10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 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:   (704) 382-3853 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:   (704) 382-3853 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:   (704) 382-3853 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 November 5, 2012, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy	Common Stock (Par Value $0.01)	100 (all of which were held directly by Duke Energy Corporation)
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 Energy 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.

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

TABLE OF CONTENTS
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS		2
PART I.  FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS	4
	Unaudited Condensed Interim Financial Statements
	Progress Energy, Inc. (Progress Energy)
	Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income	4
	Unaudited Condensed Consolidated Balance Sheets	5
	Unaudited Condensed Consolidated Statements of Cash Flows	6
	Unaudited Consolidated Statements of Changes in Total Equity	7
	Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC)
	Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income	8
	Unaudited Condensed Consolidated Balance Sheets	9
	Unaudited Condensed Consolidated Statements of Cash Flows	10
	Unaudited Consolidated Statements of Changes in Total Equity	11
	Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF)
	Unaudited Condensed Statements of Operations and Comprehensive Income	12
	Unaudited Condensed Balance Sheets	13
	Unaudited Condensed Statements of Cash Flows	14
	Unaudited Statements of Changes in Total Equity	15
	Combined Notes to Unaudited Condensed Interim Financial Statements
	Note 1   – Organization and Summary of Significant Accounting Policies	16
	Note 2   – Merger and Sales of Other Assets	18
	Note 3   – Financial Information by Business Segment	21
	Note 4   – Regulatory Matters	23
	Note 5   – Commitments and Contingencies	30
	Note 6   – Debt and Credit Facilities	36
	Note 7   – Goodwill	38
	Note 8   – Risk Management Activities and Derivatives Transactions	38
	Note 9   – Fair Value of Financial Assets and Liabilities	48
	Note 10 – Investments in Debt and Equity Securities	52
	Note 11 – Variable Interest Entities	57
	Note 12 – Benefit Plans	58
	Note 13 – Severance	62
	Note 14 – Income Taxes	63
	Note 15 – Related Party Transactions	64
	Note 16 – New Accounting Standards	65
	Note 17 – Condensed Consolidating Statements	66
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	75
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	90
ITEM 4.	CONTROLS AND PROCEDURES	91
PART II.  OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	91
ITEM 1A.	RISK FACTORS	91
ITEM 6.	EXHIBITS	92
SIGNATURES		94

1

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management’s beliefs and assumptions. These forward-looking statements, which are intended to cover the applicable Progress Energy Registrants, are identified by terms and phrases such as “anticipate,” “believe,” “intend,” “estimate,” “expect,” “continue,” “should,” “could,” “may,” “plan,” “project,” “predict,” “will,” “potential,” “forecast,” “target,” “guidance,” “outlook,” and similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

·   State and federal legislative and regulatory initiatives, including costs of compliance with existing and future environmental requirements, as well as rulings that affect cost and investment recovery or have an impact on rate structures;

·   The ability to recover eligible costs and earn an adequate return on investment through the regulatory process;

·   The scope of necessary repairs of the delamination of Crystal River Unit 3 Nuclear Plant (CR3) could prove more extensive or costly than is currently identified, such repairs could prove not to be feasible resulting in early retirement of the unit, the cost of repair and/or replacement power could exceed estimates and insurance coverage or may not be recoverable through the regulatory process;

·   The ability to maintain relationships with customers, employees or suppliers post-merger;

·   The ability to successfully integrate with Duke Energy businesses and realize cost savings and any other synergies expected from the merger;

·   The risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect;

·   The impact of compliance with material restrictions of conditions related to the Duke Energy merger imposed by regulators could exceed our expectations;

·   Costs and effects of legal and administrative proceedings, settlements, investigations and claims;

·   Industrial, commercial and residential growth or decline in PEC’s or PEF’s service territories, customer base or customer usage patterns;

·   Additional competition in electric markets and continued industry consolidation;

·   The influence of weather and other natural phenomena on each of PEC’s and PEF’s operations, including the economic, operational and other effects of storms, hurricanes, droughts and tornadoes;

·   The ability to successfully operate electric generating facilities and deliver electricity to customers;

·   The ability to recover, in a timely manner, if at all, costs associated with future significant weather events through the regulatory process;

·   The impact on our facilities and business from a terrorist attack, cyber security threats and other catastrophic events;

·   The inherent risks associated with the operation and potential construction of nuclear facilities, including environmental, health, safety, regulatory and financial risks;

·   The timing and extent of changes in commodity prices and interest rates and the ability to recover such costs through the regulatory process, where appropriate;

·   Unscheduled generation outages, unusual maintenance or repairs and electric transmission system constraints;

·   The results of financing efforts, including the Progress Energy Registrants’ ability to obtain financing on favorable terms, which can be affected by various factors, including the respective Progress Energy Registrants’ credit ratings and general economic conditions;

·   Declines in the market prices of equity securities and resultant cash funding requirements for our defined benefit pension plans and nuclear decommissioning trust funds;

·   The level of creditworthiness of counterparties to our transactions;

·   Employee workforce factors, including the potential inability to attract and retain key personnel;

·   Growth in opportunities for the respective Progress Energy Registrants’ business units;

2

·   Construction and development risks associated with the completion of our capital investment projects in existing and new generation facilities, including risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards, as well as the ability to recover costs from ratepayers in a timely manner or at all;

·   The effect of accounting pronouncements issued periodically by accounting standard-setting bodies; and

·   The impact of potential goodwill impairments.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. The Progress Energy Registrants undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

