joint OATT without prejudice. As allowed under the FERC's December 14, 2011 order, Progress Energy and Duke Energy refiled the joint dispatch agreement and OATT with the FERCon March 26, 2012.
• On December 2, 2011, the NRC approved the filing requesting an indirect transfer of control of licenses for Progress Energy's nuclear facilities to include Duke Energy as the ultimate parent corporation on these licenses.

  State Regulatory Approvals

• On April 4, 2011, Progress Energy and Duke Energy filed a merger approval application and an application for approval of a joint dispatch agreement between PEC and Duke Energy Carolinas with the NCUC. On September 2, 2011, the North Carolina Public Staff filed a settlement agreement with the NCUC. On September 6, 2011, Progress Energy and Duke Energy signed a settlement with the ORS, a party to the North Carolina proceedings to resolve the ORS's issues in the North Carolina proceeding. Under the settlement agreement with the North Carolina Public Staff, Progress Energy and Duke Energy will provide $650 million in system fuel cost savings for customers in North Carolina and South Carolina over the five years following the close of the merger, maintain their current level of community support in North Carolina for the next four years, and provide $15 million for low-income energy assistance and workforce development in North Carolina. The settlement agreement also provides that direct merger-related expenses will not be recovered from customers; however, PEC may request recovery of costs incurred to create operational savings.The NCUC held hearings regarding the application on September 20-22, 2011. On November 23, 2011, Progress Energy and Duke Energy filed proposed orders and briefs with the NCUC. The docket will remain open pending the FERC's issuance of its final orders on the merger-related actions before the FERC.
• On April 25, 2011, Progress Energy and Duke Energy filed an application for approval of the merger of PEC and Duke Energy Carolinas and an application for approval of a joint dispatch agreement between PEC and Duke Energy Carolinas with the SCPSC. On September 13, 2011, Progress Energy and Duke Energy withdrew the application of the merger of PEC and Duke Energy Carolinas, as the merger of these entities is not likely to occur for several years after the close of the merger. The SCPSC held hearings regarding the application for approval of the joint dispatch agreement on December 12, 2011. During the hearing, PEC, Duke Energy Carolinas and the ORS agreed to terminate the settlement agreement, which resolved the ORS's issues in the NCUC merger proceeding, and replaced it with a commitment by PEC and Duke Energy Carolinas to provide PEC's and Duke Energy Carolinas' retail customers in South Carolina pro rata benefits equivalent to those approved by the NCUC in its order ruling upon PEC's and Duke Energy Carolinas' merger application. The docket will remain open pending the FERC's issuance of its final orders on the merger-related actions before the FERC.
• On October 28, 2011, the Kentucky Public Service Commission approved Progress Energy's and Duke Energy's merger-related settlement agreement with the Attorney General of the Commonwealth of Kentucky.

The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to consummation of the merger. Among other restrictions, the Merger Agreement limits our total capital spending, limits the extent to which we can obtain financing through long-term debt and equity, and we may not, without the prior approval of Duke Energy, increase our quarterly common stock dividend of $0.62 per share. In the fourth quarter of 2011, our board of directors aligned Progress Energy's dividend payment schedule with that of Duke Energy such that following the closing of the merger, all stockholders of the combined company would receive dividends under the Duke Energy dividend schedule.

Certain substantial changes in ownership of Progress Energy, including the merger, can impact the timing of the utilization of tax credit carry forwards and net operating loss carry forwards (See Note 15 in the 2011 Form 10-K).

The Merger Agreement contains certain termination rights for both companies; under specified circumstances we may be required to pay Duke Energy $400 million and Duke Energy may be required to pay us $675 million. In addition, under specified circumstances each party may be required to reimburse the other party for up to $30 million of merger-related expenses.

In connection with the merger, we established an employee retention plan for certain eligible employees. Payments under the plan are contingent upon the consummation of the merger and the employees' continued employment through a specified time period following the merger. These payments will be recorded as compensation expense following consummation of the merger. We estimate the costs of the retention plan to be $14 million.

In connection with the merger, we offered a voluntary severance plan (VSP) to certain eligible employees. Payments under the plan are contingent upon the consummation of the merger. Approximately 650 employees requested and were approved for separation under the VSP in 2011. The cost of the VSP is estimated to be between $90 million to $100 million, including $65 million to $70 million for PEC and $25 million to $30 million for PEF. If the employee is not required to work for a significant period after the consummation of the merger, the costs of any benefits paid under the VSP will be measured and recorded upon consummation of the merger. If a significant retention period exists, the costs of benefits equal to what would be paid under our existing severance plan will be measured and recorded upon consummation of the merger. Any additional benefits paid under the VSP will be recorded ratably over the remaining service periods of the affected employees.

In addition, we evaluated our business needs for office space after the merger and formulated an exit plan to vacateone of our corporate headquarters buildings. We have begun to gradually vacate the premises and will be fully vacated by January 1, 2013. In December 2011, we executed an agreement with a third party to sublease the building until 2035. The estimated exit cost liability associated with this exit plan is $17 million for us, of which $12 million of expense is attributable to PEC and $5 million to PEF. The exit cost liability will be recognized proportionately as we vacate the premises, which began in the fourth quarter of 2011. During the first quarter of 2012, we recorded exit cost liabilities of $3 million for us, of which $2 million of expense is attributable to PEC and $1 million to PEF. At March 31, 2012, the total exit cost liability recorded by us is $8 million, of which $6 million of expense is attributable to PEC and $2 million of expense is attributable to PEF. These costs are included in merger and integration-related costs.

We incurred merger and integration-related costs of $5 million, net of tax, including $3 million, net of tax, and $2 million, net of tax, at PEC and PEF, respectively, during the quarter ended March 31, 2012. We incurred merger and integration-related costs of $14 million, net of tax, including $7 million, net of tax, and $7 million, net of tax, at PEC and PEF, respectively, during the quarter ended March 31, 2011.These costs are included in operations and maintenance (O&M) expense in our Consolidated Statements of Comprehensive Income.

PEC

Merger Agreement [Line Items]

Proposed Business Combination Disclosure [Text Block]

2.MERGER AGREEMENT

On January 8, 2011, Duke Energy Corporation (Duke Energy) and Progress Energy entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Progress Energy will be acquired by Duke Energy in a stock-for-stock transaction and become a wholly owned subsidiary of Duke Energy. The Merger Agreement originally had a termination date of January 8, 2012, which has been extended to July 8, 2012. The Merger Agreement can be extended past July 8, 2012, only by mutual agreement of Progress Energy and Duke Energy.

Under the terms of the Merger Agreement, each share of Progress Energy common stock will be cancelled and converted into the right to receive 2.6125 shares of Duke Energy common stock. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock will be converted into an option to acquire, or an equity award relating to, 2.6125 shares of Duke Energy common stock. The board of directors of Duke Energy approved a reverse stock split, at a ratio of 1-for-3, subject to completion of the merger. Accordingly, the adjusted exchange ratiois expected to be 0.87083 of a share of Duke Energy common stock, options and equity awards for each Progress Energy common share, option and equity award.

The combined company, to be called Duke Energy, will have an 18-member board of directors. The board will be comprised of, subject to their ability and willingness to serve, all 11 current directors of Duke Energy and seven current directors of Progress Energy. At the time of the merger, William D. Johnson, Chairman, President and CEO of Progress Energy, will be President and CEO of Duke Energy, and James E. Rogers, Chairman, President and CEO of Duke Energy, will be the Executive Chairman of the board of directors of Duke Energy, subject to their ability and willingness to serve.

Consummation of the merger is subject to customary conditions, including, among others things, approval by the shareholders of each company, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and receipt of approvals, to the extent required, from the FERC, the Federal Communications Commission, the NRC, the NCUC, the Kentucky Public Service Commission and the SCPSC. Although there are no merger-specific regulatory approvals required in Indiana, Ohio or Florida, the companies will continue to update the public service commissions in those states on the merger, as applicable and as required. The status of these matters is as follows, and we cannot predict the outcome of pending approvals:

Shareholder Approval

• On August 23, 2011, the merger was approved by the shareholders of Progress Energy and Duke Energy.

  Federal Regulatory Approvals

• Progress Energy and Duke Energy met their obligations under the Hart-Scott-Rodino Act with their March 28, 2011 filing with the U.S. Department of Justice (DOJ) for review under U.S. antitrust laws. Because the merger was not anticipated to close before the April 26,2012 expiration of the original filing, Progress Energy and Duke Energy filed a new Hart-Scott-Rodino filing on March 22, 2012, in order to be able to close the merger and continue to meet their obligations under the Hart-Scott-Rodino Act. The 30-day waiting period required by the Hart-Scott-Rodino Act expired without Progress Energy or Duke Energy having received requests for additional information. Progress Energy and Duke Energy have met their obligations under the Hart-Scott-Rodino Act.
• On January 5, 2012, the Federal Communications Commission extended its approval of the Assignment of Authorization filings to transfer control of certain licenses. The extended approval expires on July 12, 2012.
• On September 30, 2011, the FERC, which assesses market power-related issues, conditionally approved the merger application filed by Progress Energy and Duke Energy. The approval is subject to the FERC's acceptance of market power mitigation measures to address the FERC's finding that the combined company could have an adverse effect on competition in the North Carolina and South Carolina wholesale power markets. Progress Energy and Duke Energy filed a market power mitigation plan with the FERC on October 17, 2011,that proposed a “virtual divestiture” under which power up to a certain amount would have been offered into the wholesale market rather than the sale or divestiture of physical assets. A virtual divestiture is one option the FERC indicated could be used to mitigate its market power concerns. On December 14, 2011, the FERC affirmed its conditional approval of the merger, but the FERC rejected the proposed market power mitigation plan. On March 26, 2012, Progress Energy and Duke Energy filed a second market power mitigation plan with the FERC. The revised mitigation plan consists of both interim and permanent components. The two- to three-year interim component consists of several power purchase agreements whereby the companies propose to sell capacity and firm energy during the summer (June – August) and winter (December – February) to new market participants. Together, the companies would sell 800 megawatts (MWs) during summer off-peak hours, 475 MWs during summer peak hours, 225 MWs during winter off-peak hours, and 25 MWs during winter peak hours. The agreements have been executed, contingent on the closing of the merger, and will be in effect upon the closing of the merger and remain in effect until the permanent component is operational. The permanent component consists of seven transmission projects to be constructed, estimated to cost approximately $110 million. The transmission projects significantly increase power import capabilities into the PEC and Duke Energy Carolinas service territories and enhance competitive power supply options for the region.Progress Energy and Duke Energy have requested that the FERC issue orders approving the revised mitigation plan within 60 days of the filing date, but no later than June 8, 2012. There is no statutory requirement that the FERC act within a specified timeframe. On April 10, 2012, Progress Energy and Duke Energy received a request from the FERC for additional information on the transmission-related models provided by Progress Energy and Duke Energy in the revised mitigation plan. On April 13, 2012, Progress Energy and Duke Energy responded to the FERC's request. In the response, the companies reaffirmed their request that the FERC approve the revised mitigation plan within 60 days of the original filing date, but no later than June 8, 2012. Fourparticipants to the proceedings filed comments before the April 25, 2012 filing deadline.On May 1, 2012, the companies filed a response to the comments with the FERC. The companies are working with the North Carolina Public Staff and the South Carolina Office of Regulatory Staff (ORS) on appropriate state ratemaking treatment associated with the measures in the revised market mitigation plan and other merger-related issues. The companies' decision to close the merger will be subject to the companies obtaining acceptable resolution of various state ratemaking issues.
• On April 4, 2011, Progress Energy and Duke Energy made two additional filings with the FERC. The first filing is a joint dispatch agreement, pursuant to which PEC and Duke Energy Carolinas will agree to jointly dispatch their generation facilities in order to achieve certain of the operating efficiencies expected to result from the merger. The second filing is a joint open access transmission tariff (OATT) pursuant to which PEC and Duke Energy Carolinas will agree to provide transmission service over their transmission facilities under a single transmission rate. On December 14, 2011, in conjunction with the aforementioned decision on the proposed market power mitigation plan, the FERC dismissed the applications for approval of the joint dispatch agreement and the joint OATT without prejudice. As allowed under the FERC's December 14, 2011 order, Progress Energy and Duke Energy refiled the joint dispatch agreement and OATT with the FERCon March 26, 2012.
• On December 2, 2011, the NRC approved the filing requesting an indirect transfer of control of licenses for Progress Energy's nuclear facilities to include Duke Energy as the ultimate parent corporation on these licenses.

  State Regulatory Approvals

• On April 4, 2011, Progress Energy and Duke Energy filed a merger approval application and an application for approval of a joint dispatch agreement between PEC and Duke Energy Carolinas with the NCUC. On September 2, 2011, the North Carolina Public Staff filed a settlement agreement with the NCUC. On September 6, 2011, Progress Energy and Duke Energy signed a settlement with the ORS, a party to the North Carolina proceedings to resolve the ORS's issues in the North Carolina proceeding. Under the settlement agreement with the North Carolina Public Staff, Progress Energy and Duke Energy will provide $650 million in system fuel cost savings for customers in North Carolina and South Carolina over the five years following the close of the merger, maintain their current level of community support in North Carolina for the next four years, and provide $15 million for low-income energy assistance and workforce development in North Carolina. The settlement agreement also provides that direct merger-related expenses will not be recovered from customers; however, PEC may request recovery of costs incurred to create operational savings.The NCUC held hearings regarding the application on September 20-22, 2011. On November 23, 2011, Progress Energy and Duke Energy filed proposed orders and briefs with the NCUC. The docket will remain open pending the FERC's issuance of its final orders on the merger-related actions before the FERC.
• On April 25, 2011, Progress Energy and Duke Energy filed an application for approval of the merger of PEC and Duke Energy Carolinas and an application for approval of a joint dispatch agreement between PEC and Duke Energy Carolinas with the SCPSC. On September 13, 2011, Progress Energy and Duke Energy withdrew the application of the merger of PEC and Duke Energy Carolinas, as the merger of these entities is not likely to occur for several years after the close of the merger. The SCPSC held hearings regarding the application for approval of the joint dispatch agreement on December 12, 2011. During the hearing, PEC, Duke Energy Carolinas and the ORS agreed to terminate the settlement agreement, which resolved the ORS's issues in the NCUC merger proceeding, and replaced it with a commitment by PEC and Duke Energy Carolinas to provide PEC's and Duke Energy Carolinas' retail customers in South Carolina pro rata benefits equivalent to those approved by the NCUC in its order ruling upon PEC's and Duke Energy Carolinas' merger application. The docket will remain open pending the FERC's issuance of its final orders on the merger-related actions before the FERC.
• On October 28, 2011, the Kentucky Public Service Commission approved Progress Energy's and Duke Energy's merger-related settlement agreement with the Attorney General of the Commonwealth of Kentucky.

The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to consummation of the merger. Among other restrictions, the Merger Agreement limits our total capital spending, limits the extent to which we can obtain financing through long-term debt and equity, and we may not, without the prior approval of Duke Energy, increase our quarterly common stock dividend of $0.62 per share. In the fourth quarter of 2011, our board of directors aligned Progress Energy's dividend payment schedule with that of Duke Energy such that following the closing of the merger, all stockholders of the combined company would receive dividends under the Duke Energy dividend schedule.

Certain substantial changes in ownership of Progress Energy, including the merger, can impact the timing of the utilization of tax credit carry forwards and net operating loss carry forwards (See Note 15 in the 2011 Form 10-K).

The Merger Agreement contains certain termination rights for both companies; under specified circumstances we may be required to pay Duke Energy $400 million and Duke Energy may be required to pay us $675 million. In addition, under specified circumstances each party may be required to reimburse the other party for up to $30 million of merger-related expenses.

In connection with the merger, we established an employee retention plan for certain eligible employees. Payments under the plan are contingent upon the consummation of the merger and the employees' continued employment through a specified time period following the merger. These payments will be recorded as compensation expense following consummation of the merger. We estimate the costs of the retention plan to be $14 million.

In connection with the merger, we offered a voluntary severance plan (VSP) to certain eligible employees. Payments under the plan are contingent upon the consummation of the merger. Approximately 650 employees requested and were approved for separation under the VSP in 2011. The cost of the VSP is estimated to be between $90 million to $100 million, including $65 million to $70 million for PEC and $25 million to $30 million for PEF. If the employee is not required to work for a significant period after the consummation of the merger, the costs of any benefits paid under the VSP will be measured and recorded upon consummation of the merger. If a significant retention period exists, the costs of benefits equal to what would be paid under our existing severance plan will be measured and recorded upon consummation of the merger. Any additional benefits paid under the VSP will be recorded ratably over the remaining service periods of the affected employees.

In addition, we evaluated our business needs for office space after the merger and formulated an exit plan to vacateone of our corporate headquarters buildings. We have begun to gradually vacate the premises and will be fully vacated by January 1, 2013. In December 2011, we executed an agreement with a third party to sublease the building until 2035. The estimated exit cost liability associated with this exit plan is $17 million for us, of which $12 million of expense is attributable to PEC and $5 million to PEF. The exit cost liability will be recognized proportionately as we vacate the premises, which began in the fourth quarter of 2011. During the first quarter of 2012, we recorded exit cost liabilities of $3 million for us, of which $2 million of expense is attributable to PEC and $1 million to PEF. At March 31, 2012, the total exit cost liability recorded by us is $8 million, of which $6 million of expense is attributable to PEC and $2 million of expense is attributable to PEF. These costs are included in merger and integration-related costs.

We incurred merger and integration-related costs of $5 million, net of tax, including $3 million, net of tax, and $2 million, net of tax, at PEC and PEF, respectively, during the quarter ended March 31, 2012. We incurred merger and integration-related costs of $14 million, net of tax, including $7 million, net of tax, and $7 million, net of tax, at PEC and PEF, respectively, during the quarter ended March 31, 2011.These costs are included in operations and maintenance (O&M) expense in our Consolidated Statements of Comprehensive Income.

PEF

Merger Agreement [Line Items]

Proposed Business Combination Disclosure [Text Block]

2.MERGER AGREEMENT

On January 8, 2011, Duke Energy Corporation (Duke Energy) and Progress Energy entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Progress Energy will be acquired by Duke Energy in a stock-for-stock transaction and become a wholly owned subsidiary of Duke Energy. The Merger Agreement originally had a termination date of January 8, 2012, which has been extended to July 8, 2012. The Merger Agreement can be extended past July 8, 2012, only by mutual agreement of Progress Energy and Duke Energy.

Under the terms of the Merger Agreement, each share of Progress Energy common stock will be cancelled and converted into the right to receive 2.6125 shares of Duke Energy common stock. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock will be converted into an option to acquire, or an equity award relating to, 2.6125 shares of Duke Energy common stock. The board of directors of Duke Energy approved a reverse stock split, at a ratio of 1-for-3, subject to completion of the merger. Accordingly, the adjusted exchange ratiois expected to be 0.87083 of a share of Duke Energy common stock, options and equity awards for each Progress Energy common share, option and equity award.

The combined company, to be called Duke Energy, will have an 18-member board of directors. The board will be comprised of, subject to their ability and willingness to serve, all 11 current directors of Duke Energy and seven current directors of Progress Energy. At the time of the merger, William D. Johnson, Chairman, President and CEO of Progress Energy, will be President and CEO of Duke Energy, and James E. Rogers, Chairman, President and CEO of Duke Energy, will be the Executive Chairman of the board of directors of Duke Energy, subject to their ability and willingness to serve.

Consummation of the merger is subject to customary conditions, including, among others things, approval by the shareholders of each company, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and receipt of approvals, to the extent required, from the FERC, the Federal Communications Commission, the NRC, the NCUC, the Kentucky Public Service Commission and the SCPSC. Although there are no merger-specific regulatory approvals required in Indiana, Ohio or Florida, the companies will continue to update the public service commissions in those states on the merger, as applicable and as required. The status of these matters is as follows, and we cannot predict the outcome of pending approvals:

Shareholder Approval

• On August 23, 2011, the merger was approved by the shareholders of Progress Energy and Duke Energy.

  Federal Regulatory Approvals

• Progress Energy and Duke Energy met their obligations under the Hart-Scott-Rodino Act with their March 28, 2011 filing with the U.S. Department of Justice (DOJ) for review under U.S. antitrust laws. Because the merger was not anticipated to close before the April 26,2012 expiration of the original filing, Progress Energy and Duke Energy filed a new Hart-Scott-Rodino filing on March 22, 2012, in order to be able to close the merger and continue to meet their obligations under the Hart-Scott-Rodino Act. The 30-day waiting period required by the Hart-Scott-Rodino Act expired without Progress Energy or Duke Energy having received requests for additional information. Progress Energy and Duke Energy have met their obligations under the Hart-Scott-Rodino Act.
• On January 5, 2012, the Federal Communications Commission extended its approval of the Assignment of Authorization filings to transfer control of certain licenses. The extended approval expires on July 12, 2012.
• On September 30, 2011, the FERC, which assesses market power-related issues, conditionally approved the merger application filed by Progress Energy and Duke Energy. The approval is subject to the FERC's acceptance of market power mitigation measures to address the FERC's finding that the combined company could have an adverse effect on competition in the North Carolina and South Carolina wholesale power markets. Progress Energy and Duke Energy filed a market power mitigation plan with the FERC on October 17, 2011,that proposed a “virtual divestiture” under which power up to a certain amount would have been offered into the wholesale market rather than the sale or divestiture of physical assets. A virtual divestiture is one option the FERC indicated could be used to mitigate its market power concerns. On December 14, 2011, the FERC affirmed its conditional approval of the merger, but the FERC rejected the proposed market power mitigation plan. On March 26, 2012, Progress Energy and Duke Energy filed a second market power mitigation plan with the FERC. The revised mitigation plan consists of both interim and permanent components. The two- to three-year interim component consists of several power purchase agreements whereby the companies propose to sell capacity and firm energy during the summer (June – August) and winter (December – February) to new market participants. Together, the companies would sell 800 megawatts (MWs) during summer off-peak hours, 475 MWs during summer peak hours, 225 MWs during winter off-peak hours, and 25 MWs during winter peak hours. The agreements have been executed, contingent on the closing of the merger, and will be in effect upon the closing of the merger and remain in effect until the permanent component is operational. The permanent component consists of seven transmission projects to be constructed, estimated to cost approximately $110 million. The transmission projects significantly increase power import capabilities into the PEC and Duke Energy Carolinas service territories and enhance competitive power supply options for the region.Progress Energy and Duke Energy have requested that the FERC issue orders approving the revised mitigation plan within 60 days of the filing date, but no later than June 8, 2012. There is no statutory requirement that the FERC act within a specified timeframe. On April 10, 2012, Progress Energy and Duke Energy received a request from the FERC for additional information on the transmission-related models provided by Progress Energy and Duke Energy in the revised mitigation plan. On April 13, 2012, Progress Energy and Duke Energy responded to the FERC's request. In the response, the companies reaffirmed their request that the FERC approve the revised mitigation plan within 60 days of the original filing date, but no later than June 8, 2012. Fourparticipants to the proceedings filed comments before the April 25, 2012 filing deadline.On May 1, 2012, the companies filed a response to the comments with the FERC. The companies are working with the North Carolina Public Staff and the South Carolina Office of Regulatory Staff (ORS) on appropriate state ratemaking treatment associated with the measures in the revised market mitigation plan and other merger-related issues. The companies' decision to close the merger will be subject to the companies obtaining acceptable resolution of various state ratemaking issues.
• On April 4, 2011, Progress Energy and Duke Energy made two additional filings with the FERC. The first filing is a joint dispatch agreement, pursuant to which PEC and Duke Energy Carolinas will agree to jointly dispatch their generation facilities in order to achieve certain of the operating efficiencies expected to result from the merger. The second filing is a joint open access transmission tariff (OATT) pursuant to which PEC and Duke Energy Carolinas will agree to provide transmission service over their transmission facilities under a single transmission rate. On December 14, 2011, in conjunction with the aforementioned decision on the proposed market power mitigation plan, the FERC dismissed the applications for approval of the joint dispatch agreement and the joint OATT without prejudice. As allowed under the FERC's December 14, 2011 order, Progress Energy and Duke Energy refiled the joint dispatch agreement and OATT with the FERCon March 26, 2012.
• On December 2, 2011, the NRC approved the filing requesting an indirect transfer of control of licenses for Progress Energy's nuclear facilities to include Duke Energy as the ultimate parent corporation on these licenses.

  State Regulatory Approvals

• On April 4, 2011, Progress Energy and Duke Energy filed a merger approval application and an application for approval of a joint dispatch agreement between PEC and Duke Energy Carolinas with the NCUC. On September 2, 2011, the North Carolina Public Staff filed a settlement agreement with the NCUC. On September 6, 2011, Progress Energy and Duke Energy signed a settlement with the ORS, a party to the North Carolina proceedings to resolve the ORS's issues in the North Carolina proceeding. Under the settlement agreement with the North Carolina Public Staff, Progress Energy and Duke Energy will provide $650 million in system fuel cost savings for customers in North Carolina and South Carolina over the five years following the close of the merger, maintain their current level of community support in North Carolina for the next four years, and provide $15 million for low-income energy assistance and workforce development in North Carolina. The settlement agreement also provides that direct merger-related expenses will not be recovered from customers; however, PEC may request recovery of costs incurred to create operational savings.The NCUC held hearings regarding the application on September 20-22, 2011. On November 23, 2011, Progress Energy and Duke Energy filed proposed orders and briefs with the NCUC. The docket will remain open pending the FERC's issuance of its final orders on the merger-related actions before the FERC.
• On April 25, 2011, Progress Energy and Duke Energy filed an application for approval of the merger of PEC and Duke Energy Carolinas and an application for approval of a joint dispatch agreement between PEC and Duke Energy Carolinas with the SCPSC. On September 13, 2011, Progress Energy and Duke Energy withdrew the application of the merger of PEC and Duke Energy Carolinas, as the merger of these entities is not likely to occur for several years after the close of the merger. The SCPSC held hearings regarding the application for approval of the joint dispatch agreement on December 12, 2011. During the hearing, PEC, Duke Energy Carolinas and the ORS agreed to terminate the settlement agreement, which resolved the ORS's issues in the NCUC merger proceeding, and replaced it with a commitment by PEC and Duke Energy Carolinas to provide PEC's and Duke Energy Carolinas' retail customers in South Carolina pro rata benefits equivalent to those approved by the NCUC in its order ruling upon PEC's and Duke Energy Carolinas' merger application. The docket will remain open pending the FERC's issuance of its final orders on the merger-related actions before the FERC.
• On October 28, 2011, the Kentucky Public Service Commission approved Progress Energy's and Duke Energy's merger-related settlement agreement with the Attorney General of the Commonwealth of Kentucky.

The Merger Agreement includes certain restrictions, limitations and prohibitions as to actions we may or may not take in the period prior to consummation of the merger. Among other restrictions, the Merger Agreement limits our total capital spending, limits the extent to which we can obtain financing through long-term debt and equity, and we may not, without the prior approval of Duke Energy, increase our quarterly common stock dividend of $0.62 per share. In the fourth quarter of 2011, our board of directors aligned Progress Energy's dividend payment schedule with that of Duke Energy such that following the closing of the merger, all stockholders of the combined company would receive dividends under the Duke Energy dividend schedule.

Certain substantial changes in ownership of Progress Energy, including the merger, can impact the timing of the utilization of tax credit carry forwards and net operating loss carry forwards (See Note 15 in the 2011 Form 10-K).

The Merger Agreement contains certain termination rights for both companies; under specified circumstances we may be required to pay Duke Energy $400 million and Duke Energy may be required to pay us $675 million. In addition, under specified circumstances each party may be required to reimburse the other party for up to $30 million of merger-related expenses.

In connection with the merger, we established an employee retention plan for certain eligible employees. Payments under the plan are contingent upon the consummation of the merger and the employees' continued employment through a specified time period following the merger. These payments will be recorded as compensation expense following consummation of the merger. We estimate the costs of the retention plan to be $14 million.