3

PART I.  FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
September 30, 2012
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of OPERATIONS and COMPREHENSIVE INCOME
	Three months ended September 30						Nine months ended September 30
(in millions)	2012			2011			2012			2011
Operating revenues
Regulated electric	$	2,775		$	2,743		$	7,135		$	7,161
Non-regulated electric and other		13			10			43			35
Total operating revenues		2,788			2,753			7,178			7,196
Operating expenses
Fuel used in electric generation and purchased power		1,396			1,234			3,299			3,186
Operation, maintenance and other		626			494			1,798			1,500
Depreciation and amortization		174			175			571			508
Property and other taxes		160			164			440			437
Impairment charges		55			-			55			-
Total operating expenses		2,411			2,067			6,163			5,631
Gains on sales of other assets and other, net		2			1			4			2
Operating income		379			687			1,019			1,567
Other income and expenses, net		32			(44	)		97			21
Interest expense, net		182			172			560			542
Income from continuing operations before income taxes		229			471			556			1,046
Income tax expense from continuing operations		75			178			193			386
Income from continuing operations		154			293			363			660
Income (loss) from discontinued operations, net of tax		3			-			10			(4	)
Net income		157			293			373			656
Less: net income attributable to noncontrolling interests		2			2			5			5
Net income attributable to Duke Energy Corporation	$	155		$	291		$	368		$	651
Net income amounts attributable to Duke Energy Corporation
Income from continuing operations, net of tax	$	152		$	291		$	358		$	655
Discontinued operations, net of tax		3			-			10			(4	)
Net income attributable to Duke Energy Corporation	$	155		$	291		$	368		$	651
Comprehensive income, net of tax
Comprehensive income	$	255		$	228		$	472		$	574
Comprehensive income attributable to noncontrolling interests,   net of tax		(2	)		(2	)		(5	)		(5	)
Comprehensive income attributable to Duke Energy Corporation	$	253		$	226		$	467		$	569

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

4

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	September 30, 2012			December 31, 2011
ASSETS
Current assets
Cash and cash equivalents	$	57		$	230
Receivables, (net of allowance of $13 at September 30, 2012, and   $27 at December 31, 2011)		930			883
Receivables from affiliated companies		24			-
Inventory		1,366			1,429
Regulatory assets		226			275
Deferred tax assets		326			371
Prepayments and other current assets		97			132
Total current assets		3,026			3,320
Investments and other assets
Nuclear decommissioning trust funds		1,844			1,647
Goodwill		3,655			3,655
Intangibles		30			36
Other		502			468
Total investments and other assets		6,031			5,806
Property, plant and equipment
Cost		36,844			34,797
Cost, variable interest entities		16			16
Accumulated depreciation and amortization		(12,857	)		(12,684	)
Generation facilities to be retired, net		164			163
Net property, plant and equipment		24,167			22,292
Regulatory assets and deferred debits
Regulatory assets		3,331			3,424
Other		96			89
Total regulatory assets and deferred debits		3,427			3,513
Total assets	$	36,651		$	34,931
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	835		$	968
Payables to affiliated companies		29			-
Notes payable and commercial paper		-			671
Notes payable to affiliated companies		635			-
Taxes accrued		233			56
Interest accrued		187			200
Customer deposits		341			340
Derivative liabilities		209			382
Current maturities of long-term debt		838			961
Other		429			441
Total current liabilities		3,736			4,019
Long-term debt		12,664			11,918
Long-term debt, affiliate		274			273
Deferred credits and other liabilities
Deferred income taxes		2,509			2,193
Investment tax credits		97			103
Accrued pension and other post-retirement benefit costs		1,724			1,625
Asset retirement obligations		2,137			1,265
Regulatory liabilities		2,704			2,727
Other		560			690
Total deferred credits and other liabilities		9,731			8,603
Commitments and contingencies
Preferred stock of subsidiaries		93			93
Equity
Common stock $0.01 par value, 100 shares authorized, issued and outstanding at   September 30, 2012; no par value, 500 million shares authorized, 295 million shares    issued and outstanding at December 31, 2011		-			7,418
Additional paid-in capital		7,465			16
Retained earnings		2,751			2,752
Accumulated other comprehensive loss		(66	)		(165	)
Total common shareholders' equity		10,150			10,021
Noncontrolling interests		3			4
Total equity		10,153			10,025
Total liabilities and equity	$	36,651		$	34,931
See Notes to Progress Energy, Inc. Unaudited Condensed Consolidated Interim Financial Statements

5

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Nine months ended September 30	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	373		$	656
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization (including amortization of nuclear fuel)		678			621
Equity component of AFUDC		(77	)		(77	)
Severance expense		39			-
FERC mitigation costs		71			-
Community support and charitable contributions expense		40			-
Amount to be refunded to customers (Note 4B)		100			-
Gains on sales of other assets		(21	)		-
Deferred income taxes		257			430
Contributions to qualified pension plans		(122	)		(313	)
Accrued pension and other post-retirement benefit costs		137			89
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		(12	)		37
Receivables		(97	)		(109	)
Receivables from affiliate		(24	)		-
Inventory		60			(151	)
Other current assets		(6	)		(62	)
Increase (decrease) in
Accounts payable		6			(95	)
Payables to affiliate		29			-
Taxes accrued		175			156
Other current liabilities		(15	)		16
Other assets		-			(48	)
Other liabilities		(141	)		108
Net cash provided by operating activities		1,450			1,258
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(1,695	)		(1,647	)
Purchases of available-for-sale securities		(947	)		(4,537	)
Proceeds from sales and maturities of available-for-sale securities		921			4,509
Insurance proceeds		7			78
Change in restricted cash		24			(7	)
Other		81			29
Net cash used by investing activities		(1,609	)		(1,575	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		1,432			1,286
Issuance of common stock related to employee benefit plans		6			42
Payments for the redemption of long-term debt		(961	)		(1,010	)
Payments of short-term debt with original maturities greater than 90 days		(65	)		-
Proceeds from issuance of short-term debt with original maturities greater than 90 days		65			-
Notes payable and commercial paper		(671	)		45
Distributions to noncontrolling interests		(6	)		(6	)
Dividends paid		(445	)		(550	)
Notes payable to affiliate		635			-
Other		(4	)		2
Net cash used in financing activities		(14	)		(191	)
Net decrease in cash and cash equivalents		(173	)		(508	)
Cash and cash equivalents at beginning of period		230			611
Cash and cash equivalents at end of period	$	57		$	103
Supplemental disclosures
Significant noncash transactions
Accrued capital expenditures	$	250		$	329
Asset retirement obligation additions		813			3
Capital expenditures financed through capital leases		137			-

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

6

PROGRESS ENERGY, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of EQUITY
									Accumulated Other Comprehensive (Loss) Income
(in millions)	Common Stock			Additional Paid-in Capital		Retained Earnings			Net (Losses) Gains on Cash Flow Hedges			Pension and OPEB Related Adjustments			Common Stockholders' Equity			Noncontrolling Interests			Total Equity
Balance, December 31, 2010	$	7,332		$	11	$	2,805		$	(63	)	$	(62	)	$	10,023		$	4		$	10,027
Net income(a)		-			-		651			-			-			651			2			653
Other comprehensive loss		-			-		-			(77	)		(5	)		(82	)		-			(82	)
Issuance of shares		42			-		-			-			-			42			-			42
Stock-based compensation expense		24			4		-			-			-			28			-			28
Dividends declared		-			-		(550	)		-			-			(550	)		-			(550	)
Distributions to noncontrolling interests		-			-		-			-			-			-			(3	)		(3	)
Balance, September 30, 2011	$	7,398		$	15	$	2,906		$	(140	)	$	(67	)	$	10,112		$	3		$	10,115
Balance, December 31, 2011	$	7,418		$	16	$	2,752		$	(143	)	$	(22	)	$	10,021		$	4		$	10,025
Net income(a)		-			-		368			-			-			368			2			370
Other comprehensive income		-			-		-			99			-			99			-			99
Issuance of shares		6			-		-			-			-			6			-			6
Stock-based compensation expense		12			13		-			-			-			25			-			25
Dividends declared		-			-		(369	)		-			-			(369	)		-			(369	)
Distributions to noncontrolling interests		-			-		-			-			-			-			(2	)		(2	)
Issuance of 100 shares of $0.01 par value   common shares to Duke Energy		(7,436	)		7,436		-			-			-			-			-			-
Other		-			-		-			-			-			-			(1	)		(1	)
Balance, September 30, 2012	$	-		$	7,465	$	2,751		$	(44	)	$	(22	)	$	10,150		$	3		$	10,153

(a)

For the nine months ended September 30, 2012, consolidated net income of $373 million includes $3 million attributable to preferred shareholders of subsidiaries. For the nine months ended September 30, 2011, consolidated net income of $656 million includes $3 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.

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

7

CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
September 30, 2012
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of OPERATIONS and COMPREHENSIVE INCOME
	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
Operating revenues
Regulated electric	$	1,394	$	1,330	$	3,561	$	3,524
Non-regulated electric and other		4		1		17		10
Total operating revenues		1,398		1,331		3,578		3,534
Operating expenses
Fuel used in electric generation and purchased power		597		544		1,450		1,382
Operation, maintenance and other		384		273		1,146		863
Depreciation and amortization		131		132		399		383
Property and other taxes		60		58		168		164
Impairment charges		55		-		55		-
Total operating expenses		1,227		1,007		3,218		2,792
Gains on sales of other assets and other, net		1		-		2		1
Operating income		172		324		362		743
Other income and expenses, net		21		16		57		55
Interest expense, net		52		41		156		134
Income before income taxes		141		299		263		664
Income tax expense		45		100		83		227
Net income		96		199		180		437
Less: preferred stock dividend requirement		1		1		2		2
Net income available to parent	$	95	$	198	$	178	$	435
Comprehensive income, net of tax	$	168	$	165	$	251	$	400
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

8

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)	September 30, 2012				December 31, 2011
ASSETS
Current assets
Cash and cash equivalents		$	19			$	20
Receivables, (net of allowance of $8 at September 30, 2012, and   $9 at December 31, 2011)			486				492
Receivables from affiliated companies			11				1
Inventory			749				770
Deferred tax assets			123				142
Prepayments and other current assets			70				84
Total current assets			1,458				1,509
Investments and other assets
Nuclear decommissioning trust funds			1,223				1,088
Other			216				210
Total investments and other assets			1,439				1,298
Property, plant and equipment
Cost			20,841				19,367
Cost, variable interest entities			16				16
Accumulated depreciation and amortization			(8,025	)			(7,991	)
Generation facilities to be retired, net			164				163
Net property, plant and equipment			12,996				11,555
Regulatory assets and deferred debits
Regulatory assets			1,762				1,682
Other			30				22
Total regulatory assets and deferred debits			1,792				1,704
Total Assets		$	17,685			$	16,066
LIABILITIES AND EQUITY
Current liabilities
Accounts payable		$	369			$	518
Payables to affiliated companies			52				29
Notes payable and commercial paper			-				188
Notes payable to affiliated companies			243				31
Taxes accrued			85				23
Interest accrued			71				77
Customer deposits			119				116
Derivative liabilities			79				123
Current maturities of long-term debt			403				502
Other			247				178
Total current liabilities			1,668				1,785
Long-term debt			4,435				3,704
Deferred credits and other liabilities
Deferred income taxes			2,091				1,903
Investment tax credits			94				98
Accrued pension and other post-retirement benefit costs			726				687
Asset retirement obligations			1,623				896
Regulatory liabilities			1,667				1,543
Other			284				303
Total deferred credits and other liabilities			6,485				5,430
Commitments and contingencies
Preferred stock			59				59
Equity
Common stock without par value, 200 million shares authorized, 160   million shares issued and outstanding			2,159				2,148
Retained earnings			2,879				3,011
Accumulated other comprehensive loss			-				(71	)
Total equity			5,038				5,088
Total liabilities and equity		$	17,685			$	16,066
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

9

CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of CASH FLOWS
(in millions)
Nine months ended September 30	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	180		$	437
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization (including amortization of nuclear fuel)		499			489
Equity component of AFUDC		(50	)		(53	)
Severance expense		16			-
FERC mitigation costs		71			-
Community support and charitable contributions expense		40			-
Gains on sales of other assets		(2	)		-
Deferred income taxes		127			222
Contributions to qualified pension plans		(60	)		(207	)
Accrued pension and other post-retirement benefit costs		58			32
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		(33	)		(17	)
Receivables		(35	)		34
Receivables from affiliate		(10	)		7
Inventory		23			(142	)
Other current assets		(6	)		88
(Decrease) increase in
Accounts payable		(20	)		(44	)
Payables to affiliate		23			(11	)
Taxes accrued		62			55
Other current liabilities		16			(8	)
Other assets		(19	)		(31	)
Other liabilities		(27	)		37
Net cash provided by operating activities		853			888
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(1,098	)		(1,010	)
Purchases of available-for-sale securities		(385	)		(430	)
Proceeds from sales and maturities of available-for-sale securities		359			401
Notes due from affiliate		-			(59	)
Other		75			4
Net cash used by investing activities		(1,049	)		(1,094	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		988			496
Payments for the redemption of long-term debt		(502	)		(1	)
Notes payable and commercial paper		(188	)		-
Dividends paid on preferred stock		(2	)		(2	)
Dividends to parent		(310	)		(450	)
Notes payable to affiliate		212			-
Other		(3	)		-
Net cash provided by financing activities		195			43
Net decrease in cash and cash equivalents		(1	)		(163	)
Cash and cash equivalents at beginning of period		20			230
Cash and cash equivalents at end of period	$	19		$	67
Supplemental disclosures
Significant noncash transactions
Accrued capital expenditures	$	144		$	255
Asset retirement obligation additions		684			3
Capital expenditures financed through capital leases		137			-