In connection with the merger, we offered a voluntary severance plan (VSP) to certain eligible employees. Payments under the plan are contingent upon the consummation of the merger. Approximately 650 employees requested and were approved for separation under the VSP in 2011. The cost of the VSP is estimated to be between $90 million to $100 million, including $65 million to $70 million for PEC and $25 million to $30 million for PEF. If the employee is not required to work for a significant period after the consummation of the merger, the costs of any benefits paid under the VSP will be measured and recorded upon consummation of the merger. If a significant retention period exists, the costs of benefits equal to what would be paid under our existing severance plan will be measured and recorded upon consummation of the merger. Any additional benefits paid under the VSP will be recorded ratably over the remaining service periods of the affected employees.

In addition, we evaluated our business needs for office space after the merger and formulated an exit plan to vacateone of our corporate headquarters buildings. We have begun to gradually vacate the premises and will be fully vacated by January 1, 2013. In December 2011, we executed an agreement with a third party to sublease the building until 2035. The estimated exit cost liability associated with this exit plan is $17 million for us, of which $12 million of expense is attributable to PEC and $5 million to PEF. The exit cost liability will be recognized proportionately as we vacate the premises, which began in the fourth quarter of 2011. During the first quarter of 2012, we recorded exit cost liabilities of $3 million for us, of which $2 million of expense is attributable to PEC and $1 million to PEF. At March 31, 2012, the total exit cost liability recorded by us is $8 million, of which $6 million of expense is attributable to PEC and $2 million of expense is attributable to PEF. These costs are included in merger and integration-related costs.

We incurred merger and integration-related costs of $5 million, net of tax, including $3 million, net of tax, and $2 million, net of tax, at PEC and PEF, respectively, during the quarter ended March 31, 2012. We incurred merger and integration-related costs of $14 million, net of tax, including $7 million, net of tax, and $7 million, net of tax, at PEC and PEF, respectively, during the quarter ended March 31, 2011.These costs are included in operations and maintenance (O&M) expense in our Consolidated Statements of Comprehensive Income.

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Unaudited Condensed Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Utility Plant
Utility plant in service	$ 31,284	$ 31,065
Accumulated depreciation	(12,141)	(12,001)
Utility plant in service, net	19,143	19,064
Other utility plant, net	217	217
Construction work in progress	2,698	2,449
Nuclear fuel, net of amortization	747	767
Total utility plant, net	22,805	22,497
Current assets
Cash and cash equivalents	565	230
Receivables, net	758	889
Notes receivable from affiliated companies	0	0
Inventory, net	1,447	1,438
Regulatory assets	250	275
Derivative collateral posted	166	147
Deferred tax assets	518	371
Prepayments and other current assets	131	133
Total current assets	3,835	3,483
Deferred debits and other assets
Regulatory assets	3,123	3,025
Nuclear decommissioning trust funds	1,762	1,647
Miscellaneous other property and investments	413	407
Goodwill	3,655	3,655
Other assets and deferred debits	382	345
Total deferred debits and other assets	9,335	9,079
Total assets	35,975	35,059
Common stock equity
Common stock	7,451	7,434
Accumulated other comprehensive loss	(160)	(165)
Retained earnings	2,718	2,752
Total common stock equity	10,009	10,021
Noncontrolling interests	2	4
Total equity	10,011	10,025
Preferred stock of subsidiaries	93	93
Long-term debt, affiliate	273	273
Long-term debt, net	11,742	11,718
Total capitalization	22,119	22,109
Current liabilities
Current portion of long-term debt	1,375	950
Short-term debt	1,056	671
Notes payable to affiliated companies	0	0
Accounts payable	878	909
Interest accrued	193	200
Dividends declared	2	78
Customer deposits	343	340
Derivative liabilities	484	436
Accrued compensation and other benefits	127	195
Other current liabilities	304	306
Total current liabilities	4,762	4,085
Deferred credits and other liabilities
Noncurrent income tax liabilities	2,637	2,355
Accumulated deferred investment tax credits	101	103
Regulatory liabilities	2,684	2,700
Asset retirement obligations	1,282	1,265
Accrued pension and other benefits	1,611	1,625
Derivative liabilities	364	352
Other liabilities and deferred credits	415	465
Total deferred credits and other liabilities	9,094	8,865
Commitments and contingencies (Notes 13 and 14)	0	0
Total capitalization and liabilities	35,975	35,059
PEC
Utility Plant
Utility plant in service	17,613	17,439
Accumulated depreciation	(7,628)	(7,567)
Utility plant in service, net	9,985	9,872
Other utility plant, net	181	181
Construction work in progress	1,439	1,294
Nuclear fuel, net of amortization	519	540
Total utility plant, net	12,124	11,887
Current assets
Cash and cash equivalents	21	20
Receivables, net	400	492
Receivables from affiliated companies	21	13
Inventory, net	779	775
Deferred fuel cost	25	31
Deferred tax assets	166	142
Prepayments and other current assets	99	76
Total current assets	1,511	1,549
Deferred debits and other assets
Regulatory assets	1,352	1,310
Nuclear decommissioning trust funds	1,163	1,088
Miscellaneous other property and investments	187	188
Other assets and deferred debits	87	80
Total deferred debits and other assets	2,789	2,666
Total assets	16,424	16,102
Common stock equity
Common stock	2,155	2,148
Accumulated other comprehensive loss	(66)	(71)
Retained earnings	2,884	3,011
Total common stock equity	4,973	5,088
Preferred stock	59	59
Long-term debt, net	3,693	3,693
Total capitalization	8,725	8,840
Current liabilities
Current portion of long-term debt	500	500
Short-term debt	441	188
Notes payable to affiliated companies	42	31
Accounts payable	520	527
Payables to affiliated companies	64	41
Interest accrued	64	77
Customer deposits	120	116
Derivative liabilities	149	130
Accrued compensation and other benefits	76	110
Other current liabilities	118	85
Total current liabilities	2,094	1,805
Deferred credits and other liabilities
Noncurrent income tax liabilities	2,062	1,976
Accumulated deferred investment tax credits	97	98
Regulatory liabilities	1,632	1,543
Asset retirement obligations	908	896
Accrued pension and other benefits	677	687
Other liabilities and deferred credits	229	257
Total deferred credits and other liabilities	5,605	5,457
Commitments and contingencies (Notes 13 and 14)	0	0
Total capitalization and liabilities	16,424	16,102
PEF
Utility Plant
Utility plant in service	13,506	13,461
Accumulated depreciation	(4,433)	(4,356)
Utility plant in service, net	9,073	9,105
Held for future use	36	36
Construction work in progress	1,259	1,155
Nuclear fuel, net of amortization	228	227
Total utility plant, net	10,596	10,523
Current assets
Cash and cash equivalents	18	16
Receivables, net	345	372
Receivables from affiliated companies	32	19
Notes receivable from affiliated companies	6	0
Inventory, net	669	663
Regulatory assets	225	244
Derivative collateral posted	136	123
Deferred tax assets	223	138
Prepayments and other current assets	25	39
Total current assets	1,679	1,614
Deferred debits and other assets
Regulatory assets	1,659	1,602
Nuclear decommissioning trust funds	599	559
Other assets and deferred debits	199	186
Total deferred debits and other assets	2,457	2,347
Total assets	14,732	14,484
Common stock equity
Common stock	1,760	1,757
Accumulated other comprehensive loss	(26)	(27)
Retained earnings	2,966	2,945
Total common stock equity	4,700	4,675
Preferred stock	34	34
Long-term debt, net	4,057	4,482
Total capitalization	8,791	9,191
Current liabilities
Current portion of long-term debt	425	0
Short-term debt	360	233
Notes payable to affiliated companies	0	8
Accounts payable	336	358
Payables to affiliated companies	38	25
Interest accrued	66	54
Customer deposits	223	224
Derivative liabilities	335	268
Accrued compensation and other benefits	30	53
Other current liabilities	129	112
Total current liabilities	1,942	1,335
Deferred credits and other liabilities
Noncurrent income tax liabilities	1,553	1,405
Regulatory liabilities	967	1,071
Asset retirement obligations	374	369
Accrued pension and other benefits	591	598
Capital lease obligations	188	189
Derivative liabilities	234	231
Other liabilities and deferred credits	92	95
Total deferred credits and other liabilities	3,999	3,958
Commitments and contingencies (Notes 13 and 14)	0	0
Total capitalization and liabilities	$ 14,732	$ 14,484

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Financial Information by Business Segment

3 Months Ended

Mar. 31, 2012

Financial Information By Business Segment Disclosure [Abstract]

Financial Information by Business Segment

12.FINANCIAL INFORMATION BY BUSINESS SEGMENT

Our reportable segments are PEC and PEF, both of which are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina and in portions of Florida, respectively. These electric operations also distribute and sell electricity to other utilities, primarily on the east coast of the United States.

In addition to the reportable operating segments, the Corporate and Other segment includes the operations of the Parent and PESC and other miscellaneous nonregulated businesses that do not separately meet the quantitative thresholds for disclosure as separate reportable business segments.

Products and services are sold between the various reportable segments. All intersegment transactions are at cost.

(in millions)		PEC		PEF		Corporate and Other		Eliminations		Totals
At and for the three months ended March 31, 2012
Revenues
	Unaffiliated	$	1,085	$	1,005	$	2	$	-	$	2,092
	Intersegment		-		-		59		(59)		-
	Total revenues		1,085		1,005		61		(59)		2,092
Ongoing Earnings			60		130		(47)		-		143
Total assets			16,424		14,732		21,248		(16,429)		35,975
For the three months ended March 31, 2011
Revenues
	Unaffiliated	$	1,133	$	1,032	$	2	$	-	$	2,167
	Intersegment		-		-		74		(74)		-
	Total revenues		1,133		1,032		76		(74)		2,167
Ongoing Earnings			139		111		(48)		-		202

Management uses the non-GAAP financial measure “Ongoing Earnings” as a performance measure to evaluate the results of our segments and operations. Ongoing Earnings as presented here may not be comparable to similarly titled measures used by other companies. Ongoing Earnings is computed as GAAP net income attributable to controlling interests less discontinued operations and the effects of certain identified gains and charges, which are considered Ongoing Earnings adjustments. Some of the excluded gains and charges have occurred in more than one reporting period but are not considered representative of fundamental core earnings. Management has identified the following Ongoing Earnings adjustments: tax levelization, which increases or decreases the tax expense recorded in the reporting period to reflect the annual projected tax rate, because it has no impact on annual earnings; and CVO mark-to-market adjustments because we are unable to predict changes in their fair value. Additionally, management does not consider merger and integration costs, and operating results of discontinued operations to be representative of our ongoing operations and excluded these items in computing Ongoing Earnings.

A reconciliation of consolidated Ongoing Earnings to net income attributable to controlling interests follows:

(in millions)		2012		2011
Ongoing Earnings		$	143	$	202
Tax levelization			(7)		(2)
CVO mark-to-market			8		-
Merger and integration costs, net of tax benefit of $2 and $- (Note 2)			(5)		(14)
Continuing income attributable to noncontrolling interests, net of tax			2		1
Income from continuing operations			141		187
Discontinued operations, net of tax			11		(2)
Net income attributable to noncontrolling interests, net of tax			(2)		(1)
	Net income attributable to controlling interests	$	150	$	184

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Document and Entity Information	3 Months Ended
	Mar. 31, 2012	May 03, 2012
Document and Entity Information [Line Items]
Entity registrant name	PROGRESS ENERGY INC
Entity central index key	0001094093
Document type	10-Q
Document period end date	Mar. 31, 2012
Amendment flag	true
Amendment description	This Amendment No. 1 on Form 10-Q/A (this Amendment) amends the Quarterly Report on Form 10-Q of Progress Energy, Inc., Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF) (collectively, the Progress Registrants) for the quarterly period ended March 31, 2012, originally filed with the Securities and Exchange Commission on May 8, 2012 (the Original Filing). This Amendment is being filed solely to include certain Extensible Business Reporting Language (XBRL) information in Exhibit 101 that was inadvertently excluded from the timely filed Original Filing, in accordance with Rule 405 of Regulation S-T.
Entity current reporting status	Yes
Entity voluntary filers	No
Current fiscal year end date	--12-31
Entity filer category	Large Accelerated Filer
Entity well known seasoned issuer	Yes
Entity common stock shares outstanding		296,021,515
Document fiscal year focus	2012
Document fiscal period focus	Q1
PEC
Document and Entity Information [Line Items]
Entity registrant name	Carolina Power & Light Co
Entity central index key	0000017797
Current fiscal year end date	--12-31
Entity filer category	Non-accelerated Filer
PEF
Document and Entity Information [Line Items]
Entity registrant name	Florida Power Corp
Entity central index key	0000037637
Current fiscal year end date	--12-31
Entity filer category	Non-accelerated Filer

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Enviromental Matters

3 Months Ended

Mar. 31, 2012

Enviromental Matters Disclosure [Line Items]

Environmental Matters

13.ENVIRONMENTAL MATTERS

We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot always be precisely estimated.

A.       HAZARDOUS AND SOLID WASTE

The U.S. Environmental Protection Agency (EPA) and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, primarily ash, from each of the Utilities' coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. In June 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residues management and disposal under federal hazardous waste rules. The other option would have the EPA set design and performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste with enforcement by the courts or state laws. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residuals that are recycled. A final rule is expected in late 2012. There are federal legislative proposals that may direct the EPA to regulate coal combustion residues destined for disposal as non-hazardous wastes. Environmental groups filed a lawsuit on April 5, 2012, in the U.S. District Court for the District of Columbia to require the EPA to complete its rulemaking process and finalize new regulations for the storage, transportation and disposal of coal combustion residues. Compliance plans and estimated costs to meet the requirements of new regulations or statutes will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter.

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liability. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. 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 of our potential liability by the EPA, the state of North Carolina, the state of Florida, or potentially responsible party (PRP) groups 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 PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses. Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of potential and pending claims cannot be predicted.

We measure our liability for environmental 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 in O&M expense on the Statements of Comprehensive Income 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. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future.

The following tables contain information about accruals for probable and estimable costs related to various environmental sites, which were included in other current liabilities and other liabilities and deferred credits on the Balance Sheets:

PROGRESS ENERGY
(in millions)		MGP and Other Sites		Remediation of Distribution and Substation Transformers		Total
Balance, December 31, 2011		$	17	$	6	$	23
Amount accrued for environmental loss contingencies			3		2		5
Expenditures for environmental loss contingencies			(2)		(2)		(4)
Balance, March 31, 2012(a)		$	18	$	6	$	24
Balance, December 31, 2010		$	20	$	15	$	35
Amount accrued for environmental loss contingencies			-		-		-
Expenditures for environmental loss contingencies			(1)		(5)		(6)
Balance, March 31, 2011(a)		$	19	$	10	$	29
(a)	Expected to be paid out over one to 12 years.
PEC
(in millions)						MGP and Other Sites
Balance, December 31, 2011						$	11
Change in estimate for environmental loss contingencies							(1)
Expenditures for environmental loss contingencies							(1)
Balance, March 31, 2012(a)						$	9
Balance, December 31, 2010						$	12
Amount accrued for environmental loss contingencies							-
Expenditures for environmental loss contingencies							-
Balance, March 31, 2011(a)						$	12
(a)	Expected to be paid out over one to ten years.
PEF
(in millions)		MGP and Other Sites		Remediation of Distribution and Substation Transformers		Total
Balance, December 31, 2011		$	6	$	6	$	12
Amount accrued for environmental loss contingencies			4		2		6
Expenditures for environmental loss contingencies			(1)		(2)		(3)
Balance, March 31, 2012(a)		$	9	$	6	$	15
Balance, December 31, 2010		$	8	$	15	$	23
Amount accrued for environmental loss contingencies			-		-		-
Expenditures for environmental loss contingencies			(1)		(5)		(6)
Balance, March 31, 2011(a)		$	7	$	10	$	17
(a)	Expected to be paid out over one to 12 years.

PROGRESS ENERGY

In addition to the Utilities' sites discussed under “PEC” and “PEF” below, we incurred indemnity obligations related to certain pre-closing liabilities of divested subsidiaries, including certain environmental matters (See discussion under Guarantees in Note 14B).

PEC

PEC has recorded a minimum estimated total remediation cost for its remaining MGP site based upon its historical experience with remediation of several of its MGP sites. Remediation of PEC's other MGP sites has been substantially completed.The maximum amount of the range for all of PEC's environmental sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future.

In 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, N.C. (Ward) site. The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA's past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. At March 31, 2012 and December 31, 2011, PEC's recorded liability for the site was approximately $5 million. In 2008 and 2009, PEC filed civil actions against non-participating PRPs seeking contribution for and recovery of costs incurred in remediating the Ward site, as well as a declaratory judgment that defendants are jointly and severally liable for response costs at the site. PEC has settled with a number of the PRPs and is in active settlement negotiations with others. In March 2010, the federal district court in which this matter is pending denied motions to dismiss filed by a number of defendants, but granted several other motions filed by state agencies and successor entities. The court established a “test case” programproviding for a determination of liability on the part of a set of representative defendants. Summary judgment motions and responsive pleadings are being filed by and against these defendants and discovery and briefing are expected to be completed by May 2012. Meanwhile, proceedings with respect to the other defendants have been stayed. The outcome of these matters cannot be predicted.

In 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for further investigation at the Ward facility and certain adjacent areas (Ward OU2). The EPA's estimate for the selected remedy for Ward OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the opportunity to negotiate implementation of a response action for Ward OU1 and a remedial investigation and feasibility study for Ward OU2, as well as reimbursement to the EPA of approximately $1 million for the EPA's past expenditures in addressing conditions at the site. In September 2011, the EPA issued unilateral administrative orders to certain parties, which did not include PEC, directing the performance of remedial activities with regard to Ward OU1. It is not possible at this time to reasonably estimate the total amount of PEC's obligation, if any, for Ward OU1 and Ward OU2.

PEF

The accruals for PEF's MGP and other sites relate to two former MGP sites and other sites associated with PEF that have required, or are anticipated to require, investigation and/or remediation. Remediation of one MGP site has been substantially completed. At March 31, 2012, PEF's accrual primarily relates to a MGP site located in Orlando, Fla. The PRP group for the Orlando MGP site has agreed to an interim allocation for the Orlando MGP site and is conducting a feasibility study for remediation of soil and groundwater down to 50 feet, which has not been completed. The study preliminarily indicates a range of viable remedial approaches, and agreement has not been reached on the remediation approach. During the quarter ended March 31, 2012, one participating PRP ended its participation in the PRP group. The PRP allocations have been adjusted accordingly. The PRP group for the Orlando MGP site intends to seek recovery from the non-participating PRP, but no amount for recovery has been recorded. PEF has accrued its best estimate of its obligation with respect to the Orlando MGP site. Based on current estimates for the range of viable remedial approaches and its current allocation share, PEF could incur additional obligations of up to approximately $4 million for remediation of soil and groundwater down to 50 feet. Results of an investigative study revealed the presence of MGP byproduct material below 200 feet from the surface. The layer between approximately 50 feet and 200 feet below the surface, which is clay, is not impacted. The maximum amount of the range for remediation, if any, below 200 feet at the Orlando MGP site and for PEF's other sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. We cannot predict the outcome of this matter.

PEF has received approval from the FPSC for recovery through the ECRC of the majority of costs associated with the remediation of distribution and substation transformers. Under agreements with the Florida Department of Environmental Protection (FDEP), PEF has reviewed all distribution transformer sites and all substation sites for mineral oil-impacted soil caused by equipment integrity issues. Should additional distribution transformer sites be identified outside of this population, the distribution O&M expense will not be recoverable through the ECRC.

B.       AIR AND WATER QUALITY

We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations governing air and water quality, which likely would result in increased capital expenditures and O&M expense. Control equipment installed for compliance with then-existing or proposed laws and regulations may address some of the issues outlined. PEC and PEF have been developing an integrated compliance strategy to meet these evolving requirements. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the North Carolina Clean Smokestacks Act (Clean Smokestacks Act). The air quality controls installed to comply with nitrogen oxides (NOx)and sulfur dioxide (SO2) requirements under certain sections of the Clean Air Act(CAA) and the Clean Smokestacks Act, as well as PEC's plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address theCAIR requirements for NOx and SO2for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of CAIR.

After prior mercury regulation was vacated in federal court, the EPA developed maximum achievable control technology (MACT) standards. The Mercury and Air Toxics Standards (MATS), which are the final MACT standards for coal-fired and oil-fired electric steam generating units,became effective on April 16, 2012. Compliance is due in three years with provisions for a one-year extension from state agencies on a case-by-case basis. The MATS contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units.Several petitions regarding portions of the MATS rule have been filed in the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals), including one by the Utility Air Regulatory Group, of which Progress Energy is a member. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. Due to significant investments in NOx and SO2 emission controls and fleet modernization projects completed or under way, we believe PEC is relatively well positioned to comply with the MATS. However, PEF will be required to complete additional emissions controls and/or fleet modernization projects in order to meet the compliance timeframe for the MATS. On March 29, 2012, PEF announced plans to convert Anclote to 100 percent natural gas, which will substantially reduce emissions, as part of its MATS compliance strategy. We are continuing to evaluate the impacts of the MATSon the Utilities. We anticipate that compliance with the MATS will satisfy the North Carolina mercury rule requirements for PEC. The outcome of these matters cannot be predicted.

The CAIR, issued by the EPA, required the District of Columbia and 28 states, including North Carolina, South Carolina and Florida, to reduce NOx and SO2 emissions. The CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for NOx and beginning in 2010 and 2015, respectively, for SO2.States were required to adopt rules implementing the CAIR, and the EPA approved the North Carolina CAIR, the South Carolina CAIR and the Florida CAIR. A 2008 decision by the D.C. Court of Appeals remanded the CAIR without vacating it for the EPA to conduct further proceedings.

On July 7, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR)to replace the CAIR. The CSAPR, which was scheduled to take effect on January 1, 2012, contains new emissions trading programs for NOx and SO2 emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. A number of parties, including groups of which PEC and PEF are members, filed petitions for reconsideration and stay of, as well as legal challenges to, the CSAPR. On December 30, 2011, the D.C. Court of Appeals issued an order staying the implementation of the CSAPR, pending a decision by the court resolving the challenges to the rule. Oral argument for the CSAPR litigation occurred on April 13, 2012. As a result of the stay of CSAPR, the CAIR continues to remain in effect.The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO2 Group 1 trading program and the SO2 Group 2 trading program. If the CSAPR is upheld, North Carolina and South Carolina are included in the NOx and SO2 annual trading programs, as well as the NOx ozone season trading program. North Carolina remains classified as a Group 1 state, which will require additional NOx and SO2 emission reductions beginning in January 2014. South Carolina remains classified as a Group 2 state with no additional reductions required in 2014. Under the CSAPR, Florida is subject only to the NOx ozone season trading program. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe PEC and PEF are positioned to comply with the CSAPR without the need for significant capital expenditures. We cannot predict the outcome of this matter.

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at CR4 and CR5, which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire Crystal RiverUnits 1 and 2 (CR1 and CR2) as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 are scheduled to be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was originally anticipated to be around 2020. As discussed in Note 5B, major construction activities for Levy are being postponed, and the in-service date for the first Levy unit has been shifted to 2024. As required, PEF will continue to advise the FDEP of these developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF's compliance with environmental regulations. We cannot predict the outcome of this matter.

As previously discussed, the CSAPR establishes new NOx annual and seasonal ozone programs and a new SO2 trading program. NOx and SO2 emission allowances applicable to the current CAIR cannot be used to satisfy the new CSAPR programs. SO2 emission allowances will be utilized by the Utilities to comply with existing CAA requirements. NOx allowances cannot be utilized to comply with other requirements. As a result of the previously discussed D.C. Court of Appeals order staying the implementation of the CSAPR, the CAIR emission allowance program remains in effect. Emission allowances are included on the Balance Sheets in inventory and in other assets and deferred debits and have not changed materially from what was reported in the 2011 Form 10-K.

PEC

Enviromental Matters Disclosure [Line Items]

Environmental Matters

13.ENVIRONMENTAL MATTERS

We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot always be precisely estimated.

A.       HAZARDOUS AND SOLID WASTE

The U.S. Environmental Protection Agency (EPA) and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, primarily ash, from each of the Utilities' coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. In June 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residues management and disposal under federal hazardous waste rules. The other option would have the EPA set design and performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste with enforcement by the courts or state laws. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residuals that are recycled. A final rule is expected in late 2012. There are federal legislative proposals that may direct the EPA to regulate coal combustion residues destined for disposal as non-hazardous wastes. Environmental groups filed a lawsuit on April 5, 2012, in the U.S. District Court for the District of Columbia to require the EPA to complete its rulemaking process and finalize new regulations for the storage, transportation and disposal of coal combustion residues. Compliance plans and estimated costs to meet the requirements of new regulations or statutes will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter.

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liability. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. 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 of our potential liability by the EPA, the state of North Carolina, the state of Florida, or potentially responsible party (PRP) groups 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 PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses. Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of potential and pending claims cannot be predicted.

We measure our liability for environmental 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 in O&M expense on the Statements of Comprehensive Income 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. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future.

The following tables contain information about accruals for probable and estimable costs related to various environmental sites, which were included in other current liabilities and other liabilities and deferred credits on the Balance Sheets:

PEC
(in millions)		MGP and Other Sites
Balance, December 31, 2011		$	11
Change in estimate for environmental loss contingencies			(1)
Expenditures for environmental loss contingencies			(1)
Balance, March 31, 2012(a)		$	9
Balance, December 31, 2010		$	12
Amount accrued for environmental loss contingencies			-
Expenditures for environmental loss contingencies			-
Balance, March 31, 2011(a)		$	12
(a)	Expected to be paid out over one to ten years.

PROGRESS ENERGY

In addition to the Utilities' sites discussed under “PEC” and “PEF” below, we incurred indemnity obligations related to certain pre-closing liabilities of divested subsidiaries, including certain environmental matters (See discussion under Guarantees in Note 14B).

PEC

PEC has recorded a minimum estimated total remediation cost for its remaining MGP site based upon its historical experience with remediation of several of its MGP sites. Remediation of PEC's other MGP sites has been substantially completed.The maximum amount of the range for all of PEC's environmental sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future.

In 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, N.C. (Ward) site. The EPA offered PEC and a number of other PRPs the opportunity to negotiate the removal action for the Ward site and reimbursement to the EPA for the EPA's past expenditures in addressing conditions at the Ward site. Subsequently, PEC and other PRPs signed a settlement agreement, which requires the participating PRPs to remediate the Ward site. At March 31, 2012 and December 31, 2011, PEC's recorded liability for the site was approximately $5 million. In 2008 and 2009, PEC filed civil actions against non-participating PRPs seeking contribution for and recovery of costs incurred in remediating the Ward site, as well as a declaratory judgment that defendants are jointly and severally liable for response costs at the site. PEC has settled with a number of the PRPs and is in active settlement negotiations with others. In March 2010, the federal district court in which this matter is pending denied motions to dismiss filed by a number of defendants, but granted several other motions filed by state agencies and successor entities. The court established a “test case” programproviding for a determination of liability on the part of a set of representative defendants. Summary judgment motions and responsive pleadings are being filed by and against these defendants and discovery and briefing are expected to be completed by May 2012. Meanwhile, proceedings with respect to the other defendants have been stayed. The outcome of these matters cannot be predicted.

In 2008, the EPA issued a Record of Decision for the operable unit for stream segments downstream from the Ward site (Ward OU1) and advised 61 parties, including PEC, of their identification as PRPs for Ward OU1 and for further investigation at the Ward facility and certain adjacent areas (Ward OU2). The EPA's estimate for the selected remedy for Ward OU1 is approximately $6 million. The EPA offered PEC and the other PRPs the opportunity to negotiate implementation of a response action for Ward OU1 and a remedial investigation and feasibility study for Ward OU2, as well as reimbursement to the EPA of approximately $1 million for the EPA's past expenditures in addressing conditions at the site. In September 2011, the EPA issued unilateral administrative orders to certain parties, which did not include PEC, directing the performance of remedial activities with regard to Ward OU1. It is not possible at this time to reasonably estimate the total amount of PEC's obligation, if any, for Ward OU1 and Ward OU2.