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

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CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS of EQUITY
						Accumulated Other Comprehensive (Loss) Income
(in millions)	Common Stock		Retained Earnings			Net (Losses) Gains on Cash Flow Hedges			Total Equity
Balance, December 31, 2010	$	2,130	$	3,083		$	(33	)	$	5,180
Net income		-		437			-			437
Other comprehensive loss		-		-			(37	)		(37	)
Stock-based compensation expense		14		-			-			14
Dividends paid to parent		-		(450	)		-			(450	)
Preferred stock dividends at stated rate		-		(2	)		-			(2	)
Balance, September 30, 2011	$	2,144	$	3,068		$	(70	)	$	5,142
Balance, December 31, 2011	$	2,148	$	3,011		$	(71	)	$	5,088
Net income		-		180			-			180
Other comprehensive income		-		-			71			71
Stock-based compensation expense		11		-			-			11
Dividends paid to parent		-		(310	)		-			(310	)
Preferred stock dividends at stated rate		-		(2	)		-			(2	)
Balance, September 30, 2012	$	2,159	$	2,879		$	-		$	5,038
See Notes to Progress Energy Carolinas, Inc. Unaudited Condensed Consolidated Interim Financial Statements.

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FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS
September 30, 2012
UNAUDITED CONDENSED STATEMENTS of OPERATIONS and COMPREHENSIVE INCOME
	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
Operating revenues
Regulated electric	$	1,382	$	1,414	$	3,576	$	3,639
Non-regulated electric and other		6		5		18		16
Total operating revenues		1,388		1,419		3,594		3,655
Operating expenses
Fuel used in electric generation and purchased power		799		690		1,849		1,804
Operation, maintenance and other		245		222		660		652
Depreciation and amortization		39		39		158		112
Property and other taxes		99		106		271		274
Total operating expenses		1,182		1,057		2,938		2,842
Gains on sales of other assets and other, net		1		1		2		2
Operating income		207		363		658		815
Other income and expenses, net		11		5		29		24
Interest expense, net		62		46		194		176
Income before income taxes		156		322		493		663
Income tax expense		56		119		182		245
Net income		100		203		311		418
Less: preferred stock dividend requirement		-		-		1		1
Net income available to parent	$	100	$	203	$	310	$	417
Comprehensive income, net of tax	$	126	$	186	$	337	$	396
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

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FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED BALANCE SHEETS
(in millions)	September 30, 2012			December 31, 2011
ASSETS
Current assets
Cash and cash equivalents	$	20		$	16
Receivables, (net of allowance of $5 at September 30, 2012, and   $18 at December 31, 2011)		434			367
Receivables from affiliated companies		19			7
Inventory		618			659
Regulatory assets		214			244
Deferred tax assets		133			138
Prepayments and other current assets		44			37
Total current assets		1,482			1,468
Investments and other assets
Nuclear decommissioning trust funds		621			559
Other		187			142
Total investments and other assets		808			701
Property, plant and equipment
Cost		15,476			14,926
Accumulated depreciation and amortization		(4,594	)		(4,474	)
Net property, plant and equipment		10,882			10,452
Regulatory assets and deferred debits
Regulatory assets		1,446			1,629
Other		42			44
Total regulatory assets and deferred debits		1,488			1,673
Total assets	$	14,660		$	14,294
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	399		$	340
Payables to affiliated companies		25			14
Notes payable and commercial paper		-			233
Notes payable to affiliated companies		221			8
Taxes accrued		142			31
Interest accrued		59			54
Customer deposits		222			224
Derivative liabilities		130			220
Current maturities of long-term debt		435			10
Other		128			132
Total current liabilities		1,761			1,266
Long-term debt		4,237			4,671
Deferred credits and other liabilities
Deferred income taxes		1,541			1,325
Accrued pension and other post-retirement benefit costs		631			598
Asset retirement obligations		514			369
Regulatory liabilities		880			1,024
Other		217			332
Total deferred credits and other liabilities		3,783			3,648
Commitments and contingencies
Preferred stock		34			34
Equity
Common stock without par value, 60 million shares authorized,   100 shares issued and outstanding		1,762			1,757
Retained earnings		3,084			2,945
Accumulated other comprehensive loss		(1	)		(27	)
Total equity		4,845			4,675
Total liabilities and equity	$	14,660		$	14,294
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

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FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED STATEMENTS of CASH FLOWS
(in millions)
Nine months ended September 30	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	311		$	418
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		161			115
Equity component of AFUDC		(27	)		(24	)
Severance expense		7			-
Amount to be refunded to customers (Note 4B)		100			-
Gains on sales of other assets		(2	)		(2	)
Deferred income taxes		192			291
Contributions to qualified pension plans		(61	)		(104	)
Accrued pension and other post-retirement benefit costs		52			38
Decrease (increase) in
Net realized and unrealized mark-to-market hedging transactions		64			11
Receivables		(76	)		(132	)
Receivables from affiliate		(12	)		1
Inventory		36			(10	)
Other current assets		(47	)		(58	)
Increase (decrease) in
Accounts payable		68			(7	)
Payables to affiliate		11			(5	)
Taxes accrued		110			105
Other current liabilities		(15	)		27
Other assets		21			(2	)
Other liabilities		(123	)		58
Net cash provided by operating activities		770			720
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(573	)		(626	)
Purchases of available-for-sale securities		(562	)		(4,097	)
Proceeds from sales and maturities of available-for-sale securities		561			4,098
Insurance proceeds		7			74
Other		4			28
Net cash used by investing activities		(563	)		(523	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		-			296
Payments for the redemption of long-term debt		(9	)		(309	)
Payments of short-term debt with original maturities greater than 90 days		(65	)		-
Proceeds from issuance of short-term debt with original maturities greater than 90 days		65			-
Notes payable and commercial paper		(233	)		-
Dividends paid on preferred stock		(1	)		(1	)
Dividends to parent		(170	)		(475	)
Notes payable to affiliate		213			60
Other		(3	)		1
Net cash used by financing activities		(203	)		(428	)
Net increase (decrease) in cash and cash equivalents		4			(231	)
Cash and cash equivalents at beginning of period		16			249
Cash and cash equivalents at end of period	$	20		$	18
Supplemental disclosures
Significant noncash transactions
Accrued capital expenditures	$	102		$	72
Asset retirement obligation additions		129			-
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

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FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED CONDENSED STATEMENTS of EQUITY
						Accumulated Other Comprehensive (Loss) Income
(in millions)	Common Stock		Retained Earnings			Net (Losses) Gains on Cash Flow Hedges			Total Equity
Balance, December 31, 2010	$	1,750	$	3,144		$	(4	)	$	4,890
Net income		-		418			-			418
Other comprehensive loss		-		-			(22	)		(22	)
Stock-based compensation expense		5		-			-			5
Dividends paid to parent		-		(475	)		-			(475	)
Preferred stock dividends at stated rate		-		(1	)		-			(1	)
Tax dividend		-		(2	)		-			(2	)
Balance, September 30, 2011	$	1,755	$	3,084		$	(26	)	$	4,813
Balance, December 31, 2011	$	1,757	$	2,945		$	(27	)	$	4,675
Net income		-		311			-			311
Other comprehensive income		-		-			26			26
Stock-based compensation expense		5		-			-			5
Dividends paid to parent		-		(170	)		-			(170	)
Preferred stock dividends at stated rate		-		(1	)		-			(1	)
Tax dividend		-		(1	)		-			(1	)
Balance, September 30, 2012	$	1,762	$	3,084		$	(1	)	$	4,845
See Notes to Progress Energy Florida, Inc. Unaudited Condensed Interim Financial Statements.

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PROGRESS ENERGY, INC.

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

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

COMBINED NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS

INDEX TO APPLICABLE COMBINED NOTES TO UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS BY REGISTRANT

The unaudited notes to the condensed interim financial statements that follow are a combined presentation. The following table sets forth which notes are applicable to each of the Progress Energy Registrants.

Applicable Notes

Registrant

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1. ORGANIZATION AND BASIS OF PRESENTATION

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 Energy Registrants” refers collectively to the three separate registrants: Progress Energy, PEC and PEF. The information in these combined notes relates to each of the Progress Energy Registrants as noted in the Index to Applicable Combined Notes to Unaudited Condensed Interim Financial Statements by Registrant. 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.

PROGRESS ENERGY

The Parent is a holding company headquartered in Raleigh, N.C., subject to regulation by the Federal Energy Regulatory Commission (FERC). On July 2, 2012, Progress Energy, Inc. consummated the merger with Duke Energy Corporation (Duke Energy), and became, and will continue as, a direct wholly owned subsidiary of Duke Energy. The total consideration transferred in the merger, based on the closing price of Duke Energy common shares on July 2, 2012, was $18 billion. The merger was recorded using the acquisition method of accounting, whereby the acquiree normally reflects the impact of the adjustments of assets and liabilities to fair value and the resultant goodwill on their financial statements. However, in accordance with SEC guidance, the Progress Energy Registrants did not reflect these adjustments based on the significance of the Progress Energy Registrants’ outstanding public debt securities. See Note 2 for additional information regarding the merger.

Subsequent to the merger, our sole reportable segment is Franchised Electric, which is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. The remainder of our operations, including the Parent and Progress Energy Service Company (PESC) and other miscellaneous nonregulated businesses are presented as Other. See Note 3 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), the Public Service Commission of South Carolina (PSCSC), the United States Nuclear

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Regulatory Commission (NRC) and the FERC. As discussed further in Note 3, PEC’s operations include one reportable segment, Franchised Electric.

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. As discussed further in Note 3, PEF’s operations include one reportable segment, Franchised Electric.

B. BASIS OF PRESENTATION

These Unaudited Condensed Interim Financial Statements have been prepared in accordance with generally accepted accounting principles (GAAP) in the U.S. for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, these Unaudited Condensed Interim Financial Statements do not include all of the information and notes required by GAAP in the U.S. 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 Unaudited Condensed Interim Financial Statements and Notes do not include all of the information and notes required by GAAP in the U.S. for annual financial statements, the Unaudited Condensed Interim Financial Statements and other information included in this quarterly report should be read in conjunction with the respective Financial Statements and Notes in the Progress Energy Registrants’ combined Form 10-K for the year ended December 31, 2011 (2011 Form 10-K).

These Unaudited Condensed Interim Financial Statements reflect all normal recurring adjustments that are, in the opinion of the respective companies’ management, necessary to fairly present the financial position and results of operations of each Progress Energy Registrant. Amounts reported in the Progress Energy Registrants’ Statements of Operations and Comprehensive Income are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, regulatory rulings, the timing of maintenance on electric generating units, changes in mark-to-market valuations, changing commodity prices and other factors.

The Unaudited Condensed Interim Financial Statements and Notes have been reclassified to conform with the Duke Energy format.

C. USE OF ESTIMATES

To conform to GAAP in the U.S., management makes estimates and assumptions that affect the amounts reported in the Unaudited Condensed Interim Financial Statements and Notes. Although these estimates are based on management’s best available information at the time, actual results could differ.

D. UNBILLED REVENUE

Revenues on sales of electricity are recognized when the service is provided to customers. Unbilled retail revenues are estimated by applying a weighted average revenue per kilowatt-hour for all customer classes to the number of estimated kilowatt-hours delivered but not billed. The amount of unbilled revenues can vary significantly from period to period as a result of numerous factors, including seasonality, weather, customer usage patterns and customer mix.

Progress Energy, PEC and PEF had unbilled revenues within Receivables in their respective Balance Sheets as follows:

(in millions)	September 30, 2012		December 31, 2011
Progress Energy	$	190	$	157
PEC	$	99	$	102
PEF	$	91	$	55

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2.	MERGER AND SALES OF OTHER ASSETS
A.	MERGER WITH DUKE ENERGY

On July 2, 2012, Progress Energy consummated the merger with Duke Energy, and became, and will continue as, a direct wholly owned subsidiary of Duke Energy. Under the terms of the merger agreement, each share of Progress Energy common stock was converted into 0.87083 shares of Duke Energy common stock as adjusted for the one-for-three reverse stock split of Duke Energy stock, effected in conjunction with, and immediately prior to, the merger. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock was converted into an option to acquire, or an equity award relating to, 0.87083 shares of Duke Energy common stock. The terms and vesting periods of outstanding options and equity awards were not changed as a result of the merger.