B.       AIR AND WATER QUALITY

We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations governing air and water quality, which likely would result in increased capital expenditures and O&M expense. Control equipment installed for compliance with then-existing or proposed laws and regulations may address some of the issues outlined. PEC and PEF have been developing an integrated compliance strategy to meet these evolving requirements. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the North Carolina Clean Smokestacks Act (Clean Smokestacks Act). The air quality controls installed to comply with nitrogen oxides (NOx)and sulfur dioxide (SO2) requirements under certain sections of the Clean Air Act(CAA) and the Clean Smokestacks Act, as well as PEC's plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address theCAIR requirements for NOx and SO2for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of CAIR.

After prior mercury regulation was vacated in federal court, the EPA developed maximum achievable control technology (MACT) standards. The Mercury and Air Toxics Standards (MATS), which are the final MACT standards for coal-fired and oil-fired electric steam generating units,became effective on April 16, 2012. Compliance is due in three years with provisions for a one-year extension from state agencies on a case-by-case basis. The MATS contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units.Several petitions regarding portions of the MATS rule have been filed in the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals), including one by the Utility Air Regulatory Group, of which Progress Energy is a member. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. Due to significant investments in NOx and SO2 emission controls and fleet modernization projects completed or under way, we believe PEC is relatively well positioned to comply with the MATS. However, PEF will be required to complete additional emissions controls and/or fleet modernization projects in order to meet the compliance timeframe for the MATS. On March 29, 2012, PEF announced plans to convert Anclote to 100 percent natural gas, which will substantially reduce emissions, as part of its MATS compliance strategy. We are continuing to evaluate the impacts of the MATSon the Utilities. We anticipate that compliance with the MATS will satisfy the North Carolina mercury rule requirements for PEC. The outcome of these matters cannot be predicted.

The CAIR, issued by the EPA, required the District of Columbia and 28 states, including North Carolina, South Carolina and Florida, to reduce NOx and SO2 emissions. The CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for NOx and beginning in 2010 and 2015, respectively, for SO2.States were required to adopt rules implementing the CAIR, and the EPA approved the North Carolina CAIR, the South Carolina CAIR and the Florida CAIR. A 2008 decision by the D.C. Court of Appeals remanded the CAIR without vacating it for the EPA to conduct further proceedings.

On July 7, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR)to replace the CAIR. The CSAPR, which was scheduled to take effect on January 1, 2012, contains new emissions trading programs for NOx and SO2 emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. A number of parties, including groups of which PEC and PEF are members, filed petitions for reconsideration and stay of, as well as legal challenges to, the CSAPR. On December 30, 2011, the D.C. Court of Appeals issued an order staying the implementation of the CSAPR, pending a decision by the court resolving the challenges to the rule. Oral argument for the CSAPR litigation occurred on April 13, 2012. As a result of the stay of CSAPR, the CAIR continues to remain in effect.The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO2 Group 1 trading program and the SO2 Group 2 trading program. If the CSAPR is upheld, North Carolina and South Carolina are included in the NOx and SO2 annual trading programs, as well as the NOx ozone season trading program. North Carolina remains classified as a Group 1 state, which will require additional NOx and SO2 emission reductions beginning in January 2014. South Carolina remains classified as a Group 2 state with no additional reductions required in 2014. Under the CSAPR, Florida is subject only to the NOx ozone season trading program. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe PEC and PEF are positioned to comply with the CSAPR without the need for significant capital expenditures. We cannot predict the outcome of this matter.

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at CR4 and CR5, which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire Crystal RiverUnits 1 and 2 (CR1 and CR2) as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 are scheduled to be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was originally anticipated to be around 2020. As discussed in Note 5B, major construction activities for Levy are being postponed, and the in-service date for the first Levy unit has been shifted to 2024. As required, PEF will continue to advise the FDEP of these developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF's compliance with environmental regulations. We cannot predict the outcome of this matter.

As previously discussed, the CSAPR establishes new NOx annual and seasonal ozone programs and a new SO2 trading program. NOx and SO2 emission allowances applicable to the current CAIR cannot be used to satisfy the new CSAPR programs. SO2 emission allowances will be utilized by the Utilities to comply with existing CAA requirements. NOx allowances cannot be utilized to comply with other requirements. As a result of the previously discussed D.C. Court of Appeals order staying the implementation of the CSAPR, the CAIR emission allowance program remains in effect. Emission allowances are included on the Balance Sheets in inventory and in other assets and deferred debits and have not changed materially from what was reported in the 2011 Form 10-K.

PEF

Enviromental Matters Disclosure [Line Items]

Environmental Matters

13.ENVIRONMENTAL MATTERS

We are subject to regulation by various federal, state and local authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. We believe that we are in substantial compliance with those environmental regulations currently applicable to our business and operations and believe we have all necessary permits to conduct such operations. Environmental laws and regulations frequently change and the ultimate costs of compliance cannot always be precisely estimated.

A.       HAZARDOUS AND SOLID WASTE

The U.S. Environmental Protection Agency (EPA) and a number of states are considering additional regulatory measures that may affect management, treatment, marketing and disposal of coal combustion residues, primarily ash, from each of the Utilities' coal-fired plants. Revised or new laws or regulations under consideration may impose changes in solid waste classifications or groundwater protection environmental controls. In June 2010, the EPA proposed two options for new rules to regulate coal combustion residues. The first option would create a comprehensive program of federally enforceable requirements for coal combustion residues management and disposal under federal hazardous waste rules. The other option would have the EPA set design and performance standards for coal combustion residues management facilities and regulate disposal of coal combustion residues as nonhazardous waste with enforcement by the courts or state laws. The EPA did not identify a preferred option. Under both options, the EPA may leave in place a regulatory exemption for approved beneficial uses of coal combustion residuals that are recycled. A final rule is expected in late 2012. There are federal legislative proposals that may direct the EPA to regulate coal combustion residues destined for disposal as non-hazardous wastes. Environmental groups filed a lawsuit on April 5, 2012, in the U.S. District Court for the District of Columbia to require the EPA to complete its rulemaking process and finalize new regulations for the storage, transportation and disposal of coal combustion residues. Compliance plans and estimated costs to meet the requirements of new regulations or statutes will be determined when any new regulations are finalized. We are also evaluating the effect on groundwater quality from past and current operations, which may result in operational changes and additional measures under existing regulations. These issues are also under evaluation by state agencies. Certain regulated chemicals have been measured in wells near our ash ponds at levels above groundwater quality standards. Additional monitoring and investigation will be conducted. Detailed plans and cost estimates will be determined if these evaluations reveal that corrective actions are necessary. We cannot predict the outcome of this matter.

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liability. Some states, including North Carolina, South Carolina and Florida, have similar types of statutes. 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 of our potential liability by the EPA, the state of North Carolina, the state of Florida, or potentially responsible party (PRP) groups 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 PRPs at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. These costs are eligible for regulatory recovery through either base rates or cost-recovery clauses. Both PEC and PEF evaluate potential claims against other PRPs and insurance carriers and plan to submit claims for cost recovery where appropriate. The outcome of potential and pending claims cannot be predicted.

We measure our liability for environmental 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 in O&M expense on the Statements of Comprehensive Income 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. It is probable that current estimates will change and additional losses, which could be material, may be incurred in the future.

The following tables contain information about accruals for probable and estimable costs related to various environmental sites, which were included in other current liabilities and other liabilities and deferred credits on the Balance Sheets:

PEF
(in millions)		MGP and Other Sites		Remediation of Distribution and Substation Transformers		Total
Balance, December 31, 2011		$	6	$	6	$	12
Amount accrued for environmental loss contingencies			4		2		6
Expenditures for environmental loss contingencies			(1)		(2)		(3)
Balance, March 31, 2012(a)		$	9	$	6	$	15
Balance, December 31, 2010		$	8	$	15	$	23
Amount accrued for environmental loss contingencies			-		-		-
Expenditures for environmental loss contingencies			(1)		(5)		(6)
Balance, March 31, 2011(a)		$	7	$	10	$	17
(a)	Expected to be paid out over one to 12 years.

PROGRESS ENERGY

In addition to the Utilities' sites discussed under “PEC” and “PEF” below, we incurred indemnity obligations related to certain pre-closing liabilities of divested subsidiaries, including certain environmental matters (See discussion under Guarantees in Note 14B).

PEF

The accruals for PEF's MGP and other sites relate to two former MGP sites and other sites associated with PEF that have required, or are anticipated to require, investigation and/or remediation. Remediation of one MGP site has been substantially completed. At March 31, 2012, PEF's accrual primarily relates to a MGP site located in Orlando, Fla. The PRP group for the Orlando MGP site has agreed to an interim allocation for the Orlando MGP site and is conducting a feasibility study for remediation of soil and groundwater down to 50 feet, which has not been completed. The study preliminarily indicates a range of viable remedial approaches, and agreement has not been reached on the remediation approach. During the quarter ended March 31, 2012, one participating PRP ended its participation in the PRP group. The PRP allocations have been adjusted accordingly. The PRP group for the Orlando MGP site intends to seek recovery from the non-participating PRP, but no amount for recovery has been recorded. PEF has accrued its best estimate of its obligation with respect to the Orlando MGP site. Based on current estimates for the range of viable remedial approaches and its current allocation share, PEF could incur additional obligations of up to approximately $4 million for remediation of soil and groundwater down to 50 feet. Results of an investigative study revealed the presence of MGP byproduct material below 200 feet from the surface. The layer between approximately 50 feet and 200 feet below the surface, which is clay, is not impacted. The maximum amount of the range for remediation, if any, below 200 feet at the Orlando MGP site and for PEF's other sites cannot be determined at this time. Actual experience may differ from current estimates, and it is probable that estimates will continue to change in the future. We cannot predict the outcome of this matter.

PEF has received approval from the FPSC for recovery through the ECRC of the majority of costs associated with the remediation of distribution and substation transformers. Under agreements with the Florida Department of Environmental Protection (FDEP), PEF has reviewed all distribution transformer sites and all substation sites for mineral oil-impacted soil caused by equipment integrity issues. Should additional distribution transformer sites be identified outside of this population, the distribution O&M expense will not be recoverable through the ECRC.

B.       AIR AND WATER QUALITY

We are, or may ultimately be, subject to various current and proposed federal, state and local environmental compliance laws and regulations governing air and water quality, which likely would result in increased capital expenditures and O&M expense. Control equipment installed for compliance with then-existing or proposed laws and regulations may address some of the issues outlined. PEC and PEF have been developing an integrated compliance strategy to meet these evolving requirements. PEC has installed environmental compliance controls that meet the emission reduction requirements under the first phase of the North Carolina Clean Smokestacks Act (Clean Smokestacks Act). The air quality controls installed to comply with nitrogen oxides (NOx)and sulfur dioxide (SO2) requirements under certain sections of the Clean Air Act(CAA) and the Clean Smokestacks Act, as well as PEC's plan to replace a portion of its coal-fired generation with natural gas-fueled generation, largely address theCAIR requirements for NOx and SO2for our North Carolina units at PEC. PEF has installed environmental compliance controls that meet the emission reduction requirements under the first phase of CAIR.

After prior mercury regulation was vacated in federal court, the EPA developed maximum achievable control technology (MACT) standards. The Mercury and Air Toxics Standards (MATS), which are the final MACT standards for coal-fired and oil-fired electric steam generating units,became effective on April 16, 2012. Compliance is due in three years with provisions for a one-year extension from state agencies on a case-by-case basis. The MATS contains stringent emission limits for mercury, non-mercury metals, and acid gases from coal-fired units and hazardous air pollutant metals, acid gases, and hydrogen fluoride from oil-fired units.Several petitions regarding portions of the MATS rule have been filed in the U.S. Court of Appeals for the District of Columbia (D.C. Court of Appeals), including one by the Utility Air Regulatory Group, of which Progress Energy is a member. The North Carolina mercury rule contains a requirement that all coal-fired units in the state install mercury controls by December 31, 2017, and requires compliance plan applications to be submitted in 2013. Due to significant investments in NOx and SO2 emission controls and fleet modernization projects completed or under way, we believe PEC is relatively well positioned to comply with the MATS. However, PEF will be required to complete additional emissions controls and/or fleet modernization projects in order to meet the compliance timeframe for the MATS. On March 29, 2012, PEF announced plans to convert Anclote to 100 percent natural gas, which will substantially reduce emissions, as part of its MATS compliance strategy. We are continuing to evaluate the impacts of the MATSon the Utilities. We anticipate that compliance with the MATS will satisfy the North Carolina mercury rule requirements for PEC. The outcome of these matters cannot be predicted.

The CAIR, issued by the EPA, required the District of Columbia and 28 states, including North Carolina, South Carolina and Florida, to reduce NOx and SO2 emissions. The CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for NOx and beginning in 2010 and 2015, respectively, for SO2.States were required to adopt rules implementing the CAIR, and the EPA approved the North Carolina CAIR, the South Carolina CAIR and the Florida CAIR. A 2008 decision by the D.C. Court of Appeals remanded the CAIR without vacating it for the EPA to conduct further proceedings.

On July 7, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR)to replace the CAIR. The CSAPR, which was scheduled to take effect on January 1, 2012, contains new emissions trading programs for NOx and SO2 emissions as well as more stringent overall emissions targets in 27 states, including North Carolina, South Carolina and Florida. A number of parties, including groups of which PEC and PEF are members, filed petitions for reconsideration and stay of, as well as legal challenges to, the CSAPR. On December 30, 2011, the D.C. Court of Appeals issued an order staying the implementation of the CSAPR, pending a decision by the court resolving the challenges to the rule. Oral argument for the CSAPR litigation occurred on April 13, 2012. As a result of the stay of CSAPR, the CAIR continues to remain in effect.The EPA issued the CSAPR as four separate programs, including the NOx annual trading program, the NOx ozone season trading program, the SO2 Group 1 trading program and the SO2 Group 2 trading program. If the CSAPR is upheld, North Carolina and South Carolina are included in the NOx and SO2 annual trading programs, as well as the NOx ozone season trading program. North Carolina remains classified as a Group 1 state, which will require additional NOx and SO2 emission reductions beginning in January 2014. South Carolina remains classified as a Group 2 state with no additional reductions required in 2014. Under the CSAPR, Florida is subject only to the NOx ozone season trading program. Due to significant investments in NOx and SO2 emissions controls and fleet modernization projects completed or under way, we believe PEC and PEF are positioned to comply with the CSAPR without the need for significant capital expenditures. We cannot predict the outcome of this matter.

To date, expenditures at PEF for CAIR regulation primarily relate to environmental compliance projects at CR4 and CR5, which have both been completed and placed in service. Under an agreement with the FDEP, PEF will retire Crystal RiverUnits 1 and 2 (CR1 and CR2) as coal-fired units and operate emission control equipment at CR4 and CR5. CR1 and CR2 are scheduled to be retired after the second proposed nuclear unit at Levy completes its first fuel cycle, which was originally anticipated to be around 2020. As discussed in Note 5B, major construction activities for Levy are being postponed, and the in-service date for the first Levy unit has been shifted to 2024. As required, PEF will continue to advise the FDEP of these developments that will delay the retirement of CR1 and CR2 beyond the originally anticipated date. We are currently evaluating the impacts of the Levy schedule on PEF's compliance with environmental regulations. We cannot predict the outcome of this matter.

As previously discussed, the CSAPR establishes new NOx annual and seasonal ozone programs and a new SO2 trading program. NOx and SO2 emission allowances applicable to the current CAIR cannot be used to satisfy the new CSAPR programs. SO2 emission allowances will be utilized by the Utilities to comply with existing CAA requirements. NOx allowances cannot be utilized to comply with other requirements. As a result of the previously discussed D.C. Court of Appeals order staying the implementation of the CSAPR, the CAIR emission allowance program remains in effect. Emission allowances are included on the Balance Sheets in inventory and in other assets and deferred debits and have not changed materially from what was reported in the 2011 Form 10-K.

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Unaudited Condensed Consolidated Balance Sheets (Parentheticals)	Mar. 31, 2012	Dec. 31, 2011
Balance Sheets Parentheticals [Line Items]
Common shares, authorized	500,000,000	500,000,000
Common shares, issued	296,000,000	295,000,000
Common shares, outstanding	296,000,000	295,000,000
PEC
Balance Sheets Parentheticals [Line Items]
Common shares, authorized	200,000,000	200,000,000
Common shares, issued	160,000,000	160,000,000
Common shares, outstanding	160,000,000	160,000,000
PEF
Balance Sheets Parentheticals [Line Items]
Common shares, authorized	60,000,000	60,000,000
Common shares, issued	100	100
Common shares, outstanding	100	100

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Preferred Stock of Subsidiaries

3 Months Ended

Mar. 31, 2012

Preferred Stock Of Subsidiaries Disclosure [Line Items]

Preferred Stock

7.       PREFERREDSTOCK OF SUBSIDIARIES

All of our preferred stock was issued by the Utilities. The preferred stock is considered temporary equity due to certain provisions that could require us to redeem the preferred stock for cash. In the event dividends payable on PEC or PEF preferred stock are in default for an amount equivalent to or exceeding four quarterly dividend payments, the holders of the preferred stock are entitled to elect a majority of PEC's or PEF's respective board of directors until all accrued and unpaid dividends are paid. All classes of preferred stock are entitled to cumulative dividends with preference to the common stock dividends, are redeemable by vote of the Utilities' respective board of directors at any time, and do not have any preemptive rights. All classes of preferred stock have a liquidation preference equal to $100 per share plus any accumulated unpaid dividends except for PEF's 4.75%, $100 par value class, which does not have a liquidation preference. Each holder of PEC's preferred stock is entitled to one vote. The holders of PEF's preferred stock have no right to vote except for certain circumstances involving dividends payable on preferred stock that are in default or certain matters affecting the rights and preferences of the preferred stock.

PEC

Preferred Stock Of Subsidiaries Disclosure [Line Items]

Preferred Stock

7.       PREFERREDSTOCK OF SUBSIDIARIES

All of our preferred stock was issued by the Utilities. The preferred stock is considered temporary equity due to certain provisions that could require us to redeem the preferred stock for cash. In the event dividends payable on PEC or PEF preferred stock are in default for an amount equivalent to or exceeding four quarterly dividend payments, the holders of the preferred stock are entitled to elect a majority of PEC's or PEF's respective board of directors until all accrued and unpaid dividends are paid. All classes of preferred stock are entitled to cumulative dividends with preference to the common stock dividends, are redeemable by vote of the Utilities' respective board of directors at any time, and do not have any preemptive rights. All classes of preferred stock have a liquidation preference equal to $100 per share plus any accumulated unpaid dividends except for PEF's 4.75%, $100 par value class, which does not have a liquidation preference. Each holder of PEC's preferred stock is entitled to one vote. The holders of PEF's preferred stock have no right to vote except for certain circumstances involving dividends payable on preferred stock that are in default or certain matters affecting the rights and preferences of the preferred stock.

PEF

Preferred Stock Of Subsidiaries Disclosure [Line Items]

Preferred Stock

7.       PREFERREDSTOCK OF SUBSIDIARIES

All of our preferred stock was issued by the Utilities. The preferred stock is considered temporary equity due to certain provisions that could require us to redeem the preferred stock for cash. In the event dividends payable on PEC or PEF preferred stock are in default for an amount equivalent to or exceeding four quarterly dividend payments, the holders of the preferred stock are entitled to elect a majority of PEC's or PEF's respective board of directors until all accrued and unpaid dividends are paid. All classes of preferred stock are entitled to cumulative dividends with preference to the common stock dividends, are redeemable by vote of the Utilities' respective board of directors at any time, and do not have any preemptive rights. All classes of preferred stock have a liquidation preference equal to $100 per share plus any accumulated unpaid dividends except for PEF's 4.75%, $100 par value class, which does not have a liquidation preference. Each holder of PEC's preferred stock is entitled to one vote. The holders of PEF's preferred stock have no right to vote except for certain circumstances involving dividends payable on preferred stock that are in default or certain matters affecting the rights and preferences of the preferred stock.

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Equity

3 Months Ended

Mar. 31, 2012

Equity And Comprehensive Income Disclosure [Line Items]

Equity

6.EQUITY

A.EARNINGS PER COMMON SHARE

There are no material differences between our basic and diluted earnings per share amounts or our basic and diluted weighted-average number of common shares outstanding for the three months ended March 31, 2012 and 2011. The effects of performance share awards and stock options outstanding on diluted earnings per share are immaterial.

B.       RECONCILIATION OF TOTAL EQUITY

PROGRESS ENERGY

The consolidated financial statements include the accounts of the Parent and its majority owned subsidiaries. Noncontrolling interests principally represent minority shareholders' proportionate share of the equity of a subsidiary and aVIE (See Note 1C).

The following table presents changes in total equity for the year to date:

(in millions)		Total Common Stock Equity		Noncontrolling Interests		Total Equity
Balance, December 31, 2011		$	10,021	$	4	$	10,025
Net income(a)			150		0		150
Other comprehensive income			5		0		5
Issuance of shares through offerings and stock- based compensation plans (See Note 6C)			17		0		17
Dividends declared			(184)		0		(184)
Distributions to noncontrolling interests			0		(2)		(2)
Balance, March 31, 2012		$	10,009	$	2	$	10,011
Balance, December 31, 2010		$	10,023	$	4	$	10,027
Net income(a)			184		(1)		183
Other comprehensive income			4		0		4
Issuance of shares through offerings and stock- based compensation plans (See Note 6C)			19		0		19
Dividends declared			(183)		0		(183)
Distributions to noncontrolling interests			0		(2)		(2)
Other			0		2		2
Balance, March 31, 2011		$	10,047	$	3	$	10,050
(a)	For the three months ended March 31, 2012, consolidated net income of $152 million includes $2 million attributable to preferred shareholders of subsidiaries. For the three months ended March 31, 2011, consolidated net income of $185 million includes $2 million attributable to preferred shareholders of subsidiaries. Income attributable to preferred shareholders of subsidiaries is not a component of total equity and is excluded from the table above.

PEC

Interim disclosures of changes in equity are required if the reporting entity has less than wholly-owned subsidiaries, of which PEC has none. Therefore, an equity reconciliation for PEC has not been provided.

PEF

Interim disclosures of changes in equity are required if the reporting entity has less than wholly-owned subsidiaries, of which PEF has none. Therefore, an equity reconciliation for PEF has not been provided.

C.       COMMON STOCK

At March 31, 2012 and December 31, 2011, we had 500 million shares of common stock authorized under our charter, of which 296 million and 295million shares were outstanding, respectively.We periodically issue shares of common stockthrough the Progress Energy Investor Plus Plan (IPP), equity incentive plans and other benefit plans.

The following table presents information for our common stock issuances:

	Three months ended March 31
	2012			2011
(in millions)	Shares		Net Proceeds	Shares		Net Proceeds
Total issuances	0.8	$	3	1.0	$	8
Issuances through IPP	-		-	-		1

PEC

Equity And Comprehensive Income Disclosure [Line Items]

Equity

6.EQUITY

B.       RECONCILIATION OF TOTAL EQUITY

PEC

Interim disclosures of changes in equity are required if the reporting entity has less than wholly-owned subsidiaries, of which PEC has none. Therefore, an equity reconciliation for PEC has not been provided.

PEF

Equity And Comprehensive Income Disclosure [Line Items]

Equity

6.EQUITY

B.       RECONCILIATION OF TOTAL EQUITY

PEF

Interim disclosures of changes in equity are required if the reporting entity has less than wholly-owned subsidiaries, of which PEF has none. Therefore, an equity reconciliation for PEF has not been provided.

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Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2012

Regulatory Matters Disclosure [Abstract]

Schedule of extended outage repair and replacement power costs and recoveries

(in millions)			Replacement Power Costs		Repair Costs
Spent to date			$	506	$	279
NEIL proceeds received to date				(162)		(143)
Insurance receivable at March 31, 2012, net				(55)		0
	Balance for recovery(a)		$	289	$	136
(a)		See "2012 Settlement Agreement" below for discussion of PEF's ability to recover prudently incurred fuel and purchased power costs and CR3 repair costs.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2012

Commitments And Contingencies Disclosure [Line Items]

Commitments and Contingencies

14.COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 22 in the 2011 Form 10-K are described below.

A.PURCHASE OBLIGATIONS

As part of our ordinary course of business, we and the Utilities enter into various long- and short-term contracts for fuel requirements at our generating plants. Significant changes from the commitment amounts reported in Note 22A in the 2011 Form 10-K can result from new contracts, changes in existing contracts along with the impact of fluctuations in current estimates of future market prices for those contracts that are market price indexed. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels, and other financial commitments. Additional commitments for fuel and related transportation will be required to supply the Utilities' future needs. At March 31, 2012, our and the Utilities' contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2011 Form 10-K.

B.       GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties. Such agreements include guarantees, standby letters of credit and surety bonds. At March 31, 2012, 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.

At March 31, 2012, we have issued guarantees and indemnifications of and for certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses. At March 31, 2012, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $234 million, including $59 million at PEF. Related to the sales of businesses, the latest specified notice period extends until 2013 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For certain matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications related to discontinued operations have no limitations as to time or maximum potential future payments. At March 31, 2012 and December 31, 2011, we had recorded liabilities related to guarantees and indemnifications to third parties of $43 million and $63 million, respectively. These amounts included $35 million and $37 million for PEF at March 31, 2012 and December 31, 2011, respectively. Our liabilities decreased primarily due to the reversal of certain environmental indemnification liabilities for which the indemnification period has expired (See Note 4). During the three months ended March 31, 2012, our and the Utilities' accruals and expendituresrelated to guarantees and indemnifications were not material. As current estimates change, it is possible that additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

In addition, the Parent has issued $300 million in guarantees for certain payments of two wholly owned indirect subsidiaries (See Note 15).

C.        OTHER COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL

We are subject to federal, state and local regulations regarding environmental matters (See Note 13).

Hurricane Katrina

In May 2011, PEC and PEF were named in a class action lawsuit filed in the U.S. District Court for the Southern District of Mississippi. Plaintiffs claimed that PEC and PEF, along with numerous other utility, oil, coal and chemical companies, were liable for damages relating to losses suffered by victims of Hurricane Katrina as a result of their contributions of greenhouse gas emissions to the frequency and intensity of storms such as Hurricane Katrina. On March 20, 2012, the federal district court dismissed the class action lawsuit.On April 16, 2012, the plaintiffs filed a notice of appeal of this decision with the United States Court of Appeals for the Fifth Circuit. We believe the plaintiff's claim is without merit; however, we cannot predict the outcome of this matter.

Water Discharge Permit

In October 2011, Earthjustice, on behalf of the Sierra Club and Florida Wildlife Federation, filed a petition seeking review of the water discharge permit issued to CR1, CR2 and CR3 raising a number of technical and legal issues with respect to the permit. In March 2012, a settlement was reached providing for the withdrawal of the petition and issuance by the FDEP of a revised water discharge permit identical in form to the one under appeal but with an 18-month term rather than the standard five-year term. The settlement fully resolved the current dispute.

SPENT NUCLEAR FUEL MATTERS

Pursuant to the Nuclear Waste Policy Act of 1982, 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 for Disposal of Spent Nuclear Fuel.

The DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, the Utilities filed a complaint in the U.S. Court of Federal Claims against the DOE, claiming that the DOE breached the standard contract and asserting damages incurred through 2005.In2011, the judge in the U.S. Court of Federal Claims issued a ruling to award PEC substantially all their asserted damages. As a result, PEC recorded the award as an offset for past spent fuel storage costs incurred.