As a result of the merger, the prior Progress Energy shares outstanding were cancelled. Progress Energy now has 100 authorized, issued and outstanding shares of common stock.

MERGER-RELATED REGULATORY MATTERS

Federal Energy Regulatory Commission

On June 8, 2012, the FERC conditionally approved the merger including Duke Energy and Progress Energy’s revised market power mitigation plan, the Joint Dispatch Agreement (JDA) and the joint Open Access Transmission Tariff (OATT). The revised market power mitigation plan provides for the acceleration of one transmission project and the construction of seven other transmission projects (Long-term FERC Mitigation) and interim firm power sale agreements during the construction of the transmission projects (Interim FERC Mitigation). The Long-term FERC Mitigation will increase power imported into the service areas of Duke Energy Carolinas LLC (Duke Energy Carolinas), a wholly owned subsidiary of Duke Energy, and PEC and enhance competitive power supply options in the service areas. The construction of these projects will occur over the next two to three years. In conjunction with the Interim FERC Mitigation, Duke Energy Carolinas and PEC entered into power sale agreements with various counterparties that were effective with the consummation of the merger. These agreements, or similar power sale agreements, will be in place until the Long-term FERC Mitigation is operational. Under the agreements PEC will deliver around-the-clock power during the winter and summer in quantities that vary by season and by peak period.

The FERC order requires an independent party to monitor whether the power sale agreements remain in effect during construction of the transmission projects and provide quarterly reports to the FERC regarding the status of construction of the transmission projects.

·   On June 25, 2012, Duke Energy and Progress Energy accepted the conditions imposed by the FERC.

·   On July 9, 2012, certain intervenors requested a rehearing seeking to overturn the June 8, 2012 order by the FERC. On August 8, 2012, the FERC granted rehearing for further consideration.

North Carolina Utilities Commission and Public Service Commission of South Carolina

In September 2011, Duke Energy and Progress Energy reached settlements with the Public Staff of the North Carolina Utilities Commission (NC Public Staff) and the South Carolina Office of Regulatory Staff (ORS) and certain other interested parties in connection with the regulatory proceedings related to the merger, the JDA and the OATT that were pending before the NCUC and PSCSC. These settlements were updated in May 2012 to reflect the results of ongoing merger-related applications pending before the FERC. As part of these settlements and the application for approval of the merger by the NCUC and PSCSC, Duke Energy Carolinas and PEC agreed to the conditions and obligations listed below.

·   Guarantee of $650 million in system fuel and fuel-related savings over 60 to 78 months for North Carolina and South Carolina retail customers. The savings are expected to be achieved through coal blending, coal commodity and transportation savings, gas transportation savings and the joint dispatch of Duke Energy Carolinas and PEC generation fleets.

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·   Duke Energy Carolinas and PEC will not seek recovery from retail customers for the cost of the Long-term FERC Mitigation for five years following merger consummation. After five years, Duke Energy Carolinas and PEC may seek to recover the costs of the Long-term FERC Mitigation, but must show that the projects are needed to provide adequate and reliable retail service regardless of the merger.

·   A $65 million rate reduction over the term of the Interim FERC Mitigation to reflect the cost of capacity not available to Duke Energy Carolinas and PEC wholesale and retail customers during the Interim FERC Mitigation. The rate reduction will be achieved through retail decrement riders apportioned between Duke Energy Carolinas and PEC retail customers.

·   Duke Energy Carolinas and PEC will not seek recovery from retail customers for any revenue shortfalls or fuel-related costs associated with the Interim FERC Mitigation.

·   Duke Energy Carolinas and PEC will not seek recovery from retail customers for any of their allocable share of merger-related severance costs.

·   Duke Energy Carolinas and PEC will provide community support and charitable contributions for four years, workforce development, low income energy assistance and funding for green energy at a total cost of approximately $99 million, which cannot be recovered from retail customers.

·   Duke Energy Carolinas and PEC will abide by revised North Carolina Regulatory Conditions and Code of Conduct governing their operations.

On June 29, 2012, the NCUC approved the merger application and the JDA application with conditions that were reflective of the settlement agreements described above. On July 2, 2012, the PSCSC approved the JDA application subject to Duke Energy Carolinas and PEC providing their South Carolina retail customers pro rata benefits equivalent to those approved by the NCUC in its merger approval order.

On July 6, 2012, the NCUC issued an order initiating investigation and scheduling hearings on the Duke Energy board of directors’ decision on July 2, 2012, to replace William D. Johnson with James E. Rogers as President and CEO of Duke Energy subsequent to the merger close, as well as other related matters. See Note 4C for further information.

ACCOUNTING CHARGES RELATED TO THE MERGER CONSUMMATION

The following pre-tax consummation charges were recognized upon closing of the merger and are included in our Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2012.

(in millions)	PEC		PEF		Progress Energy
FERC Mitigation	$	71	$	-	$	71
Severance costs		42		24		66
Community support, charitable contributions and other		54		9		63
Total	$	167	$	33	$	200

The FERC Mitigation charges reflect the portion of transmission project costs that are probable of disallowance, the impairment of the carrying value of the generation assets serving the Interim FERC Mitigation, and the mark-to-market loss recognized on the power sale agreements upon closing of the merger. Subsequent changes in the fair value of the interim power sale agreements are reflected in regulated electric operating revenues over the life of the contracts. The charges related to the transmission projects and the impairment of the carrying value of generation assets were recorded within impairment charges in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2012. The mark-to-market loss on the power sale agreements was recorded in regulated electric operating revenues in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2012. Realized gains or losses on the interim contract sales are also recorded within regulated electric operating revenues. The ability to successfully

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defend future recovery of a portion of the transmission projects in rates and any future changes to estimated transmission project costs could impact the amount that is not expected to be recovered.

In conjunction with the merger, in November 2011, Duke Energy and Progress Energy each offered a voluntary severance plan (VSP) to certain eligible employees. VSP and other severance costs incurred during the three and nine months ended September 30, 2012, were recorded primarily within operations, maintenance and other (O&M) expense in the Consolidated Statements of Operations and Comprehensive Income. See Note 13 for further information related to employee severance expenses.

Community support, charitable contributions and other reflect (i) the unconditional obligation to provide funding at a level comparable to historic practices over the next four years and (ii) financial and legal advisory costs that were incurred upon the closing of the merger, retention and relocation costs paid to certain employees. These charges were recorded within O&M expense in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2012.

COSTS TO ACHIEVE THE MERGER

The following table summarizes pre-tax merger consummation costs, integration and other related costs (collectively referred to as costs to achieve), including those discussed above, substantially all of which are included in operating expenses in our Statements of Operations and Comprehensive Income:

	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
Progress Energy	$	218	$	14	$	241	$	32
PEC		180		7		194		17
PEF		38		7		47		15

Duke Energy expects to incur significant system integration and other merger-related transition costs primarily through 2016 that are necessary in order to achieve certain cost savings, efficiencies and other benefits anticipated to result from the merger.

EXIT COSTS

In 2011, we evaluated our business needs for office space after the merger and formulated an exit plan to vacate one 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 $9 million of expense will be attributable to PEC, $4 million to PEF and $4 million to other Duke Energy subsidiaries. The exit cost liability is being recognized proportionately as we vacate the premises, which began in the fourth quarter of 2011. The costs of the exit plan are included in O&M expense in the Consolidated Statements of Operations and Comprehensive Income.

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The following table presents a reconciliation of the beginning and ending exit cost liability balance:

(in millions)
Balance, December 31, 2011	$	5
Additional exit cost recognized		5
Balance, June 30, 2012		10
Additional exit cost recognized(a)		2
Balance, September 30, 2012(b)	$	12

(a)	PEC, PEF and other Duke Energy subsidiaries recognized exit costs of $1 million, $- million and $1 million, respectively, for the three months ended September 30, 2012, and $4 million, $2 million and $1 million, respectively, for the nine months ended September 30, 2012.
(b)	Expense related to the recognition of the cumulative exit cost liability at September 30, 2012, was attributed to PEC, PEF and other Duke Energy subsidiaries totaling $8 million, $3 million and $1 million, respectively.

B.   SALES OF OTHER ASSETS

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 5C 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 September 30, 2012 and 2011, earnings (loss) from discontinued operations, net of tax was $3 million and $- million, respectively. During the nine months ended September 30, 2012 and 2011, earnings (loss) from discontinued operations, net of tax was $10 million and $(4) million, respectively. Earnings for the nine months ended September 30, 2012, relates primarily to an $18 million pre-tax gain from the reversal of certain environmental indemnification liabilities for which the indemnification period expired in the first quarter of 2012.

3. FINANCIAL INFORMATION BY BUSINESS SEGMENT

PROGRESS ENERGY

Effective with the consummation of the merger with Duke Energy on July 2, 2012, our reportable segments changed based on the financial information the chief decision maker evaluates for the allocation of resources and assessing performance. Our sole reportable segment is now Franchised Electric, which is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. 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 segment, Other now presents the remainder of our operations, including the Parent and PESC and other miscellaneous nonregulated businesses, as well as costs to achieve the merger with Duke Energy. Also effective with the consummation of the merger, management began evaluating segment performance based on Segment Income. Segment Income is defined as income from continuing operations net of income attributable to noncontrolling interests.

Prior periods’ segment information has been recast to conform to the current year presentation. None of these segment changes impact the Progress Energy Registrants’ reported consolidated revenues or net income.

Products and services are sold between the affiliate companies of Duke Energy at cost.

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BUSINESS SEGMENT DATA
(in millions)	Unaffiliated Revenues			Affiliated Revenues				Total Revenues				Segment Income/ Consolidated Net Income(a)
Three months ended September 30, 2012
Franchised Electric		$	2,747		$	39			$	2,786			$	333
Total reportable segment			2,747			39				2,786				333
Other			3			-				3				(181	)(b)
Eliminations			-			(1	)			(1	)			-
Add back of noncontrolling interest component			-			-				-				2
Income from discontinued operations, net of tax			-			-				-				3
Total consolidated		$	2,750		$	38			$	2,788			$	157
Three months ended September 30, 2011
Franchised Electric		$	2,750		$	-			$	2,750			$	408
Total reportable segment			2,750			-				2,750				408
Other			3			-				3				(117	)(b)
Add back of noncontrolling interest component			-			-				-				2
Total consolidated		$	2,753		$	-			$	2,753			$	293

(in millions)	Unaffiliated Revenues			Affiliated Revenues				Total Revenues				Segment Income/ Consolidated Net Income(a)
Nine months ended September 30, 2012
Franchised Electric		$	7,132		$	40			$	7,172			$	636
Total reportable segment			7,132			40				7,172				636
Other			8			-				8				(278	)(b)
Eliminations			-			(2	)			(2	)			-
Add back of noncontrolling interest component			-			-				-				5
Income from discontinued operations, net of tax			-			-				-				10
Total consolidated		$	7,140		$	38			$	7,178			$	373
Nine months ended September 30, 2011
Franchised Electric		$	7,188		$	1			$	7,189			$	874
Total reportable segment			7,188			1				7,189				874
Other			8			-				8				(219	)(b)
Eliminations			-			(1	)			(1	)			-
Add back of noncontrolling interest component			-			-				-				5
Loss from discontinued operations, net of tax			-			-				-				(4	)
Total consolidated		$	7,196		$	-			$	7,196			$	656

(a)	Segment income excludes noncontrolling interests and results of entities classified as discontinued operations.
(b)	Segment income includes after-tax costs to achieve the merger with Duke Energy of $132 million and $149 million for the three and nine months ended September 30, 2012, respectively, and $9 million and $27 million for the three and nine months ended September 30, 2011, respectively.

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SEGMENT ASSETS
Segment assets in the following table exclude all intercompany assets between the Progress Energy Registrants.
(in millions)	September 30, 2012				December 31, 2011
Franchised Electric		$	36,135			$	34,166
Total reportable segment			36,135				34,166
Other			549				765
Reclassifications(a)			(33	)			-
Total consolidated assets		$	36,651			$	34,931

(a) Primarily represents reclassification of federal tax balances in consolidation.

PEC and PEF

PEC and PEF each have one reportable operating segment, Franchised Electric, which generates, transmits, distributes and sells electricity in portions of North Carolina and South Carolina and in portions of Florida, respectively.