On December 12, 2011, the Utilities filed another complaint in the U.S. Court of Federal Claims against the DOE, claiming damages incurred from January 1, 2006, through December 31, 2010. The damages stem from the same breach of contract asserted in the previous litigation. On March 23, 2012, the Utilities filed their initial disclosure of damages with the U.S. Court of Federal Claims and the DOE. The Utilities may file subsequent damage claims as they incur additional costs. We cannot predict the outcome of this matter.

SYNTHETIC FUELS MATTERS

In October 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates arising out of an Asset Purchase Agreement dated as of October 19, 1999, and amended as of August 23, 2000, (the Asset Purchase Agreement) by and among U.S. Global, LLC (Global); Earthco synthetic fuels facilities (Earthco); certain affiliates of Earthco; EFC Synfuel LLC (which was owned indirectly by Progress Energy, Inc.) and certain of its affiliates, including Solid Energy LLC; Solid Fuel LLC; Ceredo Synfuel LLC; Gulf Coast Synfuel LLC (renamed Sandy River Synfuel LLC) (collectively, the Progress Affiliates), as amended by an amendment to the Asset Purchase Agreement. In a case filed in the Circuit Court for Broward County, Fla., in March 2003 (the Florida Global Case), Global requested an unspecified amount of compensatory damages, as well as declaratory relief. Global asserted (1) that pursuant to the Asset Purchase Agreement, it was entitled to an interest in two synthetic fuels facilities previously owned by the Progress Affiliates and an option to purchase additional interests in the two synthetic fuels facilities and (2) that it was entitled to damages because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuels facilities. As a result of the 2007 expiration of the Internal Revenue Code Section 29 tax credit program, all of our synthetic fuels businesses were abandoned and we reclassified our synthetic fuels businesses as discontinued operations.

The jury awarded Global $78 million. In November 2009, the court assessed $55 million in prejudgment interest and entered judgment in favor of Global in a total amount of $133 million. During the year ended December 31, 2009, we recorded an after-tax charge of $74 million to discontinued operations. In December 2009, we appealed the Broward County judgment to the Florida Fourth District Court of Appeals. Also in December 2009, we made a $154 million payment, which represents payment of the total judgment and a required premium equivalent to two years of interest, to the Broward County Clerk of Court bond account. The appellate briefing process has been completed. Oral argument was held on September 27, 2011. We cannot predict the outcome of this matter.

In a second suit filed in the Superior Court for Wake County, N.C., Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC (the North Carolina Global Case), the Progress Affiliates seek declaratory relief consistent with our interpretation of the Asset Purchase Agreement. Global was served with the North Carolina Global Case on April17, 2003.In May 2003, Global moved to dismiss the North Carolina Global Case for lack of personal jurisdiction over Global. In the alternative, Global requested that the court decline to exercise its discretion to hear the Progress Affiliates' declaratory judgment action. In August 2003, the Wake County Superior Court denied Global's motion to dismiss, but stayed the North Carolina Global Case, pending the outcome of the Florida Global Case. The Progress Affiliates appealed the superior court's order staying the case. By order dated September 7, 2004, the North Carolina Court of Appeals dismissed the Progress Affiliates' appeal. Based upon the verdict in the Florida Global Case, we anticipate dismissal of the North Carolina Global Case.

OTHER LITIGATION MATTERS

We and our subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

PEC

Commitments And Contingencies Disclosure [Line Items]

Commitments and Contingencies

14.COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 22 in the 2011 Form 10-K are described below.

A.PURCHASE OBLIGATIONS

As part of our ordinary course of business, we and the Utilities enter into various long- and short-term contracts for fuel requirements at our generating plants. Significant changes from the commitment amounts reported in Note 22A in the 2011 Form 10-K can result from new contracts, changes in existing contracts along with the impact of fluctuations in current estimates of future market prices for those contracts that are market price indexed. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels, and other financial commitments. Additional commitments for fuel and related transportation will be required to supply the Utilities' future needs. At March 31, 2012, our and the Utilities' contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2011 Form 10-K.

B.       GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties. Such agreements include guarantees, standby letters of credit and surety bonds. At March 31, 2012, 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.

At March 31, 2012, we have issued guarantees and indemnifications of and for certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses. At March 31, 2012, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $234 million, including $59 million at PEF. Related to the sales of businesses, the latest specified notice period extends until 2013 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For certain matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications related to discontinued operations have no limitations as to time or maximum potential future payments. At March 31, 2012 and December 31, 2011, we had recorded liabilities related to guarantees and indemnifications to third parties of $43 million and $63 million, respectively. These amounts included $35 million and $37 million for PEF at March 31, 2012 and December 31, 2011, respectively. Our liabilities decreased primarily due to the reversal of certain environmental indemnification liabilities for which the indemnification period has expired (See Note 4). During the three months ended March 31, 2012, our and the Utilities' accruals and expendituresrelated to guarantees and indemnifications were not material. As current estimates change, it is possible that additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

In addition, the Parent has issued $300 million in guarantees for certain payments of two wholly owned indirect subsidiaries (See Note 15).

C.        OTHER COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL

We are subject to federal, state and local regulations regarding environmental matters (See Note 13).

Hurricane Katrina

In May 2011, PEC and PEF were named in a class action lawsuit filed in the U.S. District Court for the Southern District of Mississippi. Plaintiffs claimed that PEC and PEF, along with numerous other utility, oil, coal and chemical companies, were liable for damages relating to losses suffered by victims of Hurricane Katrina as a result of their contributions of greenhouse gas emissions to the frequency and intensity of storms such as Hurricane Katrina. On March 20, 2012, the federal district court dismissed the class action lawsuit.On April 16, 2012, the plaintiffs filed a notice of appeal of this decision with the United States Court of Appeals for the Fifth Circuit. We believe the plaintiff's claim is without merit; however, we cannot predict the outcome of this matter.

Water Discharge Permit

In October 2011, Earthjustice, on behalf of the Sierra Club and Florida Wildlife Federation, filed a petition seeking review of the water discharge permit issued to CR1, CR2 and CR3 raising a number of technical and legal issues with respect to the permit. In March 2012, a settlement was reached providing for the withdrawal of the petition and issuance by the FDEP of a revised water discharge permit identical in form to the one under appeal but with an 18-month term rather than the standard five-year term. The settlement fully resolved the current dispute.

SPENT NUCLEAR FUEL MATTERS

Pursuant to the Nuclear Waste Policy Act of 1982, 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 for Disposal of Spent Nuclear Fuel.

The DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, the Utilities filed a complaint in the U.S. Court of Federal Claims against the DOE, claiming that the DOE breached the standard contract and asserting damages incurred through 2005.In2011, the judge in the U.S. Court of Federal Claims issued a ruling to award PEC substantially all their asserted damages. As a result, PEC recorded the award as an offset for past spent fuel storage costs incurred.

On December 12, 2011, the Utilities filed another complaint in the U.S. Court of Federal Claims against the DOE, claiming damages incurred from January 1, 2006, through December 31, 2010. The damages stem from the same breach of contract asserted in the previous litigation. On March 23, 2012, the Utilities filed their initial disclosure of damages with the U.S. Court of Federal Claims and the DOE. The Utilities may file subsequent damage claims as they incur additional costs. We cannot predict the outcome of this matter.

SYNTHETIC FUELS MATTERS

In October 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates arising out of an Asset Purchase Agreement dated as of October 19, 1999, and amended as of August 23, 2000, (the Asset Purchase Agreement) by and among U.S. Global, LLC (Global); Earthco synthetic fuels facilities (Earthco); certain affiliates of Earthco; EFC Synfuel LLC (which was owned indirectly by Progress Energy, Inc.) and certain of its affiliates, including Solid Energy LLC; Solid Fuel LLC; Ceredo Synfuel LLC; Gulf Coast Synfuel LLC (renamed Sandy River Synfuel LLC) (collectively, the Progress Affiliates), as amended by an amendment to the Asset Purchase Agreement. In a case filed in the Circuit Court for Broward County, Fla., in March 2003 (the Florida Global Case), Global requested an unspecified amount of compensatory damages, as well as declaratory relief. Global asserted (1) that pursuant to the Asset Purchase Agreement, it was entitled to an interest in two synthetic fuels facilities previously owned by the Progress Affiliates and an option to purchase additional interests in the two synthetic fuels facilities and (2) that it was entitled to damages because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuels facilities. As a result of the 2007 expiration of the Internal Revenue Code Section 29 tax credit program, all of our synthetic fuels businesses were abandoned and we reclassified our synthetic fuels businesses as discontinued operations.

The jury awarded Global $78 million. In November 2009, the court assessed $55 million in prejudgment interest and entered judgment in favor of Global in a total amount of $133 million. During the year ended December 31, 2009, we recorded an after-tax charge of $74 million to discontinued operations. In December 2009, we appealed the Broward County judgment to the Florida Fourth District Court of Appeals. Also in December 2009, we made a $154 million payment, which represents payment of the total judgment and a required premium equivalent to two years of interest, to the Broward County Clerk of Court bond account. The appellate briefing process has been completed. Oral argument was held on September 27, 2011. We cannot predict the outcome of this matter.

In a second suit filed in the Superior Court for Wake County, N.C., Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC (the North Carolina Global Case), the Progress Affiliates seek declaratory relief consistent with our interpretation of the Asset Purchase Agreement. Global was served with the North Carolina Global Case on April17, 2003.In May 2003, Global moved to dismiss the North Carolina Global Case for lack of personal jurisdiction over Global. In the alternative, Global requested that the court decline to exercise its discretion to hear the Progress Affiliates' declaratory judgment action. In August 2003, the Wake County Superior Court denied Global's motion to dismiss, but stayed the North Carolina Global Case, pending the outcome of the Florida Global Case. The Progress Affiliates appealed the superior court's order staying the case. By order dated September 7, 2004, the North Carolina Court of Appeals dismissed the Progress Affiliates' appeal. Based upon the verdict in the Florida Global Case, we anticipate dismissal of the North Carolina Global Case.

OTHER LITIGATION MATTERS

We and our subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

PEF

Commitments And Contingencies Disclosure [Line Items]

Commitments and Contingencies

14.COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 22 in the 2011 Form 10-K are described below.

A.PURCHASE OBLIGATIONS

As part of our ordinary course of business, we and the Utilities enter into various long- and short-term contracts for fuel requirements at our generating plants. Significant changes from the commitment amounts reported in Note 22A in the 2011 Form 10-K can result from new contracts, changes in existing contracts along with the impact of fluctuations in current estimates of future market prices for those contracts that are market price indexed. In most cases, these contracts contain provisions for price adjustments, minimum purchase levels, and other financial commitments. Additional commitments for fuel and related transportation will be required to supply the Utilities' future needs. At March 31, 2012, our and the Utilities' contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2011 Form 10-K.

B.       GUARANTEES

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties. Such agreements include guarantees, standby letters of credit and surety bonds. At March 31, 2012, 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.

At March 31, 2012, we have issued guarantees and indemnifications of and for certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses. At March 31, 2012, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $234 million, including $59 million at PEF. Related to the sales of businesses, the latest specified notice period extends until 2013 for the majority of legal, tax and environmental matters provided for in the indemnification provisions. Indemnifications for the performance of assets extend to 2016. For certain matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain indemnifications related to discontinued operations have no limitations as to time or maximum potential future payments. At March 31, 2012 and December 31, 2011, we had recorded liabilities related to guarantees and indemnifications to third parties of $43 million and $63 million, respectively. These amounts included $35 million and $37 million for PEF at March 31, 2012 and December 31, 2011, respectively. Our liabilities decreased primarily due to the reversal of certain environmental indemnification liabilities for which the indemnification period has expired (See Note 4). During the three months ended March 31, 2012, our and the Utilities' accruals and expendituresrelated to guarantees and indemnifications were not material. As current estimates change, it is possible that additional losses related to guarantees and indemnifications to third parties, which could be material, may be recorded in the future.

In addition, the Parent has issued $300 million in guarantees for certain payments of two wholly owned indirect subsidiaries (See Note 15).

C.        OTHER COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL

We are subject to federal, state and local regulations regarding environmental matters (See Note 13).

Hurricane Katrina

In May 2011, PEC and PEF were named in a class action lawsuit filed in the U.S. District Court for the Southern District of Mississippi. Plaintiffs claimed that PEC and PEF, along with numerous other utility, oil, coal and chemical companies, were liable for damages relating to losses suffered by victims of Hurricane Katrina as a result of their contributions of greenhouse gas emissions to the frequency and intensity of storms such as Hurricane Katrina. On March 20, 2012, the federal district court dismissed the class action lawsuit.On April 16, 2012, the plaintiffs filed a notice of appeal of this decision with the United States Court of Appeals for the Fifth Circuit. We believe the plaintiff's claim is without merit; however, we cannot predict the outcome of this matter.

Water Discharge Permit

In October 2011, Earthjustice, on behalf of the Sierra Club and Florida Wildlife Federation, filed a petition seeking review of the water discharge permit issued to CR1, CR2 and CR3 raising a number of technical and legal issues with respect to the permit. In March 2012, a settlement was reached providing for the withdrawal of the petition and issuance by the FDEP of a revised water discharge permit identical in form to the one under appeal but with an 18-month term rather than the standard five-year term. The settlement fully resolved the current dispute.

SPENT NUCLEAR FUEL MATTERS

Pursuant to the Nuclear Waste Policy Act of 1982, 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 for Disposal of Spent Nuclear Fuel.

The DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, the Utilities filed a complaint in the U.S. Court of Federal Claims against the DOE, claiming that the DOE breached the standard contract and asserting damages incurred through 2005.In2011, the judge in the U.S. Court of Federal Claims issued a ruling to award PEC substantially all their asserted damages. As a result, PEC recorded the award as an offset for past spent fuel storage costs incurred.

On December 12, 2011, the Utilities filed another complaint in the U.S. Court of Federal Claims against the DOE, claiming damages incurred from January 1, 2006, through December 31, 2010. The damages stem from the same breach of contract asserted in the previous litigation. On March 23, 2012, the Utilities filed their initial disclosure of damages with the U.S. Court of Federal Claims and the DOE. The Utilities may file subsequent damage claims as they incur additional costs. We cannot predict the outcome of this matter.

SYNTHETIC FUELS MATTERS

In October 2009, a jury delivered a verdict in a lawsuit against Progress Energy and a number of our subsidiaries and affiliates arising out of an Asset Purchase Agreement dated as of October 19, 1999, and amended as of August 23, 2000, (the Asset Purchase Agreement) by and among U.S. Global, LLC (Global); Earthco synthetic fuels facilities (Earthco); certain affiliates of Earthco; EFC Synfuel LLC (which was owned indirectly by Progress Energy, Inc.) and certain of its affiliates, including Solid Energy LLC; Solid Fuel LLC; Ceredo Synfuel LLC; Gulf Coast Synfuel LLC (renamed Sandy River Synfuel LLC) (collectively, the Progress Affiliates), as amended by an amendment to the Asset Purchase Agreement. In a case filed in the Circuit Court for Broward County, Fla., in March 2003 (the Florida Global Case), Global requested an unspecified amount of compensatory damages, as well as declaratory relief. Global asserted (1) that pursuant to the Asset Purchase Agreement, it was entitled to an interest in two synthetic fuels facilities previously owned by the Progress Affiliates and an option to purchase additional interests in the two synthetic fuels facilities and (2) that it was entitled to damages because the Progress Affiliates prohibited it from procuring purchasers for the synthetic fuels facilities. As a result of the 2007 expiration of the Internal Revenue Code Section 29 tax credit program, all of our synthetic fuels businesses were abandoned and we reclassified our synthetic fuels businesses as discontinued operations.

The jury awarded Global $78 million. In November 2009, the court assessed $55 million in prejudgment interest and entered judgment in favor of Global in a total amount of $133 million. During the year ended December 31, 2009, we recorded an after-tax charge of $74 million to discontinued operations. In December 2009, we appealed the Broward County judgment to the Florida Fourth District Court of Appeals. Also in December 2009, we made a $154 million payment, which represents payment of the total judgment and a required premium equivalent to two years of interest, to the Broward County Clerk of Court bond account. The appellate briefing process has been completed. Oral argument was held on September 27, 2011. We cannot predict the outcome of this matter.

In a second suit filed in the Superior Court for Wake County, N.C., Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC (the North Carolina Global Case), the Progress Affiliates seek declaratory relief consistent with our interpretation of the Asset Purchase Agreement. Global was served with the North Carolina Global Case on April17, 2003.In May 2003, Global moved to dismiss the North Carolina Global Case for lack of personal jurisdiction over Global. In the alternative, Global requested that the court decline to exercise its discretion to hear the Progress Affiliates' declaratory judgment action. In August 2003, the Wake County Superior Court denied Global's motion to dismiss, but stayed the North Carolina Global Case, pending the outcome of the Florida Global Case. The Progress Affiliates appealed the superior court's order staying the case. By order dated September 7, 2004, the North Carolina Court of Appeals dismissed the Progress Affiliates' appeal. Based upon the verdict in the Florida Global Case, we anticipate dismissal of the North Carolina Global Case.

OTHER LITIGATION MATTERS

We and our subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

XML

Benefit Plans

3 Months Ended

Mar. 31, 2012

Benefit Plans Disclosure [Line Items]

Benefit Plans

10.BENEFIT PLANS

We have noncontributory defined benefit retirement plans that provide pension benefits for substantially all full-time employees. 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 months ended March 31 were:

PROGRESS ENERGY
		Pension Benefits					OPEB
(in millions)		2012			2011		2012		2011
Service cost		$	16	$	13	$	3	$	3
Interest cost			33		35		10		10
Expected return on plan assets			(46)		(45)		-		-
Amortization of actuarial loss(a)			23		14		6		3
Other amortization, net(a)			2		2		1		1
	Net periodic cost	$	28	$	19	$	20	$	17
(a)	Adjusted to reflect PEF’s rate treatment. See Note 17B in the 2011 Form 10-K.
PEC
		Pension Benefits				OPEB
(in millions)			2012		2011		2012		2011
Service cost		$	6	$	5	$	1	$	2
Interest cost			15		16		5		5
Expected return on plan assets			(24)		(23)		-		-
Amortization of actuarial loss			9		6		3		1
Other amortization, net			2		1		-		-
	Net periodic cost	$	8	$	5	$	9	$	8
PEF
		Pension Benefits				OPEB
(in millions)			2012		2011		2012		2011
Service cost		$	7	$	6	$	1	$	1
Interest cost			14		15		4		4
Expected return on plan assets			(20)		(20)		-		-
Amortization of actuarial loss			11		8		3		2
Other amortization, net			-		-		1		1
	Net periodic cost	$	12	$	9	$	9	$	8

In 2012, we expect to make contributions directly to pension plan assets of approximately $125 million to $225 million, including $60 million to $110 million for PEC and $65 million to $115million for PEF. We contributed $18 million during the three months ended March 31, 2012, including $10 million for PEC and $8 million for PEF.

PEC

Benefit Plans Disclosure [Line Items]

Benefit Plans

10.BENEFIT PLANS

We have noncontributory defined benefit retirement plans that provide pension benefits for substantially all full-time employees. 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 months ended March 31 were:

PEC
		Pension Benefits				OPEB
(in millions)			2012		2011		2012		2011
Service cost		$	6	$	5	$	1	$	2
Interest cost			15		16		5		5
Expected return on plan assets			(24)		(23)		-		-
Amortization of actuarial loss			9		6		3		1
Other amortization, net			2		1		-		-
	Net periodic cost	$	8	$	5	$	9	$	8

In 2012, we expect to make contributions directly to pension plan assets of approximately $125 million to $225 million, including $60 million to $110 million for PEC and $65 million to $115million for PEF. We contributed $18 million during the three months ended March 31, 2012, including $10 million for PEC and $8 million for PEF.

PEF

Benefit Plans Disclosure [Line Items]

Benefit Plans

10.BENEFIT PLANS

We have noncontributory defined benefit retirement plans that provide pension benefits for substantially all full-time employees. 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 months ended March 31 were:

PEF
		Pension Benefits				OPEB
(in millions)			2012		2011		2012		2011
Service cost		$	7	$	6	$	1	$	1
Interest cost			14		15		4		4
Expected return on plan assets			(20)		(20)		-		-
Amortization of actuarial loss			11		8		3		2
Other amortization, net			-		-		1		1
	Net periodic cost	$	12	$	9	$	9	$	8

In 2012, we expect to make contributions directly to pension plan assets of approximately $125 million to $225 million, including $60 million to $110 million for PEC and $65 million to $115million for PEF. We contributed $18 million during the three months ended March 31, 2012, including $10 million for PEC and $8 million for PEF.

XML

Debt and Credit Facilities

3 Months Ended

Mar. 31, 2012

Debt And Credit Facilities Disclosure [Line Items]

Debt and Credit Facilities

8.DEBT AND CREDIT FACILITIES

Material changes to Progress Energy's, PEC's and PEF's debt and credit facilities and financing activities since December 31, 2011, are as follows.

On February 15, 2012, the Parent's $478 million revolving credit agreement was amended to extend the expiration date from May 3, 2012, to May 3, 2013, with its existing syndication of 14 financial institutions. Our combined credit commitments for the Parent, PEC and PEF are $1.978 billion, supported by 23 financial institutions.

On March8, 2012, the Parent issued $450 million of 3.15% Senior Notes due April 1, 2022. The net proceeds, along with available cash on hand, were used to retire the $450 million outstanding aggregate principal balance of our 6.85% Senior Notes due April 15, 2012.

PEC

Debt And Credit Facilities Disclosure [Line Items]

Debt and Credit Facilities

8.DEBT AND CREDIT FACILITIES

Material changes to Progress Energy's, PEC's and PEF's debt and credit facilities and financing activities since December 31, 2011, are as follows.

On February 15, 2012, the Parent's $478 million revolving credit agreement was amended to extend the expiration date from May 3, 2012, to May 3, 2013, with its existing syndication of 14 financial institutions. Our combined credit commitments for the Parent, PEC and PEF are $1.978 billion, supported by 23 financial institutions.

On March8, 2012, the Parent issued $450 million of 3.15% Senior Notes due April 1, 2022. The net proceeds, along with available cash on hand, were used to retire the $450 million outstanding aggregate principal balance of our 6.85% Senior Notes due April 15, 2012.

PEF

Debt And Credit Facilities Disclosure [Line Items]

Debt and Credit Facilities

8.DEBT AND CREDIT FACILITIES

Material changes to Progress Energy's, PEC's and PEF's debt and credit facilities and financing activities since December 31, 2011, are as follows.

On February 15, 2012, the Parent's $478 million revolving credit agreement was amended to extend the expiration date from May 3, 2012, to May 3, 2013, with its existing syndication of 14 financial institutions. Our combined credit commitments for the Parent, PEC and PEF are $1.978 billion, supported by 23 financial institutions.

On March8, 2012, the Parent issued $450 million of 3.15% Senior Notes due April 1, 2022. The net proceeds, along with available cash on hand, were used to retire the $450 million outstanding aggregate principal balance of our 6.85% Senior Notes due April 15, 2012.

XML

Fair Value Disclosures

3 Months Ended

Mar. 31, 2012

Fair Value Disclosures [Line Items]

Fair Value Disclosures

9.FAIR VALUE DISCLOSURES

A.       DEBT AND INVESTMENTS

PROGRESS ENERGY

DEBT

The carrying amount of our long-term debt, including current maturities, was $13.390billion and $12.941billion at March 31, 2012 and December 31, 2011, respectively. The estimated fair value of this debtwas $15.4 billion and $15.3 billion at March 31, 2012 and December 31, 2011, respectively, and is classified within Level 2 (see further discussion under “B. Fair Value Measurements”).

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. Our available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning the Utilities' nuclear plants as discussed in Note 5C in the 2011Form 10-K. Nuclear decommissioning trust(NDT) funds are presented on the Consolidated Balance Sheets at fair value.

The following table summarizes our available-for-sale securities at March 31, 2012 and December 31, 2011:

(in millions)		Fair Value		Unrealized Losses		Unrealized Gains
March 31, 2012
Common stock equity		$	1,160	$	16	$	508
Preferred stock and other equity			43		-		14
Corporate debt			90		-		7
U.S. state and municipal debt			124		2		7
U.S. and foreign government debt			293		-		14
Money market funds and other			55		1		1
	Total	$	1,765	$	19	$	551
December 31, 2011
Common stock equity		$	1,033	$	29	$	401
Preferred stock and other equity			29		-		11
Corporate debt			86		-		6
U.S. state and municipal debt			128		2		7
U.S. and foreign government debt			284		-		18
Money market funds and other			70		-		1
	Total	$	1,630	$	31	$	444

The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding table includes the unrealized gains and losses for the NDT funds based on the original cost of the trust investments.

The aggregate fair value of investments that related to the 2012 and 2011 unrealized losses was $155 million and $136 million, respectively.

At March 31, 2012, the fair value of our available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	34
Due after one through five years		217
Due after five through 10 years		175
Due after 10 years		94
Total	$	520

The following table presents selected information about our sales of available-for-sale securities during the three months ended March 31, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.

(in millions)	2012		2011
Proceeds	$	304	$	1,744
Realized gains		7		9
Realized losses		3		4

PEC

DEBT

The carrying amount of PEC's long-term debt, including current maturities, was $4.193 billion at March 31, 2012 and December 31, 2011. The estimated fair value of this debtwas $4.7 billion at March 31, 2012 and December 31, 2011, and is classified within Level 2 (see further discussion under “B. Fair Value Measurements”).

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEC's available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEC's nuclear plants as discussed in Note 5C in the 2011Form 10-K. NDT funds are presented on the Consolidated Balance Sheets at fair value.

The following table summarizes PEC's available-for-sale securities at March 31, 2012 and December 31, 2011:

(in millions)		Fair Value		Unrealized Losses		Unrealized Gains
March 31, 2012
Common stock equity		$	755	$	11	$	322
Preferred stock and other equity			20		-		9
Corporate debt			75		-		6
U.S. state and municipal debt			53		-		3
U.S. and foreign government debt			229		-		13
Money market funds and other			34		1		1
	Total	$	1,166	$	12	$	354
December 31, 2011
Common stock equity		$	673	$	20	$	255
Preferred stock and other equity			17		-		7
Corporate debt			69		-		5
U.S. state and municipal debt			56		-		3
U.S. and foreign government debt			226		-		16
Money market funds and other			60		-		1
	Total	$	1,101	$	20	$	287

The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding table includes the unrealized gains and losses for the NDT funds based on the original cost of the trust investments.

The aggregate fair value of investments that related to the March 31, 2012 and December 31, 2011 unrealized losses was $99 million and $98 million, respectively.

At March 31, 2012, the fair value of PEC's available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	11
Due after one through five years		191
Due after five through 10 years		100
Due after 10 years		65
Total	$	367

The following table presents selected information about PEC's sales of available-for-sale securities during the three months ended March 31, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.

(in millions)	2012		2011
Proceeds	$	130	$	131
Realized gains		5		3
Realized losses		2		1

PEF

DEBT

The carrying amount of PEF's long-term debt, including current maturities, was $4.482 billion at March 31, 2012 and December 31, 2011. The estimated fair value of this debtwas $5.3 billion and $5.4 billion at March 31, 2012 and December 31, 2011, respectively,and is classified within Level 2 (see further discussion under “B. Fair Value Measurements”).

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEF's available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEF's nuclear plant as discussed in Note 5C in the 2011Form 10-K. The NDT funds are presented on the Balance Sheets at fair value.

The following table summarizes PEF's available-for-sale securities at March 31, 2012 and December 31, 2011:

(in millions)		Fair Value		Unrealized Losses		Unrealized Gains
March 31, 2012
Common stock equity		$	405	$	5	$	186
Preferred stock and other equity			23		-		5
Corporate debt			15		-		1
U.S. state and municipal debt			71		2		4
U.S. and foreign government debt			64		-		1
Money market funds and other			21		-		-
	Total	$	599	$	7	$	197
December 31, 2011
Common stock equity		$	360	$	9	$	146
Preferred stock and other equity			12		-		4
Corporate debt			17		-		1
U.S. state and municipal debt			72		2		4
U.S. and foreign government debt			58		-		2
Money market funds and other			10		-		-
	Total	$	529	$	11	$	157

The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding table includes unrealized gains and losses for the NDT funds based on the original cost of the trust investments.

The aggregate fair value of investments that related to the March 31, 2012 and December 31, 2011 unrealized losses was $56million and $38 million, respectively.

At March 31, 2012, the fair value of PEF's available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	23
Due after one through five years		26
Due after five through 10 years		75
Due after 10 years		29
Total	$	153

The following table presents selected information about PEF's sales of available-for-sale securities during the three months ended March 31, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.

(in millions)	2012		2011
Proceeds	$	174	$	1,606
Realized gains		2		6
Realized losses		1		3

B.       FAIR VALUE MEASUREMENTS

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Fair value measurements require the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. A midmarket pricing convention (the midpoint price between bid and ask prices) is permitted for use as a practical expedient.

GAAP also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:

Level 1 – The pricing inputs are unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.

Level 2 – The pricing inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards, swaps and options; certain marketable debt securities; and financial instruments traded in less than active markets.

Level 3 – The pricing inputs include significant inputs generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Level 3 instruments may include longer-term instruments that extend into periods in which quoted prices or other observable inputs are not available.

We generally classify our and the Utilities' long-term debt within Level 2. Fair value measurements of long-term debt are obtained from an independent third-party and may take into account a number of factors, including valuations of other comparable financial instruments in terms of rating, structure, maturity and/or covenant protection;comparable trades, where observable; andgeneral interest rate and market conditions. We do not make any adjustments to the long-term debt fair value measurements obtained from the independent third-party and we corroborate the fair value measurements against comparable market data.

The following tables set forth, by level within the fair value hierarchy, our and the Utilities' financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and December 31, 2011. Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

PROGRESS ENERGY
(in millions)			Level 1		Level 2		Level 3		Total
March 31, 2012
Assets
	Nuclear decommissioning trust funds
		Common stock equity	$	1,160	$	-	$	-	$	1,160
		Preferred stock and other equity		33		10		-		43
		Corporate debt		-		90		-		90
		U.S. state and municipal debt		-		124		-		124
		U.S. and foreign government debt		129		164		-		293
		Money market funds and other		1		51		-		52
	Total nuclear decommissioning trust funds			1,323		439		-		1,762
	Derivatives
		Commodity forward contracts		-		8		-		8
	Other marketable securities
		Money market and other		18		-		-		18
		Total assets	$	1,341	$	447	$	-	$	1,788
Liabilities
	Derivatives
		Commodity forward contracts	$	-	$	769	$	27	$	796
		Interest rate contracts		-		49		-		49
		Contingent value obligations derivatives		-		3		-		3
		Total liabilities	$	-	$	821	$	27	$	848
(in millions)				Level 1		Level 2		Level 3		Total
December 31, 2011
Assets
	Nuclear decommissioning trust funds
		Common stock equity	$	1,033	$	-	$	-	$	1,033
		Preferred stock and other equity		28		1		-		29
		Corporate debt		-		86		-		86
		U.S. state and municipal debt		-		128		-		128
		U.S. and foreign government debt		87		197		-		284
		Money market funds and other		-		87		-		87
	Total nuclear decommissioning trust funds			1,148		499		-		1,647
	Derivatives
		Commodity forward contracts		-		5		-		5
	Other marketable securities
		Money market and other		20		-		-		20
		Total assets	$	1,168	$	504	$	-	$	1,672
Liabilities
	Derivatives
		Commodity forward contracts	$	-	$	668	$	24	$	692
		Interest rate contracts		-		93		-		93
		Contingent value obligations derivatives		-		14		-		14
		Total liabilities	$	-	$	775	$	24	$	799
PEC
(in millions)				Level 1		Level 2		Level 3		Total
March 31, 2012
Assets
	Nuclear decommissioning trust funds
		Common stock equity	$	755	$	-	$	-	$	755
		Preferred stock and other equity		20		-		-		20
		Corporate debt		-		75		-		75
		U.S. state and municipal debt		-		53		-		53
		U.S. and foreign government debt		105		124		-		229
		Money market funds and other		1		30		-		31
	Total nuclear decommissioning trust funds			881		282		-		1,163
	Derivatives
		Commodity forward contracts		-		1		-		1
	Other marketable securities			4		-		-		4
		Total assets	$	885	$	283	$	-	$	1,168
Liabilities
	Derivatives
		Commodity forward contracts	$	-	$	208	$	27	$	235
		Interest rate contracts		-		41		-		41
		Total liabilities	$	-	$	249	$	27	$	276
(in millions)				Level 1		Level 2		Level 3		Total
December 31, 2011
Assets
	Nuclear decommissioning trust funds
		Common stock equity	$	673	$	-	$	-	$	673
		Preferred stock and other equity		17		-		-		17
		Corporate debt		-		69		-		69
		U.S. state and municipal debt		-		56		-		56
		U.S. and foreign government debt		81		145		-		226
		Money market funds and other		-		47		-		47
	Total nuclear decommissioning trust funds			771		317		-		1,088
	Other marketable securities			6		-		-		6
		Total assets	$	777	$	317	$	-	$	1,094
Liabilities
	Derivatives
		Commodity forward contracts	$	-	$	177	$	24	$	201
		Interest rate contracts		-		47		-		47
		Total liabilities	$	-	$	224	$	24	$	248
PEF
(in millions)				Level 1		Level 2		Level 3		Total
March 31, 2012
Assets
	Nuclear decommissioning trust funds
		Common stock equity	$	405	$	-	$	-	$	405
		Preferred stock and other equity		13		10		-		23
		Corporate debt		-		15		-		15
		U.S. state and municipal debt		-		71		-		71
		U.S. and foreign government debt		24		40		-		64
		Money market funds and other		-		21		-		21
	Total nuclear decommissioning trust funds			442		157		-		599
	Derivatives
		Commodity forward contracts		-		7		-		7
	Other marketable securities			1		-		-		1
		Total assets	$	443	$	164	$	-	$	607
Liabilities
	Derivatives
		Commodity forward contracts	$	-	$	561	$	-	$	561
		Interest rate contracts		-		8		-		8
		Total liabilities	$	-	$	569	$	-	$	569
(in millions)				Level 1		Level 2		Level 3		Total
December 31, 2011
Assets
	Nuclear decommissioning trust funds
		Common stock equity	$	360	$	-	$	-	$	360
		Preferred stock and other equity		11		1		-		12
		Corporate debt		-		17		-		17
		U.S. state and municipal debt		-		72		-		72
		U.S. and foreign government debt		6		52		-		58
		Money market funds and other		-		40		-		40
	Total nuclear decommissioning trust funds			377		182		-		559
	Derivatives
		Commodity forward contracts		-		5		-		5
	Other marketable securities			1		-		-		1
		Total assets	$	378	$	187	$	-	$	565
Liabilities
	Derivatives
		Commodity forward contracts	$	-	$	491	$	-	$	491
		Interest rate contracts		-		8		-		8
		Total liabilities	$	-	$	499	$	-	$	499

The determination of the fair values in the preceding tables incorporates various factors, including risks of nonperformance by us or our counterparties. Such risks consider not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits or letters of credit), but also the impact of our and the Utilities' credit risk on our liabilities.

Commodity forward contract derivatives and interest rate contract derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity forward contract derivatives and interest rate contract derivatives are valued using financial models which utilize observable inputs for similar instruments and are classified within Level 2. Such models may be internally developed, but are similar to models commonly used across industries to value derivative contracts. To determine fair value, we utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors may include forward commodity prices and price curves, volumes and notional amounts, location, interest rates and credit quality of us and our counterparties. Certain commodity derivatives are valued utilizing pricing inputs that are not observable for substantially the full term of the contract, or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. SeeNote 11 for discussion of risk management activities and derivative transactions.

NDT funds reflect the assets of the Utilities' nuclear decommissioning trusts. The assets of the trusts are invested primarily in exchange-traded equity securities (classified within Level 1) and marketable debt securities, most of which are valued using Level 1 inputs for similar instruments and are classified within Level 2.

We issued Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (Florida Progress), as discussed in Note 16in the 2011 Form 10-K. The CVOs are derivatives recorded at fair value based on quoted prices from a less-than-active market and are classified as Level 2.

Transfers into (out of) Levels 1, 2 or 3 represent existing assets or liabilities previously categorized as a higher level for which the inputs to the estimate became less observable or assets and liabilities that were previously classified as Level 2 or 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the end of the period.There were no transfers into (out of) Levels 1, 2 and 3 during the period.

QUALITATIVE AND QUANTITATIVE INFORMATION ABOUT LEVEL 3 FAIR VALUE MEASUREMENTS

A reconciliation of changes in the fair value of our and PEC's commodity derivative liabilities classified as Level 3 in the fair value hierarchy for the three months endedMarch 31 follows:

PROGRESS ENERGY
(in millions)	2012		2011
Derivatives, net at January 1	$	24	$	36
Total unrealized losses (gains) deferred as regulatory assets and liabilities, net		3		(4)
Derivatives, net at March 31	$	27	$	32
PEC
(in millions)	2012		2011
Derivatives, net at January 1	$	24	$	36
Total unrealized losses (gains) deferred as regulatory assets and liabilities, net		3		(4)
Derivatives, net at March 31	$	27	$	32

During the three months ended March 31, 2012 and 2011, PEF did not have any assets or liabilities classified as Level 3.

Substantially all unrealized gains and losses on derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment.There were no Level 3 realized gains or losses, purchases, sales, issuances or settlements during the period.

For commodity derivative contracts classified as Level 3, we utilize internally-developed financial models based upon the income approach (discounted cash flow method) to measure the fair values. The primary inputs to these models are the forward commodity prices used to develop the forward price curves for the respective instrument. The pricing inputs are derived from published exchange transaction prices and other observable or public data sources. For the commodity derivative contracts classified as Level 3, the pricing inputs for natural gas forward price curves are not observable for the full term of the related contracts. In isolation, increases (decreases) in these unobservable forward natural gas prices would result in favorable (unfavorable) fair value adjustments. In the absence of observable market information that supports the pricing inputs, there is a presumption that the transaction price is equal to the last observable price for a similar period. We regularly evaluate and validate the pricing inputs we use to estimate fair value by a market participant price verification procedure, which provides a comparison of our forward commodity curves to market participant generated curves.

Quantitative information about our and PEC'scommodity derivative liabilities classified as Level 3 follows:

PROGRESS ENERGY
(in millions)	Fair Value		Valuation Technique	Unobservable Input		Range (price per MMBtu)
March 31, 2012
Commodity natural gas hedges	$	27	Discounted cash flow	Forward natural gas curves	$	4.111	-	4.528
PEC
(in millions)	Fair Value		Valuation Technique	Unobservable Input		Range (price per MMBtu)
March 31, 2012
Commodity natural gas hedges	$	27	Discounted cash flow	Forward natural gas curves	$	4.111	-	4.528

PEC

Fair Value Disclosures [Line Items]

Fair Value Disclosures

9.FAIR VALUE DISCLOSURES

A.       DEBT AND INVESTMENTS

PEC

DEBT

The carrying amount of PEC's long-term debt, including current maturities, was $4.193 billion at March 31, 2012 and December 31, 2011. The estimated fair value of this debtwas $4.7 billion at March 31, 2012 and December 31, 2011, and is classified within Level 2 (see further discussion under “B. Fair Value Measurements”).

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEC's available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEC's nuclear plants as discussed in Note 5C in the 2011Form 10-K. NDT funds are presented on the Consolidated Balance Sheets at fair value.

The following table summarizes PEC's available-for-sale securities at March 31, 2012 and December 31, 2011:

(in millions)		Fair Value		Unrealized Losses		Unrealized Gains
March 31, 2012
Common stock equity		$	755	$	11	$	322
Preferred stock and other equity			20		-		9
Corporate debt			75		-		6
U.S. state and municipal debt			53		-		3
U.S. and foreign government debt			229		-		13
Money market funds and other			34		1		1
	Total	$	1,166	$	12	$	354
December 31, 2011
Common stock equity		$	673	$	20	$	255
Preferred stock and other equity			17		-		7
Corporate debt			69		-		5
U.S. state and municipal debt			56		-		3
U.S. and foreign government debt			226		-		16
Money market funds and other			60		-		1
	Total	$	1,101	$	20	$	287

The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding table includes the unrealized gains and losses for the NDT funds based on the original cost of the trust investments.

The aggregate fair value of investments that related to the March 31, 2012 and December 31, 2011 unrealized losses was $99 million and $98 million, respectively.

At March 31, 2012, the fair value of PEC's available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	11
Due after one through five years		191
Due after five through 10 years		100
Due after 10 years		65
Total	$	367

The following table presents selected information about PEC's sales of available-for-sale securities during the three months ended March 31, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.

(in millions)	2012		2011
Proceeds	$	130	$	131
Realized gains		5		3
Realized losses		2		1

B.       FAIR VALUE MEASUREMENTS

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Fair value measurements require the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. A midmarket pricing convention (the midpoint price between bid and ask prices) is permitted for use as a practical expedient.

GAAP also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:

Level 1 – The pricing inputs are unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.

Level 2 – The pricing inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards, swaps and options; certain marketable debt securities; and financial instruments traded in less than active markets.

Level 3 – The pricing inputs include significant inputs generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Level 3 instruments may include longer-term instruments that extend into periods in which quoted prices or other observable inputs are not available.

We generally classify our and the Utilities' long-term debt within Level 2. Fair value measurements of long-term debt are obtained from an independent third-party and may take into account a number of factors, including valuations of other comparable financial instruments in terms of rating, structure, maturity and/or covenant protection;comparable trades, where observable; andgeneral interest rate and market conditions. We do not make any adjustments to the long-term debt fair value measurements obtained from the independent third-party and we corroborate the fair value measurements against comparable market data.

The following tables set forth, by level within the fair value hierarchy, our and the Utilities' financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and December 31, 2011. Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

PEC
(in millions)				Level 1		Level 2		Level 3		Total
March 31, 2012
Assets
	Nuclear decommissioning trust funds
		Common stock equity	$	755	$	-	$	-	$	755
		Preferred stock and other equity		20		-		-		20
		Corporate debt		-		75		-		75
		U.S. state and municipal debt		-		53		-		53
		U.S. and foreign government debt		105		124		-		229
		Money market funds and other		1		30		-		31
	Total nuclear decommissioning trust funds			881		282		-		1,163
	Derivatives
		Commodity forward contracts		-		1		-		1
	Other marketable securities			4		-		-		4
		Total assets	$	885	$	283	$	-	$	1,168
Liabilities
	Derivatives
		Commodity forward contracts	$	-	$	208	$	27	$	235
		Interest rate contracts		-		41		-		41
		Total liabilities	$	-	$	249	$	27	$	276
(in millions)				Level 1		Level 2		Level 3		Total
December 31, 2011
Assets
	Nuclear decommissioning trust funds
		Common stock equity	$	673	$	-	$	-	$	673
		Preferred stock and other equity		17		-		-		17
		Corporate debt		-		69		-		69
		U.S. state and municipal debt		-		56		-		56
		U.S. and foreign government debt		81		145		-		226
		Money market funds and other		-		47		-		47
	Total nuclear decommissioning trust funds			771		317		-		1,088
	Other marketable securities			6		-		-		6
		Total assets	$	777	$	317	$	-	$	1,094
Liabilities
	Derivatives
		Commodity forward contracts	$	-	$	177	$	24	$	201
		Interest rate contracts		-		47		-		47
		Total liabilities	$	-	$	224	$	24	$	248

The determination of the fair values in the preceding tables incorporates various factors, including risks of nonperformance by us or our counterparties. Such risks consider not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits or letters of credit), but also the impact of our and the Utilities' credit risk on our liabilities.

Commodity forward contract derivatives and interest rate contract derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity forward contract derivatives and interest rate contract derivatives are valued using financial models which utilize observable inputs for similar instruments and are classified within Level 2. Such models may be internally developed, but are similar to models commonly used across industries to value derivative contracts. To determine fair value, we utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors may include forward commodity prices and price curves, volumes and notional amounts, location, interest rates and credit quality of us and our counterparties. Certain commodity derivatives are valued utilizing pricing inputs that are not observable for substantially the full term of the contract, or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. SeeNote 11 for discussion of risk management activities and derivative transactions.

NDT funds reflect the assets of the Utilities' nuclear decommissioning trusts. The assets of the trusts are invested primarily in exchange-traded equity securities (classified within Level 1) and marketable debt securities, most of which are valued using Level 1 inputs for similar instruments and are classified within Level 2.

We issued Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (Florida Progress), as discussed in Note 16in the 2011 Form 10-K. The CVOs are derivatives recorded at fair value based on quoted prices from a less-than-active market and are classified as Level 2.

Transfers into (out of) Levels 1, 2 or 3 represent existing assets or liabilities previously categorized as a higher level for which the inputs to the estimate became less observable or assets and liabilities that were previously classified as Level 2 or 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the end of the period.There were no transfers into (out of) Levels 1, 2 and 3 during the period.

QUALITATIVE AND QUANTITATIVE INFORMATION ABOUT LEVEL 3 FAIR VALUE MEASUREMENTS

A reconciliation of changes in the fair value of our and PEC's commodity derivative liabilities classified as Level 3 in the fair value hierarchy for the three months endedMarch 31 follows:

PEC
(in millions)	2012		2011
Derivatives, net at January 1	$	24	$	36
Total unrealized losses (gains) deferred as regulatory assets and liabilities, net		3		(4)
Derivatives, net at March 31	$	27	$	32

During the three months ended March 31, 2012 and 2011, PEF did not have any assets or liabilities classified as Level 3.

Substantially all unrealized gains and losses on derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment.There were no Level 3 realized gains or losses, purchases, sales, issuances or settlements during the period.

For commodity derivative contracts classified as Level 3, we utilize internally-developed financial models based upon the income approach (discounted cash flow method) to measure the fair values. The primary inputs to these models are the forward commodity prices used to develop the forward price curves for the respective instrument. The pricing inputs are derived from published exchange transaction prices and other observable or public data sources. For the commodity derivative contracts classified as Level 3, the pricing inputs for natural gas forward price curves are not observable for the full term of the related contracts. In isolation, increases (decreases) in these unobservable forward natural gas prices would result in favorable (unfavorable) fair value adjustments. In the absence of observable market information that supports the pricing inputs, there is a presumption that the transaction price is equal to the last observable price for a similar period. We regularly evaluate and validate the pricing inputs we use to estimate fair value by a market participant price verification procedure, which provides a comparison of our forward commodity curves to market participant generated curves.

Quantitative information about our and PEC'scommodity derivative liabilities classified as Level 3 follows:

PEC
(in millions)	Fair Value		Valuation Technique	Unobservable Input		Range (price per MMBtu)
March 31, 2012
Commodity natural gas hedges	$	27	Discounted cash flow	Forward natural gas curves	$	4.111	-	4.528

PEF

Fair Value Disclosures [Line Items]

Fair Value Disclosures

9.FAIR VALUE DISCLOSURES

A.       DEBT AND INVESTMENTS

PEF

DEBT

The carrying amount of PEF's long-term debt, including current maturities, was $4.482 billion at March 31, 2012 and December 31, 2011. The estimated fair value of this debtwas $5.3 billion and $5.4 billion at March 31, 2012 and December 31, 2011, respectively,and is classified within Level 2 (see further discussion under “B. Fair Value Measurements”).

INVESTMENTS

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities at fair value. PEF's available-for-sale securities include investments in stocks, bonds and cash equivalents held in trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning PEF's nuclear plant as discussed in Note 5C in the 2011Form 10-K. The NDT funds are presented on the Balance Sheets at fair value.

The following table summarizes PEF's available-for-sale securities at March 31, 2012 and December 31, 2011:

(in millions)		Fair Value		Unrealized Losses		Unrealized Gains
March 31, 2012
Common stock equity		$	405	$	5	$	186
Preferred stock and other equity			23		-		5
Corporate debt			15		-		1
U.S. state and municipal debt			71		2		4
U.S. and foreign government debt			64		-		1
Money market funds and other			21		-		-
	Total	$	599	$	7	$	197
December 31, 2011
Common stock equity		$	360	$	9	$	146
Preferred stock and other equity			12		-		4
Corporate debt			17		-		1
U.S. state and municipal debt			72		2		4
U.S. and foreign government debt			58		-		2
Money market funds and other			10		-		-
	Total	$	529	$	11	$	157

The NDT funds are managed by third-party investment managers who have a right to sell securities without our authorization. Net unrealized gains and losses of the NDT funds that would be recorded in earnings or other comprehensive income by a nonregulated entity are recorded as regulatory assets and liabilities pursuant to ratemaking treatment. Therefore, the preceding table includes unrealized gains and losses for the NDT funds based on the original cost of the trust investments.

The aggregate fair value of investments that related to the March 31, 2012 and December 31, 2011 unrealized losses was $56million and $38 million, respectively.

At March 31, 2012, the fair value of PEF's available-for-sale debt securities by contractual maturity was:

(in millions)
Due in one year or less	$	23
Due after one through five years		26
Due after five through 10 years		75
Due after 10 years		29
Total	$	153

The following table presents selected information about PEF's sales of available-for-sale securities during the three months ended March 31, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.

(in millions)	2012		2011
Proceeds	$	174	$	1,606
Realized gains		2		6
Realized losses		1		3

B.       FAIR VALUE MEASUREMENTS

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Fair value measurements require the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. A midmarket pricing convention (the midpoint price between bid and ask prices) is permitted for use as a practical expedient.

GAAP also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:

Level 1 – The pricing inputs are unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.

Level 2 – The pricing inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards, swaps and options; certain marketable debt securities; and financial instruments traded in less than active markets.

Level 3 – The pricing inputs include significant inputs generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Level 3 instruments may include longer-term instruments that extend into periods in which quoted prices or other observable inputs are not available.

We generally classify our and the Utilities' long-term debt within Level 2. Fair value measurements of long-term debt are obtained from an independent third-party and may take into account a number of factors, including valuations of other comparable financial instruments in terms of rating, structure, maturity and/or covenant protection;comparable trades, where observable; andgeneral interest rate and market conditions. We do not make any adjustments to the long-term debt fair value measurements obtained from the independent third-party and we corroborate the fair value measurements against comparable market data.

The following tables set forth, by level within the fair value hierarchy, our and the Utilities' financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and December 31, 2011. Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

PEF
(in millions)				Level 1		Level 2		Level 3		Total
March 31, 2012
Assets
	Nuclear decommissioning trust funds
		Common stock equity	$	405	$	-	$	-	$	405
		Preferred stock and other equity		13		10		-		23
		Corporate debt		-		15		-		15
		U.S. state and municipal debt		-		71		-		71
		U.S. and foreign government debt		24		40		-		64
		Money market funds and other		-		21		-		21
	Total nuclear decommissioning trust funds			442		157		-		599
	Derivatives
		Commodity forward contracts		-		7		-		7
	Other marketable securities			1		-		-		1
		Total assets	$	443	$	164	$	-	$	607
Liabilities
	Derivatives
		Commodity forward contracts	$	-	$	561	$	-	$	561
		Interest rate contracts		-		8		-		8
		Total liabilities	$	-	$	569	$	-	$	569
(in millions)				Level 1		Level 2		Level 3		Total
December 31, 2011
Assets
	Nuclear decommissioning trust funds
		Common stock equity	$	360	$	-	$	-	$	360
		Preferred stock and other equity		11		1		-		12
		Corporate debt		-		17		-		17
		U.S. state and municipal debt		-		72		-		72
		U.S. and foreign government debt		6		52		-		58
		Money market funds and other		-		40		-		40
	Total nuclear decommissioning trust funds			377		182		-		559
	Derivatives
		Commodity forward contracts		-		5		-		5
	Other marketable securities			1		-		-		1
		Total assets	$	378	$	187	$	-	$	565
Liabilities
	Derivatives
		Commodity forward contracts	$	-	$	491	$	-	$	491
		Interest rate contracts		-		8		-		8
		Total liabilities	$	-	$	499	$	-	$	499

The determination of the fair values in the preceding tables incorporates various factors, including risks of nonperformance by us or our counterparties. Such risks consider not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits or letters of credit), but also the impact of our and the Utilities' credit risk on our liabilities.

Commodity forward contract derivatives and interest rate contract derivatives reflect positions held by us and the Utilities. Most over-the-counter commodity forward contract derivatives and interest rate contract derivatives are valued using financial models which utilize observable inputs for similar instruments and are classified within Level 2. Such models may be internally developed, but are similar to models commonly used across industries to value derivative contracts. To determine fair value, we utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors may include forward commodity prices and price curves, volumes and notional amounts, location, interest rates and credit quality of us and our counterparties. Certain commodity derivatives are valued utilizing pricing inputs that are not observable for substantially the full term of the contract, or for which the impact of the unobservable period is significant to the fair value of the derivative. Such derivatives are classified within Level 3. SeeNote 11 for discussion of risk management activities and derivative transactions.

NDT funds reflect the assets of the Utilities' nuclear decommissioning trusts. The assets of the trusts are invested primarily in exchange-traded equity securities (classified within Level 1) and marketable debt securities, most of which are valued using Level 1 inputs for similar instruments and are classified within Level 2.

We issued Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (Florida Progress), as discussed in Note 16in the 2011 Form 10-K. The CVOs are derivatives recorded at fair value based on quoted prices from a less-than-active market and are classified as Level 2.

Transfers into (out of) Levels 1, 2 or 3 represent existing assets or liabilities previously categorized as a higher level for which the inputs to the estimate became less observable or assets and liabilities that were previously classified as Level 2 or 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the end of the period.There were no transfers into (out of) Levels 1, 2 and 3 during the period.

QUALITATIVE AND QUANTITATIVE INFORMATION ABOUT LEVEL 3 FAIR VALUE MEASUREMENTS

A reconciliation of changes in the fair value of our and PEC's commodity derivative liabilities classified as Level 3 in the fair value hierarchy for the three months endedMarch 31 follows:

During the three months ended March 31, 2012 and 2011, PEF did not have any assets or liabilities classified as Level 3.

Substantially all unrealized gains and losses on derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment.There were no Level 3 realized gains or losses, purchases, sales, issuances or settlements during the period.

For commodity derivative contracts classified as Level 3, we utilize internally-developed financial models based upon the income approach (discounted cash flow method) to measure the fair values. The primary inputs to these models are the forward commodity prices used to develop the forward price curves for the respective instrument. The pricing inputs are derived from published exchange transaction prices and other observable or public data sources. For the commodity derivative contracts classified as Level 3, the pricing inputs for natural gas forward price curves are not observable for the full term of the related contracts. In isolation, increases (decreases) in these unobservable forward natural gas prices would result in favorable (unfavorable) fair value adjustments. In the absence of observable market information that supports the pricing inputs, there is a presumption that the transaction price is equal to the last observable price for a similar period. We regularly evaluate and validate the pricing inputs we use to estimate fair value by a market participant price verification procedure, which provides a comparison of our forward commodity curves to market participant generated curves.

Quantitative information about our and PEC'scommodity derivative liabilities classified as Level 3 follows:

XML

Risk Management Activities and Derivative Transactions

3 Months Ended

Mar. 31, 2012

Risk Management Activities And Derivative Transactions Disclosure [Line Items]

Risk Management Activities And Derivative Transactions

11.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 and financial reviews using a combination of financial analysis and 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.

A.       COMMODITY DERIVATIVES

GENERAL

Most of our physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value.

ECONOMIC DERIVATIVES

Derivative products, primarily natural gas and oil contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions.

The Utilities have financial derivative instruments with settlement dates through 2015 related to their exposure to price fluctuations on fuel oil and natural gas purchases. The majority of our financial hedge agreements will settle in 2012 and 2013. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, on the Balance Sheets until the contracts are settled. After settlement of the derivatives and the fuel is consumed, any realized gains or losses are passed through the fuel cost-recovery clause.

Certain hedge agreements may result in the receipt of, or posting of, derivative collateral with our counterparties, depending on the daily derivative position. Fluctuations in commodity prices that lead to our return of collateral received and/or our posting of collateral with our counterparties negatively impact our liquidity. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures.

Certain counterparties have posted or held cash collateral in support of these instruments. Progress Energy had a cash collateral asset included in derivative collateral posted of $166 million and $147 million on the Progress Energy Consolidated Balance Sheets at March 31, 2012 and December 31, 2011, respectively. At March 31, 2012, Progress Energy had 402.8 million MMBtu notional of natural gas and 10.2 million gallons notional of oil related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas and oil purchases.

PEC had a cash collateral asset included in prepayments and other current assets of $30 million and $24 million on the PEC Consolidated Balance Sheets at March 31, 2012 and December 31, 2011, respectively. At March 31, 2012, PEC had 123.1 million MMBtu notional of natural gas related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas purchases.

PEF's cash collateral asset included in derivative collateral posted was $136 million and $123 million on the PEF Balance Sheets at March 31, 2012 and December 31, 2011, respectively. At March 31, 2012, PEF had 279.7 million MMBtu notional of natural gas and 10.2 million gallons notional of oil related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas and oil purchases.

B.       INTEREST RATE DERIVATIVES

We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates, primarily through the use of forward starting swaps. 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 exposure in these transactions is the cost of replacing the agreements at current market rates.

At March 31, 2012, all open interest rate hedges will reach their mandatory termination dates within two years. At March 31, 2012, including amounts related to terminated hedges, we had $136 million of after-tax losses, including $66 million and $24 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated other comprehensive income (OCI) related to forward starting swaps. It is expected that in the next twelve months losses of $13 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at Progress Energy, including $6 million and $2 million at PEC and PEF, respectively. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in interest rates, changes in the timing of debt issuances at the Parent and the Utilities, and changes in market value of currently open forward starting swaps.

At December 31, 2011, including amounts related to terminated hedges, we had $141 million of after-tax losses, including $71 million and $25 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated OCI related to forward starting swaps.

At March 31, 2012, Progress Energy had $300 million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF.At December 31, 2011, Progress Energy had $500million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF.

C.       CONTINGENT FEATURES

Certain of our commodity derivative instruments contain provisions defining fair value thresholds requiring the posting of collateral for hedges in a liability position greater than such threshold amounts. The thresholds are tiered and based on the individual company's credit rating with Moody's Investors Service, Inc. (Moody's), Standard & Poor's Rating Services (S&P) and/or Fitch Ratings (Fitch). Higher credit ratings have a higher threshold requiring a lower amount of the outstanding liability position to be covered by posted collateral. Conversely, lower credit ratings require a higher amount of the outstanding liability position to be covered by posted collateral. If our credit ratings were to be downgraded, we may have to post additional collateral on certain hedges in liability positions.

In addition, certain of our commodity derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from Moody's, S&P and/or Fitch. If our debt were to fall below investment grade, we would be in violation of these provisions, and the counterparties to the commodity derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on commodity derivative instruments in net liability positions.

The aggregate fair value of all commodity derivative instruments at Progress Energy with credit risk-related contingent features that are in a net liability position was $455 million at March 31, 2012, for which Progress Energy has posted collateral of $166 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2012, Progress Energy would have been required to post an additional $289 million of collateral with its counterparties.

The aggregate fair value of all commodity derivative instruments at PEC with credit risk-related contingent features that are in a liability position was $147 million at March 31, 2012, for which PEC has posted collateral of $30 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2012, PEC would have been required to post an additional $117 million of collateral with its counterparties.

The aggregate fair value of all commodity derivative instruments at PEF with credit risk-related contingent features that are in a net liability position was $308 millionat March 31, 2012, for which PEF has posted collateral of $136 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2012, PEF would have been required to post an additional $172 million of collateral with its counterparties.

D.DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

PROGRESS ENERGY

The following table presents the fair value of derivative instruments at March 31, 2012 and December 31, 2011:
Instrument / Balance sheet location				March 31, 2012				December 31, 2011
(in millions)			Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
	Derivative liabilities, current				$	2			$	2
	Derivative liabilities, long-term					1				1
Interest rate derivatives
	Derivative liabilities, current					42				76
	Derivative liabilities, long-term					7				17
		Total derivatives designated as hedging instruments				52				96
Derivatives not designated as hedging instruments
Commodity derivatives(a)
	Prepayments and other current assets		$	7			$	5
	Other assets and deferred debits			1				-
	Derivative liabilities, current					439				357
	Derivative liabilities, long-term					354				332
CVOs(b)
	Other current liabilities					-				14
	Other liabilities and deferred credits					3				-
		Fair value of derivatives not designated as hedging instruments		8		796		5		703
Fair value loss transition adjustment
	Derivative liabilities, current					1				1
	Derivative liabilities, long-term					2				2
		Total derivatives not designated as hedging instruments		8		799		5		706
		Total derivatives	$	8	$	851	$	5	$	802
(a)	Substantially all of these contracts receive regulatory treatment.
(b)	As discussed in Note 16 in the 2011 Form 10-K, the Parent issued 98.6 million CVOs in connection with the acquisition of Florida Progress during 2000. Through a negotiated settlement agreement and subsequent tender offer between October 2011 and February 2012, we repurchased and continue to hold 83.4 million CVOs.

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011:
Derivatives Designated as Hedging Instruments
Instrument		Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)				Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)				Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)			2012		2011		2012		2011		2012		2011
Interest rate derivatives(c) (d)		$	2	$	2	$	(3)	$	(1)	$	-	$	(1)
(a)	Effective portion.
(b)	Related to ineffective portion and amount excluded from effectiveness testing.
(c)	Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.
(d)	Amounts recorded on the Consolidated Statements of Comprehensive Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments
Instrument		Realized Gain or (Loss)(a)				Unrealized Gain or (Loss)(b)
(in millions)			2012		2011		2012		2011
Commodity derivatives		$	(105)	$	(52)	$	(206)	$	23
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.
Instrument						Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)							2012		2011
CVOs(a)						$	8	$	-
(a)	Amounts recorded in the Consolidated Statements of Comprehensive Income are classified in other, net.

PEC
The following table presents the fair value of derivative instruments at March 31, 2012 and December 31, 2011:
Instrument / Balance sheet location				March 31, 2012			December 31, 2011
(in millions)			Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
	Derivative liabilities, current				$	34			$	38
	Other liabilities and deferred credits					7				9
		Total derivatives designated as hedging instruments				41				47
Derivatives not designated as hedging instruments
Commodity derivatives(a)
	Other assets and deferred debits		$	1			$	-
	Derivative liabilities, current					114				91
	Other liabilities and deferred credits					121				110
		Fair value of derivatives not designated as hedging instruments		1		235		-		201
Fair value loss transition adjustment
	Derivative liabilities, current					1				1
	Other liabilities and deferred credits					2				2
		Total derivatives not designated as hedging instruments		1		238		-		204
		Total derivatives	$	1	$	279	$	-	$	251
(a)	Substantially all of these contracts receive regulatory treatment.

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011:
Derivatives Designated as Hedging Instruments
Instrument		Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)				Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)				Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)			2012		2011		2012		2011		2012		2011
Interest rate derivatives(c) (d)		$	3	$	1	$	(2)	$	(1)	$	-	$	-
(a)	Effective portion.
(b)	Related to ineffective portion and amount excluded from effectiveness testing.
(c)	Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.
(d)	Amounts recorded on the Consolidated Statements of Comprehensive Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments
Instrument		Realized Gain or (Loss)(a)				Unrealized Gain or (Loss)(b)
(in millions)			2012		2011		2012		2011
Commodity derivatives		$	(26)	$	(11)	$	(59)	$	7
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.

PEF
The following table presents the fair value of derivative instruments at March 31, 2012 and December 31, 2011:
Instrument / Balance sheet location				March 31, 2012				December 31, 2011
(in millions)			Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
	Derivative liabilities, current				$	2			$	2
	Derivative liabilities, long-term					1				1
Interest rate derivatives
	Derivative liabilities, current					8				-
	Derivative liabilities, long-term					-				8
		Total derivatives designated as hedging instruments				11				11
Derivatives not designated as hedging instruments
Commodity derivatives(a)
	Prepayments and other current assets		$	7			$	5
	Derivative liabilities, current					325				266
	Derivative liabilities, long-term					233				222
		Total derivatives not designated as hedging instruments		7		558		5		488
		Total derivatives	$	7	$	569	$	5	$	499
(a)	Substantially all of these contracts receive regulatory treatment.

The following tables present the effect of derivative instruments on the Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011:
Derivatives Designated as Hedging Instruments
Instrument		Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)				Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)				Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)			2012		2011		2012		2011		2012		2011
Interest rate derivatives(c) (d)		$	-	$	-	$	(1)	$	-	$	-	$	-
(a)	Effective portion.
(b)	Related to ineffective portion and amount excluded from effectiveness testing.
(c)	Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.
(d)	Amounts recorded on the Statements of Comprehensive Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments
Instrument		Realized Gain or (Loss)(a)				Unrealized Gain or (Loss)(b)
(in millions)			2012		2011		2012		2011
Commodity derivatives		$	(79)	$	(41)	$	(147)	$	17
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Balance Sheets until derivatives are settled.

PEC

Risk Management Activities And Derivative Transactions Disclosure [Line Items]

Risk Management Activities And Derivative Transactions

11.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 and financial reviews using a combination of financial analysis and 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.

A.       COMMODITY DERIVATIVES

GENERAL

Most of our physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value.

ECONOMIC DERIVATIVES

Derivative products, primarily natural gas and oil contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions.

The Utilities have financial derivative instruments with settlement dates through 2015 related to their exposure to price fluctuations on fuel oil and natural gas purchases. The majority of our financial hedge agreements will settle in 2012 and 2013. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, on the Balance Sheets until the contracts are settled. After settlement of the derivatives and the fuel is consumed, any realized gains or losses are passed through the fuel cost-recovery clause.

Certain hedge agreements may result in the receipt of, or posting of, derivative collateral with our counterparties, depending on the daily derivative position. Fluctuations in commodity prices that lead to our return of collateral received and/or our posting of collateral with our counterparties negatively impact our liquidity. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures.

Certain counterparties have posted or held cash collateral in support of these instruments. Progress Energy had a cash collateral asset included in derivative collateral posted of $166 million and $147 million on the Progress Energy Consolidated Balance Sheets at March 31, 2012 and December 31, 2011, respectively. At March 31, 2012, Progress Energy had 402.8 million MMBtu notional of natural gas and 10.2 million gallons notional of oil related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas and oil purchases.

PEC had a cash collateral asset included in prepayments and other current assets of $30 million and $24 million on the PEC Consolidated Balance Sheets at March 31, 2012 and December 31, 2011, respectively. At March 31, 2012, PEC had 123.1 million MMBtu notional of natural gas related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas purchases.

PEF's cash collateral asset included in derivative collateral posted was $136 million and $123 million on the PEF Balance Sheets at March 31, 2012 and December 31, 2011, respectively. At March 31, 2012, PEF had 279.7 million MMBtu notional of natural gas and 10.2 million gallons notional of oil related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas and oil purchases.

B.       INTEREST RATE DERIVATIVES

We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates, primarily through the use of forward starting swaps. 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 exposure in these transactions is the cost of replacing the agreements at current market rates.

At March 31, 2012, all open interest rate hedges will reach their mandatory termination dates within two years. At March 31, 2012, including amounts related to terminated hedges, we had $136 million of after-tax losses, including $66 million and $24 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated other comprehensive income (OCI) related to forward starting swaps. It is expected that in the next twelve months losses of $13 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at Progress Energy, including $6 million and $2 million at PEC and PEF, respectively. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in interest rates, changes in the timing of debt issuances at the Parent and the Utilities, and changes in market value of currently open forward starting swaps.

At December 31, 2011, including amounts related to terminated hedges, we had $141 million of after-tax losses, including $71 million and $25 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated OCI related to forward starting swaps.

At March 31, 2012, Progress Energy had $300 million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF.At December 31, 2011, Progress Energy had $500million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF.

C.       CONTINGENT FEATURES

Certain of our commodity derivative instruments contain provisions defining fair value thresholds requiring the posting of collateral for hedges in a liability position greater than such threshold amounts. The thresholds are tiered and based on the individual company's credit rating with Moody's Investors Service, Inc. (Moody's), Standard & Poor's Rating Services (S&P) and/or Fitch Ratings (Fitch). Higher credit ratings have a higher threshold requiring a lower amount of the outstanding liability position to be covered by posted collateral. Conversely, lower credit ratings require a higher amount of the outstanding liability position to be covered by posted collateral. If our credit ratings were to be downgraded, we may have to post additional collateral on certain hedges in liability positions.

In addition, certain of our commodity derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from Moody's, S&P and/or Fitch. If our debt were to fall below investment grade, we would be in violation of these provisions, and the counterparties to the commodity derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on commodity derivative instruments in net liability positions.

The aggregate fair value of all commodity derivative instruments at Progress Energy with credit risk-related contingent features that are in a net liability position was $455 million at March 31, 2012, for which Progress Energy has posted collateral of $166 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2012, Progress Energy would have been required to post an additional $289 million of collateral with its counterparties.

The aggregate fair value of all commodity derivative instruments at PEC with credit risk-related contingent features that are in a liability position was $147 million at March 31, 2012, for which PEC has posted collateral of $30 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2012, PEC would have been required to post an additional $117 million of collateral with its counterparties.

The aggregate fair value of all commodity derivative instruments at PEF with credit risk-related contingent features that are in a net liability position was $308 millionat March 31, 2012, for which PEF has posted collateral of $136 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2012, PEF would have been required to post an additional $172 million of collateral with its counterparties.

D.DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

PEC
The following table presents the fair value of derivative instruments at March 31, 2012 and December 31, 2011:
Instrument / Balance sheet location				March 31, 2012			December 31, 2011
(in millions)			Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Interest rate derivatives
	Derivative liabilities, current				$	34			$	38
	Other liabilities and deferred credits					7				9
		Total derivatives designated as hedging instruments				41				47
Derivatives not designated as hedging instruments
Commodity derivatives(a)
	Other assets and deferred debits		$	1			$	-
	Derivative liabilities, current					114				91
	Other liabilities and deferred credits					121				110
		Fair value of derivatives not designated as hedging instruments		1		235		-		201
Fair value loss transition adjustment
	Derivative liabilities, current					1				1
	Other liabilities and deferred credits					2				2
		Total derivatives not designated as hedging instruments		1		238		-		204
		Total derivatives	$	1	$	279	$	-	$	251
(a)	Substantially all of these contracts receive regulatory treatment.

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011:
Derivatives Designated as Hedging Instruments
Instrument		Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)				Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)				Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)			2012		2011		2012		2011		2012		2011
Interest rate derivatives(c) (d)		$	3	$	1	$	(2)	$	(1)	$	-	$	-
(a)	Effective portion.
(b)	Related to ineffective portion and amount excluded from effectiveness testing.
(c)	Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.
(d)	Amounts recorded on the Consolidated Statements of Comprehensive Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments
Instrument		Realized Gain or (Loss)(a)				Unrealized Gain or (Loss)(b)
(in millions)			2012		2011		2012		2011
Commodity derivatives		$	(26)	$	(11)	$	(59)	$	7
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.

PEF

Risk Management Activities And Derivative Transactions Disclosure [Line Items]

Risk Management Activities And Derivative Transactions

11.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 and financial reviews using a combination of financial analysis and 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.

A.       COMMODITY DERIVATIVES

GENERAL

Most of our physical commodity contracts are not derivatives or qualify as normal purchases or sales. Therefore, such contracts are not recorded at fair value.

ECONOMIC DERIVATIVES

Derivative products, primarily natural gas and oil contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions.

The Utilities have financial derivative instruments with settlement dates through 2015 related to their exposure to price fluctuations on fuel oil and natural gas purchases. The majority of our financial hedge agreements will settle in 2012 and 2013. Substantially all of these instruments receive regulatory accounting treatment. Related unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, on the Balance Sheets until the contracts are settled. After settlement of the derivatives and the fuel is consumed, any realized gains or losses are passed through the fuel cost-recovery clause.

Certain hedge agreements may result in the receipt of, or posting of, derivative collateral with our counterparties, depending on the daily derivative position. Fluctuations in commodity prices that lead to our return of collateral received and/or our posting of collateral with our counterparties negatively impact our liquidity. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures.

Certain counterparties have posted or held cash collateral in support of these instruments. Progress Energy had a cash collateral asset included in derivative collateral posted of $166 million and $147 million on the Progress Energy Consolidated Balance Sheets at March 31, 2012 and December 31, 2011, respectively. At March 31, 2012, Progress Energy had 402.8 million MMBtu notional of natural gas and 10.2 million gallons notional of oil related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas and oil purchases.

PEC had a cash collateral asset included in prepayments and other current assets of $30 million and $24 million on the PEC Consolidated Balance Sheets at March 31, 2012 and December 31, 2011, respectively. At March 31, 2012, PEC had 123.1 million MMBtu notional of natural gas related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas purchases.

PEF's cash collateral asset included in derivative collateral posted was $136 million and $123 million on the PEF Balance Sheets at March 31, 2012 and December 31, 2011, respectively. At March 31, 2012, PEF had 279.7 million MMBtu notional of natural gas and 10.2 million gallons notional of oil related to outstanding commodity derivative swaps and options that were entered into to hedge forecasted natural gas and oil purchases.

B.       INTEREST RATE DERIVATIVES

We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates, primarily through the use of forward starting swaps. 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 exposure in these transactions is the cost of replacing the agreements at current market rates.

At March 31, 2012, all open interest rate hedges will reach their mandatory termination dates within two years. At March 31, 2012, including amounts related to terminated hedges, we had $136 million of after-tax losses, including $66 million and $24 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated other comprehensive income (OCI) related to forward starting swaps. It is expected that in the next twelve months losses of $13 million, net of tax, primarily related to terminated hedges, will be reclassified to interest expense at Progress Energy, including $6 million and $2 million at PEC and PEF, respectively. The actual amounts that will be reclassified to earnings may vary from the expected amounts as a result of changes in interest rates, changes in the timing of debt issuances at the Parent and the Utilities, and changes in market value of currently open forward starting swaps.

At December 31, 2011, including amounts related to terminated hedges, we had $141 million of after-tax losses, including $71 million and $25 million of after-tax losses at PEC and PEF, respectively, recorded in accumulated OCI related to forward starting swaps.

At March 31, 2012, Progress Energy had $300 million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF.At December 31, 2011, Progress Energy had $500million notional of open forward starting swaps, including $250 million at PEC and $50 million at PEF.

C.       CONTINGENT FEATURES

Certain of our commodity derivative instruments contain provisions defining fair value thresholds requiring the posting of collateral for hedges in a liability position greater than such threshold amounts. The thresholds are tiered and based on the individual company's credit rating with Moody's Investors Service, Inc. (Moody's), Standard & Poor's Rating Services (S&P) and/or Fitch Ratings (Fitch). Higher credit ratings have a higher threshold requiring a lower amount of the outstanding liability position to be covered by posted collateral. Conversely, lower credit ratings require a higher amount of the outstanding liability position to be covered by posted collateral. If our credit ratings were to be downgraded, we may have to post additional collateral on certain hedges in liability positions.

In addition, certain of our commodity derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from Moody's, S&P and/or Fitch. If our debt were to fall below investment grade, we would be in violation of these provisions, and the counterparties to the commodity derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on commodity derivative instruments in net liability positions.

The aggregate fair value of all commodity derivative instruments at Progress Energy with credit risk-related contingent features that are in a net liability position was $455 million at March 31, 2012, for which Progress Energy has posted collateral of $166 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2012, Progress Energy would have been required to post an additional $289 million of collateral with its counterparties.

The aggregate fair value of all commodity derivative instruments at PEC with credit risk-related contingent features that are in a liability position was $147 million at March 31, 2012, for which PEC has posted collateral of $30 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2012, PEC would have been required to post an additional $117 million of collateral with its counterparties.

The aggregate fair value of all commodity derivative instruments at PEF with credit risk-related contingent features that are in a net liability position was $308 millionat March 31, 2012, for which PEF has posted collateral of $136 million in the normal course of business. If the credit risk-related contingent features underlying these agreements were triggered at March 31, 2012, PEF would have been required to post an additional $172 million of collateral with its counterparties.

D.DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

PEF
The following table presents the fair value of derivative instruments at March 31, 2012 and December 31, 2011:
Instrument / Balance sheet location				March 31, 2012				December 31, 2011
(in millions)			Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
	Derivative liabilities, current				$	2			$	2
	Derivative liabilities, long-term					1				1
Interest rate derivatives
	Derivative liabilities, current					8				-
	Derivative liabilities, long-term					-				8
		Total derivatives designated as hedging instruments				11				11
Derivatives not designated as hedging instruments
Commodity derivatives(a)
	Prepayments and other current assets		$	7			$	5
	Derivative liabilities, current					325				266
	Derivative liabilities, long-term					233				222
		Total derivatives not designated as hedging instruments		7		558		5		488
		Total derivatives	$	7	$	569	$	5	$	499
(a)	Substantially all of these contracts receive regulatory treatment.

The following tables present the effect of derivative instruments on the Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011:
Derivatives Designated as Hedging Instruments
Instrument		Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)				Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)				Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)			2012		2011		2012		2011		2012		2011
Interest rate derivatives(c) (d)		$	-	$	-	$	(1)	$	-	$	-	$	-
(a)	Effective portion.
(b)	Related to ineffective portion and amount excluded from effectiveness testing.
(c)	Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.
(d)	Amounts recorded on the Statements of Comprehensive Income are classified in interest charges.

Derivatives Not Designated as Hedging Instruments
Instrument		Realized Gain or (Loss)(a)				Unrealized Gain or (Loss)(b)
(in millions)			2012		2011		2012		2011
Commodity derivatives		$	(79)	$	(41)	$	(147)	$	17
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Balance Sheets until derivatives are settled.

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Equity - Reconciliation of Total Equity (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Beginning balance	$ 10,025		$ 10,027
Net income	150	[1]	183	[1]
Other comprehensive income	5		4
Issuance of shares through offerings and stock-based compensation plans (See Note 6C)	17		19
Dividends declared	(184)		(183)
Distributions to noncontrolling interests	(2)		(2)
Other	0		2
Ending balance	10,011		10,050
Notes To Reconciliation Of Total Equity [Details]
Net income	152		185
Net income attributable to preferred shareholders of subsidiaries excluded from reconciliation of total equity	2		2
Total Common Stock Equity
Beginning balance	10,021		10,023
Net income	150		184
Other comprehensive income	5		4
Issuance of shares through offerings and stock-based compensation plans (See Note 6C)	17		19
Dividends declared	(184)		(183)
Distributions to noncontrolling interests	0		0
Other	0		0
Ending balance	10,009		10,047
Noncontrolling Interests
Beginning balance	4		4
Net income	0		(1)
Other comprehensive income	0		0
Issuance of shares through offerings and stock-based compensation plans (See Note 6C)	0		0
Dividends declared	0		0
Distributions to noncontrolling interests	(2)		(2)
Other	0		2
Ending balance	$ 2		$ 3

[1] For the three months ended March 31, 2012, consolidated net income of $152 million includes $2 million attributable to preferred shareholders of subsidiaries. For the three months ended March 31, 2011, consolidated net income of $185 million includes $2 million attributable to preferred shareholders of subsidiaries. Income attributable to preferred shareholders of subsidiaries is not a component of total equity and is excluded from the table above.

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Significant Accounting Policies (Significant Accounting Policies)

3 Months Ended

Mar. 31, 2012

Significant accounting policies

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. The December 31, 2011 condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. 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 Progress Registrants' annual report on Form 10-K for the fiscal year ended December 31, 2011 (2011 Form 10-K).

The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary to fairly present the Progress Registrants' financial position and results of operations for the interim periods. Unless otherwise noted, all adjustments are normal and recurring in nature. Due to seasonal weather variations, the impact of regulatory orders received, 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.

Use of estimates and assumptions

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

Excise taxes

The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for sales and use tax on a net basis and gross receipts tax, franchise taxes and other excise taxes on a gross basis.

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Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2012

Benefit Plans Tables [Abstract]

Schedule of Net Benefit Costs [Tables]

PROGRESS ENERGY
		Pension Benefits					OPEB
(in millions)		2012			2011		2012		2011
Service cost		$	16	$	13	$	3	$	3
Interest cost			33		35		10		10
Expected return on plan assets			(46)		(45)		-		-
Amortization of actuarial loss(a)			23		14		6		3
Other amortization, net(a)			2		2		1		1
	Net periodic cost	$	28	$	19	$	20	$	17
(a)	Adjusted to reflect PEF’s rate treatment. See Note 17B in the 2011 Form 10-K.

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Benefit Plans - Contribution and Benefit Payment Expectations (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Contribution And Benefit Payment [Line Items]
2012 expected contributions, top of range	$ 225
2012 expected contributions, bottom of range	$ 125

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Unaudited Consolidated Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating activities
Net income	$ 152	$ 185
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	200	199
Deferred income taxes and investment tax credits, net	107	101
Deferred fuel cost (credit)	(6)	70
Allowance for equity funds used during construction	(24)	(29)
Other adjustments to net income	(7)	56
Cash provided (used) by changes in operating assets and liabilities
Receivables	78	163
Inventory	(10)	(49)
Other assets	(48)	7
Income taxes, net	(7)	57
Accounts payable	23	(89)
Accrued pension and other benefits	(33)	(224)
Other liabilities	(69)	(1)
Net cash provided (used) by operating activities	356	446
Investing activities
Gross property additions	(562)	(501)
Nuclear fuel additions	(51)	(57)
Purchases of available-for-sale securities and other investments	(363)	(1,817)
Proceeds from available-for-sale securities and other investments	359	1,809
Other investing activities	65	46
Net cash provided (used) by investing activities	(552)	(520)
Financing activities
Issuance of common stock, net	3	8
Dividends paid on common stock	(260)	(183)
Proceeds from issuance of short-term debt with original maturities greater than 90 days	65	0
Net increase (decrease) in short-term debt	320	79
Proceeds from issuance of long-term debt, net	444	494
Retirement of long-term debt	0	(700)
Other financing activities	(41)	(63)
Net cash provided (used) by financing activities	531	(365)
Net increase (decrease) in cash and cash equivalents	335	(439)
Cash and cash equivalents at beginning of period	230	611
Cash and cash equivalents at end of period	565	172
Significant noncash transactions
Accrued property additions	225	178
PEC
Operating activities
Net income	52	131
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	162	161
Deferred income taxes and investment tax credits, net	46	69
Deferred fuel cost (credit)	7	29
Allowance for equity funds used during construction	(15)	(20)
Other adjustments to net income	23	12
Cash provided (used) by changes in operating assets and liabilities
Receivables	50	102
Receivables from affiliated companies	(8)	11
Inventory	(5)	(45)
Other assets	(18)	(8)
Income taxes, net	(38)	81
Accounts payable	11	(48)
Payables to affiliated companies	23	(24)
Accrued pension and other benefits	(17)	(147)
Other liabilities	(27)	13
Net cash provided (used) by operating activities	246	317
Investing activities
Gross property additions	(356)	(279)
Nuclear fuel additions	(38)	(50)
Purchases of available-for-sale securities and other investments	(138)	(149)
Proceeds from available-for-sale securities and other investments	133	141
Changes in advances to affiliated companies	0	(1)
Other investing activities	64	5
Net cash provided (used) by investing activities	(335)	(333)
Financing activities
Dividends paid on preferred stock	(1)	(1)
Dividends paid to parent	(175)	(100)
Net increase (decrease) in short-term debt	253	0
Changes in advances from affiliated companies	11	0
Other financing activities	2	0
Net cash provided (used) by financing activities	90	(101)
Net increase (decrease) in cash and cash equivalents	1	(117)
Cash and cash equivalents at beginning of period	20	230
Cash and cash equivalents at end of period	21	113
Significant noncash transactions
Accrued property additions	162	98
PEF
Operating activities
Net income	128	102
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	31	29
Deferred income taxes and investment tax credits, net	53	60
Deferred fuel cost (credit)	(13)	41
Allowance for equity funds used during construction	(9)	(9)
Other adjustments to net income	(20)	35
Cash provided (used) by changes in operating assets and liabilities
Receivables	15	72
Receivables from affiliated companies	(13)	(7)
Inventory	(6)	(5)
Other assets	(27)	19
Income taxes, net	22	63
Accounts payable	14	(45)
Payables to affiliated companies	13	(6)
Accrued pension and other benefits	(14)	(74)
Other liabilities	15	26
Net cash provided (used) by operating activities	189	301
Investing activities
Gross property additions	(197)	(218)
Nuclear fuel additions	(13)	(7)
Purchases of available-for-sale securities and other investments	(225)	(1,659)
Proceeds from available-for-sale securities and other investments	225	1,659
Changes in advances to affiliated companies	(6)	0
Other investing activities	16	42
Net cash provided (used) by investing activities	(200)	(183)
Financing activities
Dividends paid on preferred stock	(1)	(1)
Dividends paid to parent	(105)	(325)
Proceeds from issuance of short-term debt with original maturities greater than 90 days	65	0
Net increase (decrease) in short-term debt	62	0
Changes in advances from affiliated companies	(8)	(2)
Net cash provided (used) by financing activities	13	(328)
Net increase (decrease) in cash and cash equivalents	2	(210)
Cash and cash equivalents at beginning of period	16	249
Cash and cash equivalents at end of period	18	39
Significant noncash transactions
Accrued property additions	$ 60	$ 78

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Regulatory Matters

3 Months Ended

Mar. 31, 2012

Regulatory Matters Disclosure [Line Items]

Regulatory Matters

5.       REGULATORY MATTERS

On January 8, 2011, Progress Energy and Duke Energy entered into the Merger Agreement. See Note 2 for regulatory information related to the merger with Duke Energy.

A.PEC RETAIL RATE MATTERS

COST RECOVERY FILINGS

On March 1, 2012, PEC filed with the SCPSC for a $5 millionincrease in thedemand-side management (DSM) and energy-efficiency (EE) rate, driven by the introduction of new, and the expansion of existing, DSM and EE programs. If approved, the increase will beeffective July 1, 2012, andwill increase residential electric bills by $1.37 per 1,000 kilowatt-hours (kWh). We cannot predict the outcome of this matter.

B.       PEF RETAIL RATE MATTERS

CR3 OUTAGE

In September 2009, Crystal River Nuclear Plant Unit 3 (CR3) began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete at the periphery of the containment building, which resulted in an extension of the outage. After analysis, PEF determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when PEF created an opening to accommodate the replacement of the unit's steam generators. In March 2011, the work to return the plant to service was suspended after monitoring equipment at the repair site identified a new delamination that occurred in a different section of the outer wall after the repair work was completed and during the late stages of retensioning the containment building. CR3 has remained out of service while PEF conducted an engineering analysis and review of the new delamination and evaluated repair options. Subsequent to March 2011, monitoring equipment has detected additional changes and further damage in the partially tensioned containment building and additional cracking or delaminations could occur during the repair process.

PEF analyzed multiple repair options as well as early decommissioning and believes, based on the information and analyses conducted to date, that repairing the unit is the best option. PEF engaged outside engineering consultants to perform the analysis of possible repair options for the containment building. The consultants analyzed 22 potential repair options and ultimately narrowed those to four. PEF, along with other independent consultants, reviewed the four options for technical issues, constructability, and licensing feasibility as well as cost.

Based on that initial analysis, PEF selected the best repair option, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls. The planned option does not include the area where concrete was replaced during the initial repair. The preliminary cost estimate for this repair as filed with the FPSC on June 27, 2011, is between $900 million and $1.3 billion. Engineering design of the repair is under way. PEF will update the current estimate as this work is completed.

PEF is moving forward systematically and will perform additional detailed engineering analyses and designs, which could affect any repair plan. This process will lead to more certainty for the cost and schedule of the repair. PEF will continue to refine and assess the plan, and the prudence of continuing to pursue it, based on new developments and analyses as the process moves forward. Under this repair plan, PEF estimates that CR3 will return to service in 2014. The decision related to repairing or decommissioning CR3 is complex and subject to a number of unknown factors, including but not limited to, the cost of repair and the likelihood of obtaining NRC approval to restart CR3 after repair. A number of factors could affect the repair plan, the return-to-service date and costs, including regulatory reviews, final engineering designs, contract negotiations, the ultimate work scope completion, testing, weather, the impact of new information discovered during additional testing and analysis and other developments.

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through Nuclear Electric Insurance Limited (NEIL). NEIL has confirmed that the CR3 initial delamination is a covered accidentbut has not yet made a determination as to coverage for the second delamination. Following a 12-week deductible period, the NEIL program provided reimbursement for replacement power costs for 52 weeks at $4.5 million per week, through April 9, 2011. Anadditional 71weeks of coverage, which runs through August 2012, is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. Actual replacement power costs have exceeded the insurance coverage through March 31, 2012. PEF anticipates that future replacement power costs will continue to exceed the insurance coverage. PEF also maintains insurance coverage through NEIL's accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim.

PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs. PEF has not yet received a definitive determination from NEIL about the insurance coverage related to the second delamination. In addition, no replacement power reimbursements have been received from NEIL since May 2011. These considerations led us to conclude that it was not probable that NEIL will voluntarily pay the full coverage amounts we believe they owe under the applicable insurance policies. Given the circumstances, accounting standards require full recovery to be probable to recognize an insurance receivable. Therefore, PEF has not recorded insurance receivables from NEIL related to the second delamination. Negotiations continue with NEIL regarding coverage associated with the second delamination, and PEF continues to believe that all applicable costs associated with bringing CR3 back into service are covered under all insurance policies.

The following table summarizes the CR3 replacement power and repair costs and recovery through March 31, 2012:

(in millions)			Replacement Power Costs		Repair Costs
Spent to date			$	506	$	279
NEIL proceeds received to date				(162)		(143)
Insurance receivable at March 31, 2012, net				(55)		0
	Balance for recovery(a)		$	289	$	136
(a)		See "2012 Settlement Agreement" below for discussion of PEF's ability to recover prudently incurred fuel and purchased power costs and CR3 repair costs.

PEFbelieves the actions taken and costs incurred in response to the CR3 delamination have been prudent and, accordingly, considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. Additional replacement power costs and repair and maintenance costs incurred until CR3 is returned to service could be material. Additionally, we cannot be assured that CR3 can be repaired and brought back to service until full engineering and other analyses are completed.

2012 SETTLEMENT AGREEMENT

On February 22, 2012, the FPSC approved a comprehensive settlement agreement among PEF, the Florida Office of Public Counsel and other consumer advocates. The 2012 settlement agreement will continue through the last billing cycle of December 2016. The agreement addresses three principal matters: PEF's proposed Levy Nuclear Power Plant (Levy) Nuclear Project cost recovery, the CR3 delamination prudence review then pending before the FPSC, and certain base rate issues. When all of the settlement provisions are factored in, the total increase in 2013 for residential customer bills will be approximately $4.93 per 1,000 kWh, or 4 percent.

Levy

Under the terms of the 2012 settlement agreement, PEF will set the residential cost-recovery factor of PEF's proposed two units at Levy (see “Nuclear Cost Recovery – Levy Nuclear”) at $3.45 per 1,000 kWh effective in the first billing cycle of January 2013 and continuing for a five-year period. PEF will not recover any additional Levy costs from customers through the term of the agreement, or file for any additional recovery before March 1, 2017, unless otherwise agreed to by the parties to the agreement. This amount is intended to recover the estimated retail project costs to date plus costs necessary to obtain the combined license (COL) and any engineering, procurement and construction (EPC) cancellation costs, if PEF ultimately chooses to cancel that contract. In addition, the consumer parties will not oppose PEF continuing to pursue a COL for Levy. After the five-year period, PEF will true up any actual costs not recovered under the Levy cost-recovery factor.

The 2012 settlement agreement also provides that PEF will treat the allocated wholesale cost of Levy as a retail regulatory asset and include this asset as a component of rate base and amortization expense for regulatory reporting. PEF will have the discretion to accelerate and/or suspend such amortization in full or in part provided that PEF amortizes all of the regulatory asset by December 31, 2016.

CR3

Under the terms of the 2012 settlement agreement, PEF will be permitted to recover prudently incurred fuel and purchased power costs through the fuel clause without regard for the absence of CR3 for the period from the beginning of the CR3 outage through the earlier of the term of the agreement or the return of CR3 to commercial service. If PEF does not begin repairs of CR3 prior to the end of 2012, PEF will refund replacement power costs on a pro rata basis based on the in-service date of up to $40 million in 2015 and $60 million in 2016. The parties to the agreement waive their right to challenge PEF's recovery of replacement power costs. The parties to the agreement maintain the right to challenge the prudence and reasonableness of PEF's fuel acquisition and power purchases, and other fuel prudence issues unrelated to the CR3 outage. All prudence issues from the steam generator project inception through the date of settlement approval by the FPSC are resolved.

To the extent that PEF pursues the repair of CR3, PEF will establish an estimated cost and repair schedule with ongoing consultation with the parties to the agreement. The established cost, to be approved by our board of directors, will be the basis for project measurement. If costs exceed the board-approved estimate, overruns will be split evenly between our shareholders and PEF customers up to $400 million. The parties to the agreement agree to discuss the method of recovery of any overruns in excess of $400 million, with final decision by the FPSC if resolution cannot be reached. If the repairs begin prior to the end of 2012, the parties to the agreement waive their rights to challenge PEF's decision to repair and the repair plan chosen by PEF. In addition, there will be limited rights to challenge recovery of the repair execution costs incurred prior to the final resolution on NEIL coverage. The parties to the agreement will discuss the treatment of any potential gap between NEIL repair coverage and the estimated cost, with final decision by the FPSC if resolution cannot be reached. If the repairs do not begin prior to the end of 2012, the parties to the agreement reserve the right to challenge the prudence of PEF's repair decision, plan and implementation.

PEF also retains sole discretion and flexibility to retire the unit without challenge from the parties to the agreement. If PEF decides to retire CR3, PEF is allowed to recover all remaining CR3 investments and to earn a return on the CR3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity (ROE) set at 70 percent of the current FPSC-authorized ROE, no earlier than the first billing cycle of January 2017. Additionally, any NEIL proceeds received after the settlement will be applied first to replacement power costs incurred after December 31,2012, with the remainder used to write down the remaining CR3 investments.

Base Rates, Customer Refund and Other Terms

Under the terms of the 2012 settlement agreement, PEF will maintain base rates at the current levels through the last billing cycle of December 2016, except as described as follows. The agreement provides for a $150 million annual increase in revenue requirements effective with the first billing cycle of January 2013, while maintaining the current ROE range of 9.5 percent to11.5 percent. PEF suspended depreciation expense and reversed certain regulatory liabilities associated with CR3 effective on the February 22, 2012 implementation date of the agreement, resulting in a $47 million benefit for the quarter ended March 31, 2012, which reducedO&Mexpense. Additionally, rate base associated with CR3 investments will be removed from retail rate base effective with the first billing cycle of January 2013. PEF will accrue, for future rate-setting purposes, a carrying charge at a rate of 7.4 percent on the CR3 investment until CR3 is returned to service and placed back into retail rate base. Upon return of CR3 to commercial service, PEF will be authorized to increase its base rates for the annual revenue requirements of all CR3 investments. The parties to the agreement reserve the right to participate in any hearings challenging the appropriateness of PEF's CR3 revenue requirements. In the month following CR3's return to commercial service, PEF's ROE range will increase to 9.7 percent to 11.7 percent. If PEF's retail base rate earnings fall below the ROE range, as reported on a FPSC-adjusted or pro-forma basis on a PEF monthly earnings surveillance report, PEF may petition the FPSC to amend its base rates during the term of the agreement.

Under the terms of the 2012 settlement agreement, PEF will refund $288 million to customers through the fuel clause. PEF will refund $129 million in each of 2013 and 2014, and an additional $10 million annually to residential and small commercial customers in 2014, 2015 and 2016. At December 31, 2011, a regulatory liability was established for the $288 million to be refunded in future periods. The corresponding charge was recorded as a reduction of 2011 revenues.

The cost of pollution control equipment that PEF installed and has in-service at Crystal River Units 4 and 5 (CR4 and CR5) to comply with the Federal Clean Air Interstate Rule (CAIR) is currently recovered under the Environmental Cost Recovery Clause (ECRC). The 2012 settlement agreement provides for PEF to remove those assets from recovery in the ECRC and transfer those assets to base rates effective with the first billing cycle of January 2014. The related base rate increase will be in addition to the $150 million base rate increase effective January 2013. O&M expense associated with those assets will not be included in the base rates and will continue to be recovered through the ECRC.

The 2012 settlement agreement provides for PEF to continue to recover carrying costs and other nuclear cost recovery clause-recoverable items related to the CR3 uprate project, but PEF will not seek an in-service recovery until nine months following CR3's return to commercial service. Carrying costs will be recovered through the nuclear cost recovery clause until base rates have been increased for these assets.

The 2012 settlement agreement also allows PEF to continue to reduce amortization expense (cost of removal component) beyond the expiration of the 2010 settlement agreement through the term of the 2012 settlement agreement (see “Cost of Removal Reserve”). Additionally, the 2012 settlement agreement extends PEF's ability to expedite recovery of the cost of named storms and to maintain a storm reserve at its level as of the implementation date of the agreement, and removed the maximum allowed monthly surcharge established by the 2010 settlement agreement.

COST OF REMOVAL RESERVE

The 2012 and2010 settlement agreementsprovide PEF the discretion to reduce amortization expense (cost of removal component) by up to the balance in the cost of removal reserve until the earlier of (a) PEF's applicable cost of removal reserve reaches zero, or (b) the expiration of the 2012 settlement agreement at the end of 2016. For the three months ended March 31, 2012, PEF recognized a $58 million reduction in amortization expense pursuant to the settlement agreements. PEF had eligible cost of removal reservesof $216 million remaining at March 31, 2012, whichis impacted by accruals in accordance with PEF's latest depreciation study, removal costs expended and reductions in amortization expense as permitted by the settlement agreements.

NUCLEAR COST RECOVERY

Levy Nuclear

In 2008, the FPSC granted PEF's petition for an affirmative Determination of Need and related orders requesting cost recovery under Florida's nuclear cost-recovery rule for PEF's proposed Levy project, together with the associated facilities, including transmission lines and substation facilities.

On April 30, 2012, as part of PEF's annual nuclear cost recovery filing (see “Cost Recovery”), PEF updated the Levy project schedule and cost. Due to lower-than-projected customer demand, the lingering economic slowdown, uncertainty regarding potential carbon regulation and current, low natural gas prices, PEF is shifting the in-service date for the first Levy unit to 2024, with the second unit following 18 months later. The revised schedule is consistent with the recovery approach included in the 2012 settlement agreement. Although the scope and overnight cost for Levy – including land acquisition, related transmission work and other required investments – remain essentially unchanged, the shift in schedule will increase escalation and carrying costs and raise the total estimated project cost to between $19 billion and $24 billion.

Along with the FPSC's annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to, cost; potential carbon regulation; fossil fuel prices; the benefits of fuel diversification; public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility; DSM and EE programs; and availability and terms of capital financing. Taking into account these criteria, we consider Levy to be PEF's preferred baseload generation option.

CR3 Uprate

In 2007, the FPSC issued an order approving PEF's Determination of Need petition related to a multi-stage uprate of CR3 that will increase CR3's gross output by approximately 180 MW during its next refueling outage. PEF implemented the first-stage design modifications in 2008. The final stage of the uprate required a license amendment to be filed with the NRC, which was filed by PEF in June 2011 and accepted for review by the NRC on November 21, 2011.

Cost Recovery

On April 30, 2012, PEF filed its annual nuclear cost-recovery filing with the FPSC to recover $152 million, which includes recovery of pre-construction and carrying costs and Capacity Cost-Recovery Clause (CCRC) recoverable O&M expense incurred or anticipated to be incurred during 2013, recovery of $88 million of prior years deferrals in 2013, as well as the estimated actual true-up of 2012 costs associated with the CR3 uprate and Levy projects, as permitted by the 2012 settlement agreement. This results in anincrease in the nuclear cost-recovery charge of $2.23 per 1,000 kWh for residential customers, which if approved, would begin with the first January 2013 billing cycle. The FPSC has scheduled hearings in this matter for August 2012, with a decision expected in October 2012. We cannot predict the outcome of this matter.

DEMAND-SIDE MANAGEMENT COST RECOVERY

On July 26, 2011, the FPSC voted to set PEF's DSM compliance goals to remain at their current level until the next goal setting docket is initiated. An intervener filed a protest to the FPSC's Proposed Agency Action order, asserting legal challenges to the order. The parties made legal arguments to the FPSC and the FPSC issued an order denying the protest on December 22, 2011. The intervener then filed a notice of appeal of this order to the Florida Supreme Court on January 17, 2012. We cannot predict the outcome of this matter.

OTHER MATTERS

On March 29, 2012, PEF announced plansto convert the 1,011-MW Anclote Units 1 and 2 (Anclote) from oil and natural gas fired to 100 percent natural gas fired and requested that the FPSC permit recovery of the estimated $79 million conversion cost through the ECRC.PEF believes this conversion is the most cost-effective alternative for Anclote to achieve and maintain compliance with applicable environmental regulations (see Note 13B). PEF anticipates that both converted units will be placed in service by the end of 2013. We cannot predict the outcome of this matter.

PEC

Regulatory Matters Disclosure [Line Items]

Regulatory Matters

5.       REGULATORY MATTERS

On January 8, 2011, Progress Energy and Duke Energy entered into the Merger Agreement. See Note 2 for regulatory information related to the merger with Duke Energy.

A.PEC RETAIL RATE MATTERS

COST RECOVERY FILINGS

On March 1, 2012, PEC filed with the SCPSC for a $5 millionincrease in thedemand-side management (DSM) and energy-efficiency (EE) rate, driven by the introduction of new, and the expansion of existing, DSM and EE programs. If approved, the increase will beeffective July 1, 2012, andwill increase residential electric bills by $1.37 per 1,000 kilowatt-hours (kWh). We cannot predict the outcome of this matter.

PEF

Regulatory Matters Disclosure [Line Items]

Regulatory Matters

5.       REGULATORY MATTERS

On January 8, 2011, Progress Energy and Duke Energy entered into the Merger Agreement. See Note 2 for regulatory information related to the merger with Duke Energy.

B.       PEF RETAIL RATE MATTERS

CR3 OUTAGE

In September 2009, Crystal River Nuclear Plant Unit 3 (CR3) began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete at the periphery of the containment building, which resulted in an extension of the outage. After analysis, PEF determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when PEF created an opening to accommodate the replacement of the unit's steam generators. In March 2011, the work to return the plant to service was suspended after monitoring equipment at the repair site identified a new delamination that occurred in a different section of the outer wall after the repair work was completed and during the late stages of retensioning the containment building. CR3 has remained out of service while PEF conducted an engineering analysis and review of the new delamination and evaluated repair options. Subsequent to March 2011, monitoring equipment has detected additional changes and further damage in the partially tensioned containment building and additional cracking or delaminations could occur during the repair process.

PEF analyzed multiple repair options as well as early decommissioning and believes, based on the information and analyses conducted to date, that repairing the unit is the best option. PEF engaged outside engineering consultants to perform the analysis of possible repair options for the containment building. The consultants analyzed 22 potential repair options and ultimately narrowed those to four. PEF, along with other independent consultants, reviewed the four options for technical issues, constructability, and licensing feasibility as well as cost.

Based on that initial analysis, PEF selected the best repair option, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls. The planned option does not include the area where concrete was replaced during the initial repair. The preliminary cost estimate for this repair as filed with the FPSC on June 27, 2011, is between $900 million and $1.3 billion. Engineering design of the repair is under way. PEF will update the current estimate as this work is completed.

PEF is moving forward systematically and will perform additional detailed engineering analyses and designs, which could affect any repair plan. This process will lead to more certainty for the cost and schedule of the repair. PEF will continue to refine and assess the plan, and the prudence of continuing to pursue it, based on new developments and analyses as the process moves forward. Under this repair plan, PEF estimates that CR3 will return to service in 2014. The decision related to repairing or decommissioning CR3 is complex and subject to a number of unknown factors, including but not limited to, the cost of repair and the likelihood of obtaining NRC approval to restart CR3 after repair. A number of factors could affect the repair plan, the return-to-service date and costs, including regulatory reviews, final engineering designs, contract negotiations, the ultimate work scope completion, testing, weather, the impact of new information discovered during additional testing and analysis and other developments.

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through Nuclear Electric Insurance Limited (NEIL). NEIL has confirmed that the CR3 initial delamination is a covered accidentbut has not yet made a determination as to coverage for the second delamination. Following a 12-week deductible period, the NEIL program provided reimbursement for replacement power costs for 52 weeks at $4.5 million per week, through April 9, 2011. Anadditional 71weeks of coverage, which runs through August 2012, is provided at $3.6 million per week. Accordingly, the NEIL program provides replacement power coverage of up to $490 million per event. Actual replacement power costs have exceeded the insurance coverage through March 31, 2012. PEF anticipates that future replacement power costs will continue to exceed the insurance coverage. PEF also maintains insurance coverage through NEIL's accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim.

PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs. PEF has not yet received a definitive determination from NEIL about the insurance coverage related to the second delamination. In addition, no replacement power reimbursements have been received from NEIL since May 2011. These considerations led us to conclude that it was not probable that NEIL will voluntarily pay the full coverage amounts we believe they owe under the applicable insurance policies. Given the circumstances, accounting standards require full recovery to be probable to recognize an insurance receivable. Therefore, PEF has not recorded insurance receivables from NEIL related to the second delamination. Negotiations continue with NEIL regarding coverage associated with the second delamination, and PEF continues to believe that all applicable costs associated with bringing CR3 back into service are covered under all insurance policies.

The following table summarizes the CR3 replacement power and repair costs and recovery through March 31, 2012:

(in millions)			Replacement Power Costs		Repair Costs
Spent to date			$	506	$	279
NEIL proceeds received to date				(162)		(143)
Insurance receivable at March 31, 2012, net				(55)		0
	Balance for recovery(a)		$	289	$	136
(a)		See "2012 Settlement Agreement" below for discussion of PEF's ability to recover prudently incurred fuel and purchased power costs and CR3 repair costs.

PEFbelieves the actions taken and costs incurred in response to the CR3 delamination have been prudent and, accordingly, considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. Additional replacement power costs and repair and maintenance costs incurred until CR3 is returned to service could be material. Additionally, we cannot be assured that CR3 can be repaired and brought back to service until full engineering and other analyses are completed.

2012 SETTLEMENT AGREEMENT

On February 22, 2012, the FPSC approved a comprehensive settlement agreement among PEF, the Florida Office of Public Counsel and other consumer advocates. The 2012 settlement agreement will continue through the last billing cycle of December 2016. The agreement addresses three principal matters: PEF's proposed Levy Nuclear Power Plant (Levy) Nuclear Project cost recovery, the CR3 delamination prudence review then pending before the FPSC, and certain base rate issues. When all of the settlement provisions are factored in, the total increase in 2013 for residential customer bills will be approximately $4.93 per 1,000 kWh, or 4 percent.

Levy

Under the terms of the 2012 settlement agreement, PEF will set the residential cost-recovery factor of PEF's proposed two units at Levy (see “Nuclear Cost Recovery – Levy Nuclear”) at $3.45 per 1,000 kWh effective in the first billing cycle of January 2013 and continuing for a five-year period. PEF will not recover any additional Levy costs from customers through the term of the agreement, or file for any additional recovery before March 1, 2017, unless otherwise agreed to by the parties to the agreement. This amount is intended to recover the estimated retail project costs to date plus costs necessary to obtain the combined license (COL) and any engineering, procurement and construction (EPC) cancellation costs, if PEF ultimately chooses to cancel that contract. In addition, the consumer parties will not oppose PEF continuing to pursue a COL for Levy. After the five-year period, PEF will true up any actual costs not recovered under the Levy cost-recovery factor.

The 2012 settlement agreement also provides that PEF will treat the allocated wholesale cost of Levy as a retail regulatory asset and include this asset as a component of rate base and amortization expense for regulatory reporting. PEF will have the discretion to accelerate and/or suspend such amortization in full or in part provided that PEF amortizes all of the regulatory asset by December 31, 2016.

CR3

Under the terms of the 2012 settlement agreement, PEF will be permitted to recover prudently incurred fuel and purchased power costs through the fuel clause without regard for the absence of CR3 for the period from the beginning of the CR3 outage through the earlier of the term of the agreement or the return of CR3 to commercial service. If PEF does not begin repairs of CR3 prior to the end of 2012, PEF will refund replacement power costs on a pro rata basis based on the in-service date of up to $40 million in 2015 and $60 million in 2016. The parties to the agreement waive their right to challenge PEF's recovery of replacement power costs. The parties to the agreement maintain the right to challenge the prudence and reasonableness of PEF's fuel acquisition and power purchases, and other fuel prudence issues unrelated to the CR3 outage. All prudence issues from the steam generator project inception through the date of settlement approval by the FPSC are resolved.

To the extent that PEF pursues the repair of CR3, PEF will establish an estimated cost and repair schedule with ongoing consultation with the parties to the agreement. The established cost, to be approved by our board of directors, will be the basis for project measurement. If costs exceed the board-approved estimate, overruns will be split evenly between our shareholders and PEF customers up to $400 million. The parties to the agreement agree to discuss the method of recovery of any overruns in excess of $400 million, with final decision by the FPSC if resolution cannot be reached. If the repairs begin prior to the end of 2012, the parties to the agreement waive their rights to challenge PEF's decision to repair and the repair plan chosen by PEF. In addition, there will be limited rights to challenge recovery of the repair execution costs incurred prior to the final resolution on NEIL coverage. The parties to the agreement will discuss the treatment of any potential gap between NEIL repair coverage and the estimated cost, with final decision by the FPSC if resolution cannot be reached. If the repairs do not begin prior to the end of 2012, the parties to the agreement reserve the right to challenge the prudence of PEF's repair decision, plan and implementation.

PEF also retains sole discretion and flexibility to retire the unit without challenge from the parties to the agreement. If PEF decides to retire CR3, PEF is allowed to recover all remaining CR3 investments and to earn a return on the CR3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity (ROE) set at 70 percent of the current FPSC-authorized ROE, no earlier than the first billing cycle of January 2017. Additionally, any NEIL proceeds received after the settlement will be applied first to replacement power costs incurred after December 31,2012, with the remainder used to write down the remaining CR3 investments.

Base Rates, Customer Refund and Other Terms

Under the terms of the 2012 settlement agreement, PEF will maintain base rates at the current levels through the last billing cycle of December 2016, except as described as follows. The agreement provides for a $150 million annual increase in revenue requirements effective with the first billing cycle of January 2013, while maintaining the current ROE range of 9.5 percent to11.5 percent. PEF suspended depreciation expense and reversed certain regulatory liabilities associated with CR3 effective on the February 22, 2012 implementation date of the agreement, resulting in a $47 million benefit for the quarter ended March 31, 2012, which reducedO&Mexpense. Additionally, rate base associated with CR3 investments will be removed from retail rate base effective with the first billing cycle of January 2013. PEF will accrue, for future rate-setting purposes, a carrying charge at a rate of 7.4 percent on the CR3 investment until CR3 is returned to service and placed back into retail rate base. Upon return of CR3 to commercial service, PEF will be authorized to increase its base rates for the annual revenue requirements of all CR3 investments. The parties to the agreement reserve the right to participate in any hearings challenging the appropriateness of PEF's CR3 revenue requirements. In the month following CR3's return to commercial service, PEF's ROE range will increase to 9.7 percent to 11.7 percent. If PEF's retail base rate earnings fall below the ROE range, as reported on a FPSC-adjusted or pro-forma basis on a PEF monthly earnings surveillance report, PEF may petition the FPSC to amend its base rates during the term of the agreement.

Under the terms of the 2012 settlement agreement, PEF will refund $288 million to customers through the fuel clause. PEF will refund $129 million in each of 2013 and 2014, and an additional $10 million annually to residential and small commercial customers in 2014, 2015 and 2016. At December 31, 2011, a regulatory liability was established for the $288 million to be refunded in future periods. The corresponding charge was recorded as a reduction of 2011 revenues.

The cost of pollution control equipment that PEF installed and has in-service at Crystal River Units 4 and 5 (CR4 and CR5) to comply with the Federal Clean Air Interstate Rule (CAIR) is currently recovered under the Environmental Cost Recovery Clause (ECRC). The 2012 settlement agreement provides for PEF to remove those assets from recovery in the ECRC and transfer those assets to base rates effective with the first billing cycle of January 2014. The related base rate increase will be in addition to the $150 million base rate increase effective January 2013. O&M expense associated with those assets will not be included in the base rates and will continue to be recovered through the ECRC.

The 2012 settlement agreement provides for PEF to continue to recover carrying costs and other nuclear cost recovery clause-recoverable items related to the CR3 uprate project, but PEF will not seek an in-service recovery until nine months following CR3's return to commercial service. Carrying costs will be recovered through the nuclear cost recovery clause until base rates have been increased for these assets.

The 2012 settlement agreement also allows PEF to continue to reduce amortization expense (cost of removal component) beyond the expiration of the 2010 settlement agreement through the term of the 2012 settlement agreement (see “Cost of Removal Reserve”). Additionally, the 2012 settlement agreement extends PEF's ability to expedite recovery of the cost of named storms and to maintain a storm reserve at its level as of the implementation date of the agreement, and removed the maximum allowed monthly surcharge established by the 2010 settlement agreement.

COST OF REMOVAL RESERVE

The 2012 and2010 settlement agreementsprovide PEF the discretion to reduce amortization expense (cost of removal component) by up to the balance in the cost of removal reserve until the earlier of (a) PEF's applicable cost of removal reserve reaches zero, or (b) the expiration of the 2012 settlement agreement at the end of 2016. For the three months ended March 31, 2012, PEF recognized a $58 million reduction in amortization expense pursuant to the settlement agreements. PEF had eligible cost of removal reservesof $216 million remaining at March 31, 2012, whichis impacted by accruals in accordance with PEF's latest depreciation study, removal costs expended and reductions in amortization expense as permitted by the settlement agreements.

NUCLEAR COST RECOVERY

Levy Nuclear

In 2008, the FPSC granted PEF's petition for an affirmative Determination of Need and related orders requesting cost recovery under Florida's nuclear cost-recovery rule for PEF's proposed Levy project, together with the associated facilities, including transmission lines and substation facilities.

On April 30, 2012, as part of PEF's annual nuclear cost recovery filing (see “Cost Recovery”), PEF updated the Levy project schedule and cost. Due to lower-than-projected customer demand, the lingering economic slowdown, uncertainty regarding potential carbon regulation and current, low natural gas prices, PEF is shifting the in-service date for the first Levy unit to 2024, with the second unit following 18 months later. The revised schedule is consistent with the recovery approach included in the 2012 settlement agreement. Although the scope and overnight cost for Levy – including land acquisition, related transmission work and other required investments – remain essentially unchanged, the shift in schedule will increase escalation and carrying costs and raise the total estimated project cost to between $19 billion and $24 billion.

Along with the FPSC's annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to, cost; potential carbon regulation; fossil fuel prices; the benefits of fuel diversification; public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility; DSM and EE programs; and availability and terms of capital financing. Taking into account these criteria, we consider Levy to be PEF's preferred baseload generation option.

CR3 Uprate

In 2007, the FPSC issued an order approving PEF's Determination of Need petition related to a multi-stage uprate of CR3 that will increase CR3's gross output by approximately 180 MW during its next refueling outage. PEF implemented the first-stage design modifications in 2008. The final stage of the uprate required a license amendment to be filed with the NRC, which was filed by PEF in June 2011 and accepted for review by the NRC on November 21, 2011.

Cost Recovery

On April 30, 2012, PEF filed its annual nuclear cost-recovery filing with the FPSC to recover $152 million, which includes recovery of pre-construction and carrying costs and Capacity Cost-Recovery Clause (CCRC) recoverable O&M expense incurred or anticipated to be incurred during 2013, recovery of $88 million of prior years deferrals in 2013, as well as the estimated actual true-up of 2012 costs associated with the CR3 uprate and Levy projects, as permitted by the 2012 settlement agreement. This results in anincrease in the nuclear cost-recovery charge of $2.23 per 1,000 kWh for residential customers, which if approved, would begin with the first January 2013 billing cycle. The FPSC has scheduled hearings in this matter for August 2012, with a decision expected in October 2012. We cannot predict the outcome of this matter.

DEMAND-SIDE MANAGEMENT COST RECOVERY

On July 26, 2011, the FPSC voted to set PEF's DSM compliance goals to remain at their current level until the next goal setting docket is initiated. An intervener filed a protest to the FPSC's Proposed Agency Action order, asserting legal challenges to the order. The parties made legal arguments to the FPSC and the FPSC issued an order denying the protest on December 22, 2011. The intervener then filed a notice of appeal of this order to the Florida Supreme Court on January 17, 2012. We cannot predict the outcome of this matter.

OTHER MATTERS

On March 29, 2012, PEF announced plansto convert the 1,011-MW Anclote Units 1 and 2 (Anclote) from oil and natural gas fired to 100 percent natural gas fired and requested that the FPSC permit recovery of the estimated $79 million conversion cost through the ECRC.PEF believes this conversion is the most cost-effective alternative for Anclote to achieve and maintain compliance with applicable environmental regulations (see Note 13B). PEF anticipates that both converted units will be placed in service by the end of 2013. We cannot predict the outcome of this matter.

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Risk Management Activities and Derivative Transactions (Tables)

3 Months Ended

Mar. 31, 2012

Risk Management Activities And Derivative Transactions Tables [Abstract]

Fair value of derivative instruments

The following table presents the fair value of derivative instruments at March 31, 2012 and December 31, 2011:
Instrument / Balance sheet location				March 31, 2012				December 31, 2011
(in millions)			Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity cash flow derivatives
	Derivative liabilities, current				$	2			$	2
	Derivative liabilities, long-term					1				1
Interest rate derivatives
	Derivative liabilities, current					42				76
	Derivative liabilities, long-term					7				17
		Total derivatives designated as hedging instruments				52				96
Derivatives not designated as hedging instruments
Commodity derivatives(a)
	Prepayments and other current assets		$	7			$	5
	Other assets and deferred debits			1				-
	Derivative liabilities, current					439				357
	Derivative liabilities, long-term					354				332
CVOs(b)
	Other current liabilities					-				14
	Other liabilities and deferred credits					3				-
		Fair value of derivatives not designated as hedging instruments		8		796		5		703
Fair value loss transition adjustment
	Derivative liabilities, current					1				1
	Derivative liabilities, long-term					2				2
		Total derivatives not designated as hedging instruments		8		799		5		706
		Total derivatives	$	8	$	851	$	5	$	802
(a)	Substantially all of these contracts receive regulatory treatment.
(b)	As discussed in Note 16 in the 2011 Form 10-K, the Parent issued 98.6 million CVOs in connection with the acquisition of Florida Progress during 2000. Through a negotiated settlement agreement and subsequent tender offer between October 2011 and February 2012, we repurchased and continue to hold 83.4 million CVOs.

Effect of derivative instruments on other comprehensive income - derivatives designated as hedging instruments

The following tables present the effect of derivative instruments on the Consolidated Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011:
Derivatives Designated as Hedging Instruments
Instrument		Amount of Gain or (Loss) Recognized in OCI, Net of Tax on Derivatives(a)				Amount of Gain or (Loss), Net of Tax Reclassified from Accumulated OCI into Income(a)				Amount of Pre-tax Gain or (Loss) Recognized in Income on Derivatives(b)
(in millions)			2012		2011		2012		2011		2012		2011
Interest rate derivatives(c) (d)		$	2	$	2	$	(3)	$	(1)	$	-	$	(1)
(a)	Effective portion.
(b)	Related to ineffective portion and amount excluded from effectiveness testing.
(c)	Amounts in accumulated OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The effective portion of the hedges will be amortized to interest expense over the term of the related debt.
(d)	Amounts recorded on the Consolidated Statements of Comprehensive Income are classified in interest charges.

Effect of derivative instruments on regulatory assets and liabilities - derivatives not designated as hedging instruments

Derivatives Not Designated as Hedging Instruments
Instrument		Realized Gain or (Loss)(a)				Unrealized Gain or (Loss)(b)
(in millions)			2012		2011		2012		2011
Commodity derivatives		$	(105)	$	(52)	$	(206)	$	23
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts are recorded in regulatory liabilities and assets, respectively, on the Consolidated Balance Sheets until derivatives are settled.

Effect of derivative instruments on income - derivatives not designated as hedging instruments

Instrument		Amount of Gain or (Loss) Recognized in Income on Derivatives
(in millions)			2012		2011
CVOs(a)		$	8	$	-
(a)	Amounts recorded in the Consolidated Statements of Comprehensive Income are classified in other, net.

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Fair Value Disclosures - (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Additional Fair Value Elements [Line Items]
Carrying amount of long term debt including current maturities	$ 13,390,000,000		$ 12,941,000,000
Schedule Of Available For Sale Securities [Line Items]
Fair Value	1,765,000,000		1,630,000,000
Unrealized Losses	19,000,000		31,000,000
Unrealized Gains	551,000,000		444,000,000
Aggregate fair value of investments related to unrealized losses
Aggregate fair value of investments related to unrealized losses	155,000,000		136,000,000
Fair value of available for sale debt securities by contractual maturity
Due in one year or less	34,000,000
Due after one through five years	217,000,000
Due after five through 10 years	175,000,000
Due after 10 years	94,000,000
Total	520,000,000
Sales of available for sale securities
Proceeds	304,000,000	1,744,000,000
Realized gains	7,000,000	9,000,000
Realized losses	3,000,000	4,000,000
Nuclear decommissioning trust funds
Common stock equity	1,160,000,000		1,033,000,000
Preferred stock and other equity	43,000,000		29,000,000
Corporate debt	90,000,000		86,000,000
U.S. state and municipal debt	124,000,000		128,000,000
U.S. and foreign government debt	293,000,000		284,000,000
Money market funds and other	52,000,000		87,000,000
Total nuclear decommissioning trust funds	1,762,000,000		1,647,000,000
Derivatives
Commodity forward contracts	8,000,000		5,000,000
Other marketable securities
Money market and other	18,000,000		20,000,000
Total assets	1,788,000,000		1,672,000,000
Derivatives
Commodity forward contracts	796,000,000		692,000,000
Interest rate contracts	49,000,000		93,000,000
Contingent value obligations derivatives	3,000,000		14,000,000
Total liabilities	848,000,000		799,000,000
Common Stock Outstanding - Amount
Schedule Of Available For Sale Securities [Line Items]
Fair Value	1,160,000,000		1,033,000,000
Unrealized Losses	16,000,000		29,000,000
Unrealized Gains	508,000,000		401,000,000
Preferred stock and other equity
Schedule Of Available For Sale Securities [Line Items]
Fair Value	43,000,000		29,000,000
Unrealized Gains	14,000,000		11,000,000
Corporate debt
Schedule Of Available For Sale Securities [Line Items]
Fair Value	90,000,000		86,000,000
Unrealized Gains	7,000,000		6,000,000
U.S. state and municipal debt
Schedule Of Available For Sale Securities [Line Items]
Fair Value	124,000,000		128,000,000
Unrealized Losses	2,000,000		2,000,000
Unrealized Gains	7,000,000		7,000,000
U.S. and foreign government debt
Schedule Of Available For Sale Securities [Line Items]
Fair Value	293,000,000		284,000,000
Unrealized Gains	14,000,000		18,000,000
Money market funds and other securities
Schedule Of Available For Sale Securities [Line Items]
Fair Value	55,000,000		70,000,000
Unrealized Losses	1,000,000
Unrealized Gains	1,000,000		1,000,000
Level 1
Nuclear decommissioning trust funds
Common stock equity	1,160,000,000		1,033,000,000
Preferred stock and other equity	33,000,000		28,000,000
U.S. and foreign government debt	129,000,000		87,000,000
Money market funds and other	1,000,000
Total nuclear decommissioning trust funds	1,323,000,000		1,148,000,000
Other marketable securities
Money market and other	18,000,000		20,000,000
Total assets	1,341,000,000		1,168,000,000
Level 2
Additional Fair Value Elements [Line Items]
Long-term Debt, Fair Value	15,400,000,000		15,300,000,000
Nuclear decommissioning trust funds
Preferred stock and other equity	10,000,000		1,000,000
Corporate debt	90,000,000		86,000,000
U.S. state and municipal debt	124,000,000		128,000,000
U.S. and foreign government debt	164,000,000		197,000,000
Money market funds and other	51,000,000		87,000,000
Total nuclear decommissioning trust funds	439,000,000		499,000,000
Derivatives
Commodity forward contracts	8,000,000		5,000,000
Other marketable securities
Total assets	447,000,000		504,000,000
Derivatives
Commodity forward contracts	769,000,000		668,000,000
Interest rate contracts	49,000,000		93,000,000
Contingent value obligations derivatives	3,000,000		14,000,000
Total liabilities	821,000,000		775,000,000
Level 3
Derivatives
Commodity forward contracts	27,000,000		24,000,000
Total liabilities	27,000,000		24,000,000
Fair value hierarchy
Derivatives, net at beginning of period	24,000,000	36,000,000
Deferred as regulatory assets and liabilities, net	3,000,000	(4,000,000)
Derivatives, net at end of period	$ 27,000,000	$ 32,000,000
Level 3 | Derivative financial instruments, liabilities | Maximum
Fair Value Inputs Liabilities Quantitative Information [Line Items]
Fair value inputs, price per MMBtu	4.528
Level 3 | Derivative financial instruments, liabilities | Minimum
Fair Value Inputs Liabilities Quantitative Information [Line Items]
Fair value inputs, price per MMBtu	4.111

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Condensed Consolidating Statements

3 Months Ended

Mar. 31, 2012

Condensed Consolidating Statements Disclosure [Abstract]

Condensed consolidating financials

15.CONDENSED CONSOLIDATING STATEMENTS

As discussed in Note 23 in the 2011 Form 10-K, we have guaranteed certain payments of two 100 percent owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.). Our guarantees are joint and several, full and unconditional and are in addition to the joint and several, full and unconditional guarantees 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 12B in the 2011 Form 10-K, there were no restrictions on PEC's or PEF's retained earnings.

The Trust is a VIE of which we are not the primary beneficiary. Separate financial statements and other disclosures concerning the Trust have not been presented because we believe that such information is not material to investors.

Presented below are the condensed consolidating Statements of Comprehensive Income, Balance Sheets and Cash Flows as required by Rule 3-10 of Regulation S-X. In these condensed consolidating statements, the Parent column includes the financial results of the parent holding company only. The Subsidiary Guarantor column includes the consolidated financial results of Florida Progress only, which is primarily comprised of its wholly owned subsidiary PEF. The Non-guarantor Subsidiaries column includes the consolidated financial results of all non-guarantor subsidiaries, which is primarily comprised of our wholly owned subsidiary PEC. The Other column includes elimination entries for all intercompany transactions and other consolidation adjustments. Financial statements for PEC and PEF are separately presented elsewhere in this Form 10-Q. All applicable corporate expenses have been allocated appropriately among the guarantor and non-guarantor subsidiaries. The financial information may not necessarily be indicative of results of operations or financial position had the Subsidiary Guarantor or other non-guarantor subsidiaries operated as independent entities.

Condensed Consolidating Statement of Comprehensive Income
Three months ended March 31, 2012
(in millions)			Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
Operating revenues
	Operating revenues		$	-	$	1,007	$	1,085	$	-		$	2,092
	Affiliate revenues			-		-		59		(59)			-
		Total operating revenues		-		1,007		1,144		(59)			2,092
Operating expenses
	Fuel used in electric generation			-		336		349		-			685
	Purchased power			-		145		65		-			210
	Operation and maintenance			1		160		422		(54)			529
	Depreciation, amortization and accretion			-		27		139		-			166
	Taxes other than on income			-		82		58		(2)			138
		Total operating expenses		1		750		1,033		(56)			1,728
Operating (loss) income				(1)		257		111		(3)			364
Other income (expense)
	Interest income			1		-		-		-			1
	Allowance for equity funds used during construction			-		9		15		-			24
	Other, net			8		1		2		2			13
		Total other income, net		9		10		17		2			38
Interest charges
	Interest charges			66		73		55		-			194
	Allowance for borrowed funds used during construction			-		(4)		(5)		-			(9)
		Total interest charges, net		66		69		50		-			185
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries				(58)		198		78		(1)			217
Income tax (benefit) expense				(22)		73		27		(2)			76
Equity in earnings of consolidated subsidiaries				186		-		-		(186)			-
Income from continuing operations				150		125		51		(185)			141
Discontinued operations, net of tax				-		11		-		-			11
Net income				150		136		51		(185)			152
Net income attributable to noncontrolling interests, net of tax				-		(1)		-		(1)			(2)
Net income attributable to controlling interests			$	150	$	135	$	51	$	(186)		$	150
Comprehensive income
	Comprehensive income		$	155	$	137	$	55	$	(190)		$	157
	Comprehensive income attributable to noncontrolling interests, net of tax			-		(1)		-		(1)			(2)
		Comprehensive income attributable to controlling interests	$	155	$	136	$	55	$	(191)		$	155

Condensed Consolidating Statement of Comprehensive Income
Three months ended March 31, 2011
(in millions)			Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
Operating revenues
	Operating revenues		$	-	$	1,034	$	1,133	$	-		$	2,167
	Affiliate revenues			-		-		74		(74)			-
		Total operating revenues		-		1,034		1,207		(74)			2,167
Operating expenses
	Fuel used in electric generation			-		355		363		-			718
	Purchased power			-		153		67		-			220
	Operation and maintenance			3		211		351		(71)			494
	Depreciation, amortization and accretion			-		25		129		-			154
	Taxes other than on income			-		85		59		(4)			140
	Other			-		(10)		-		-			(10)
		Total operating expenses		3		819		969		(75)			1,716
Operating (loss) income				(3)		215		238		1			451
Other income (expense)
	Interest income			-		1		-		-			1
	Allowance for equity funds used during construction			-		9		20		-			29
	Other, net			-		5		(2)		-			3
		Total other income, net		-		15		18		-			33
Interest charges
	Interest charges			73		75		51		-			199
	Allowance for borrowed funds used during construction			-		(4)		(5)		-			(9)
		Total interest charges, net		73		71		46		-			190
(Loss) income from continuing operations before income tax and equity in earnings of consolidated subsidiaries				(76)		159		210		1			294
Income tax (benefit) expense				(31)		60		80		(2)			107
Equity in earnings of consolidated subsidiaries				229		-		-		(229)			-
Income from continuing operations before cumulative effect of change in accounting principle				184		99		130		(226)			187
Discontinued operations, net of tax				-		(1)		(1)		-			(2)
Net income				184		98		129		(226)			185
Net (income) loss attributable to noncontrolling interests, net of tax				-		(1)		-		-			(1)
Net income attributable to controlling interests			$	184	$	97	$	129	$	(226)		$	184
Comprehensive income
	Comprehensive income		$	188	$	99	$	132	$	(230)		$	189
	Comprehensive income attributable to noncontrolling interests			-		(1)		-		-			(1)
		Comprehensive income attributable to controlling interests	$	188	$	98	$	132	$	(230)		$	188

Condensed Consolidating Balance Sheet
March 31, 2012
(in millions)			Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
ASSETS
Utility plant, net			$	-	$	10,596	$	12,124	$	85	$	22,805
Current assets
	Cash and cash equivalents			511		33		21		-		565
	Receivables, net			-		346		412		-		758
	Notes receivable from affiliated companies			63		7		172		(242)		-
	Regulatory assets			-		225		25		-		250
	Derivative collateral posted			-		136		30		-		166
	Prepayments and other current assets			135		960		1,134		(133)		2,096
		Total current assets		709		1,707		1,794		(375)		3,835
Deferred debits and other assets
	Investment in consolidated subsidiaries			13,968		-		-		(13,968)		-
	Regulatory assets			-		1,659		1,464		-		3,123
	Goodwill			-		-		-		3,655		3,655
	Nuclear decommissioning trust funds			-		599		1,163		-		1,762
	Other assets and deferred debits			116		255		869		(445)		795
		Total deferred debits and other assets		14,084		2,513		3,496		(10,758)		9,335
		Total assets	$	14,793	$	14,816	$	17,414	$	(11,048)	$	35,975
CAPITALIZATION AND LIABILITIES
Equity
	Common stock equity		$	10,009	$	4,759	$	5,536	$	(10,295)	$	10,009
	Noncontrolling interests			-		2		-		-		2
		Total equity		10,009		4,761		5,536		(10,295)		10,011
	Preferred stock of subsidiaries			-		34		59		-		93
	Long-term debt, affiliate			-		309		-		(36)		273
	Long-term debt, net			3,992		4,057		3,693		-		11,742
		Total capitalization		14,001		9,161		9,288		(10,331)		22,119
Current liabilities
	Current portion of long-term debt			450		425		500		-		1,375
	Short-term debt			255		360		441		-		1,056
	Notes payable to affiliated companies			-		198		44		(242)		-
	Derivative liabilities			-		335		149		-		484
	Other current liabilities			65		836		1,084		(138)		1,847
		Total current liabilities		770		2,154		2,218		(380)		4,762
Deferred credits and other liabilities
	Noncurrent income tax liabilities			-		990		2,062		(415)		2,637
	Regulatory liabilities			-		967		1,632		85		2,684
	Other liabilities and deferred credits			22		1,544		2,214		(7)		3,773
		Total deferred credits and other liabilities		22		3,501		5,908		(337)		9,094
		Total capitalization and liabilities	$	14,793	$	14,816	$	17,414	$	(11,048)	$	35,975

Condensed Consolidating Balance Sheet
December 31, 2011
(in millions)			Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
ASSETS
Utility plant, net			$	-	$	10,523	$	11,887	$	87	$	22,497
Current assets
	Cash and cash equivalents			117		92		21		-		230
	Receivables, net			-		372		517		-		889
	Notes receivable from affiliated companies			53		-		219		(272)		-
	Regulatory assets			-		244		31		-		275
	Derivative collateral posted			-		123		24		-		147
	Prepayments and other current assets			128		852		1,049		(87)		1,942
		Total current assets		298		1,683		1,861		(359)		3,483
Deferred debits and other assets
	Investment in consolidated subsidiaries			14,043		-		-		(14,043)		-
	Regulatory assets			-		1,602		1,423		-		3,025
	Goodwill			-		-		-		3,655		3,655
	Nuclear decommissioning trust funds			-		559		1,088		-		1,647
	Other assets and deferred debits			140		242		856		(486)		752
		Total deferred debits and other assets		14,183		2,403		3,367		(10,874)		9,079
		Total assets	$	14,481	$	14,609	$	17,115	$	(11,146)	$	35,059
CAPITALIZATION AND LIABILITIES
Equity
	Common stock equity		$	10,021	$	4,728	$	5,646	$	(10,374)	$	10,021
	Noncontrolling interests			-		4		-		-		4
		Total equity		10,021		4,732		5,646		(10,374)		10,025
	Preferred stock of subsidiaries			-		34		59		-		93
	Long-term debt, affiliate			-		309		-		(36)		273
	Long-term debt, net			3,543		4,482		3,693		-		11,718
		Total capitalization		13,564		9,557		9,398		(10,410)		22,109
Current liabilities
	Current portion of long-term debt			450		-		500		-		950
	Short-term debt			250		233		188		-		671
	Notes payable to affiliated companies			-		238		34		(272)		-
	Derivative liabilities			38		268		130		-		436
	Other current liabilities			161		839		1,112		(84)		2,028
		Total current liabilities		899		1,578		1,964		(356)		4,085
Deferred credits and other liabilities
	Noncurrent income tax liabilities			-		837		1,976		(458)		2,355
	Regulatory liabilities			-		1,071		1,543		86		2,700
	Other liabilities and deferred credits			18		1,566		2,234		(8)		3,810
		Total deferred credits and other liabilities		18		3,474		5,753		(380)		8,865
		Total capitalization and liabilities	$	14,481	$	14,609	$	17,115	$	(11,146)	$	35,059

Condensed Consolidating Statement of Cash Flows
Three months ended March 31, 2012
(in millions)	Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
Net cash provided by operating activities	$	227	$	166	$	245	$	(282)	$	356
Investing activities
Gross property additions		-		(197)		(365)		-		(562)
Nuclear fuel additions		-		(13)		(38)		-		(51)
Purchases of available-for-sale securities and other investments		-		(225)		(138)		-		(363)
Proceeds from available-for-sale securities and other investments		-		226		133		-		359
Changes in advances to affiliated companies		(10)		(7)		47		(30)		-
Other investing activities		(14)		15		64		-		65
Net cash used by investing activities		(24)		(201)		(297)		(30)		(552)
Financing activities
Issuance of common stock, net		3		-		-		-		3
Dividends paid on common stock		(260)		-		-		-		(260)
Dividends paid to parent		-		(108)		(175)		283		-
Proceeds from the issuance of short-term debt with original maturities greater than 90 days		-		65		-		-		65
Net increase in short-term debt		5		62		253		-		320
Proceeds from issuance of long-term debt, net		444		-		-		-		444
Changes in advances from affiliated companies		-		(40)		11		29		-
Other financing activities		(1)		(3)		(37)		-		(41)
Net cash provided (used) by financing activities		191		(24)		52		312		531
Net increase (decrease) in cash and cash equivalents		394		(59)		-		-		335
Cash and cash equivalents at beginning of period		117		92		21		-		230
Cash and cash equivalents at end of period	$	511	$	33	$	21	$	-	$	565

Condensed Consolidating Statement of Cash Flows
Three months ended March 31, 2011
(in millions)	Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
Net cash provided by operating activities	$	280	$	257	$	337	$	(428)	$	446
Investing activities
Gross property additions		-		(218)		(283)		-		(501)
Nuclear fuel additions		-		(7)		(50)		-		(57)
Purchases of available-for-sale securities and other investments		-		(1,661)		(156)		-		(1,817)
Proceeds from available-for-sale securities and other investments		-		1,661		148		-		1,809
Changes in advances to affiliated companies		(75)		21		42		12		-
Contributions to consolidated subsidiaries		(10)		-		-		10		-
Other investing activities		-		43		5		(2)		46
Net cash used by investing activities		(85)		(161)		(294)		20		(520)
Financing activities
Issuance of common stock, net		8		-		-		-		8
Dividends paid on common stock		(183)		-		-		-		(183)
Dividends paid to parent		-		(328)		(100)		428		-
Net increase in short-term debt		79		-		-		-		79
Proceeds from issuance of long-term debt, net		494		-		-		-		494
Retirement of long-term debt		(700)		-		-		-		(700)
Changes in advances from affiliated companies		-		11		-		(11)		-
Contributions from parent		-		10		-		(10)		-
Other financing activities		-		(4)		(60)		1		(63)
Net cash used by financing activities		(302)		(311)		(160)		408		(365)
Net decrease in cash and cash equivalents		(107)		(215)		(117)		-		(439)
Cash and cash equivalents at beginning of period		110		270		231		-		611
Cash and cash equivalents at end of period	$	3	$	55	$	114	$	-	$	172