The remainder of PEC’s and PEF’s operations are classified as Other. While not considered reportable segments for either company, PEC’s and PEF’s Other consists of each respective company’s costs to achieve the merger with Duke Energy. PEC’s Other had a net loss of $109 million and $5 million for the three months ended September 30, 2012 and 2011, respectively, and $119 million and $14 million for the nine months ended September 30, 2012 and 2011, respectively. PEF’s Other had a net loss of $23 million and $4 million for the three months ended September 30, 2012 and 2011, respectively, and $30 million and $13 million for the nine months ended September 30, 2012 and 2011, respectively.

The Franchised Electric operating segments own substantially all of PEC’s and PEF’s assets at September 30, 2012 and December 31, 2011.

4. REGULATORY MATTERS

RATE RELATED INFORMATION

The NCUC, the PSCSC and the FPSC approve rates for retail electric services within their states. The FERC approves rates for electric sales to certain wholesale customers served under cost-based rates, as well as sales of transmission service.

A. PEC

2012 NORTH CAROLINA RATE CASE

On October 12, 2012, PEC filed an application with the NCUC for an increase in base rates of approximately $387 million, or an average 12% increase in revenues. The request for increase is based upon an 11.25% return on equity and a capital structure of 55% equity and 45% long-term debt. The rate increase is designed primarily to recover the cost of plant modernization and other capital investments in generation, transmission and distribution systems, as well as increased expenditures for nuclear plants and personnel, vegetation management and other operating costs. The rate case includes a corresponding decrease in PEC’s energy efficiency (EE) and demand side management (DSM) rider, resulting in a net requested increase of $359 million, or 11% increase in revenues.

PEC expects revised rates, if approved, to go into effect in the second or third quarter of 2013.

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JOINT DISPATCH AGREEMENT

On June 29, 2012, and July 2, 2012, the NCUC and the PSCSC, respectively, approved the JDA between Duke Energy Carolinas and PEC. The JDA provides for joint dispatch of the generating facilities of both Duke Energy Carolinas and PEC for the purpose of reducing the cost of serving the native loads of both companies. As set forth in the JDA, Duke Energy Carolinas will act as the joint dispatcher, on behalf of both Duke Energy Carolinas and PEC. As joint dispatcher, Duke Energy Carolinas will direct the dispatch of both Duke Energy Carolinas’ and PEC’s power supply resources, determine payments between the parties for the purchase and sale of energy between Duke Energy Carolinas and PEC as a result of the JDA, and calculate and allocate the fuel cost savings to the parties as a result of the JDA.

HF LEE AND L.V. SUTTON COMBINED CYCLE FACILITY

PEC is in the process of constructing two new generating facilities, which consist of an approximately 920-MW combined cycle natural gas-fired generating facility at the HF Lee Energy Complex (Lee) in Wayne County, N.C., and an approximately 625-MW natural gas-fired generating facility at the L.V. Sutton plant (Sutton) in New Hanover County, N.C. Lee has an expected in-service date of December 2012 and Sutton has an expected in-service date of December 2013. Based on updated cost estimates, total costs (including allowance for funds used during construction [AFUDC]) for the Lee and Sutton projects are estimated to be approximately $750 million and $600 million, respectively.

HARRIS NUCLEAR PLANT EXPANSION

In 2006, PEC selected a site at its existing Shearon Harris Nuclear Power Plant (Harris) to evaluate for possible future nuclear expansion. On February 19, 2008, PEC filed its combined license (COL) application with the NRC for two Westinghouse Electric AP-1000 reactors at Harris, which the NRC docketed on April 17, 2008. No petitions to intervene have been admitted in the Harris COL application.

B. PEF

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: the Crystal River Nuclear Plant Unit 3 (CR3) delamination prudence review then pending before the FPSC, PEF’s proposed Levy Nuclear Plant (Levy) cost recovery, and certain base rate issues. Refer to each of these respective sections for further discussion.

CR3 OUTAGE

In September 2009, 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, it was determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when an opening was created 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 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 evaluates possible 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.

PEF worked with two potential vendors for repair work and received repair proposals from both vendors. After analyzing those proposals, PEF selected a single vendor that would be engaged to complete the repair of CR3 should

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the choice to repair be made. See discussion below regarding CR3 cost recovery and other provisions, as a result of a 2012 settlement agreement with the FPSC.

Based on an analysis of possible repair options performed by outside engineering consultants, PEF selected an option, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls. The preliminary cost estimate of $900 million to $1.3 billion is currently under review and could change following completion of further detailed engineering studies, vendor negotiations and final risk assessments. These engineering studies and risk assessments include analyses by independent entities currently in progress. The risk assessment process includes analysis of events that, although currently deemed unlikely, could have a significant impact on the cost estimate or feasibility of repair. This preliminary cost estimate and project scope are under review, as described further below, however, the cost estimate is trending upward.

In March 2012, Duke Energy commissioned an independent review team led by Zapata Incorporated (Zapata) to review and assess the PEF CR3 repair plan, including the repair scope, risks, costs and schedule. In its final report, Zapata found that the current repair scope appears to be technically feasible, but there are significant risks that need to be addressed regarding the approach, construction methodology, scheduling and licensing. Zapata performed four separate analyses of the estimated project cost and schedule to repair CR3, including; (i) an independent review of the current repair scope (without existing assumptions or data), of which Zapata estimated costs of $1.49 billion with a project duration of 35 months; (ii) a review of PEF’s previous bid information, which included cost estimate data from PEF, of which Zapata estimated costs of $1.55 billion with a project duration of 31 months; (iii) an expanded scope of work scenario, that included the PEF scope plus the replacement of the containment building dome and the removal and replacement of concrete in the lower building elevations, of which Zapata estimated costs of approximately $2.44 billion with a project duration of 60 months, and; (iv) a “worst case” scenario, assuming PEF performed the more limited scope of work, and at the conclusion of that work, additional damage occurred in the dome and in the lower elevations, which forced replacement of each, of which Zapata estimated costs of $3.43 billion with a project duration of 96 months. The principal difference between Zapata’s estimate and PEF’s previous estimate appears to be due to the respective levels of contingencies included by each party, including higher project risk and longer project duration. PEF has filed a copy of the Zapata report with the FPSC and with the NRC. The FPSC held a status conference on October 30, 2012 to discuss Duke Energy’s analysis of the Zapata report.

PEF continues to analyze the various aspects of the repair option as well as the option of early retirement. This analysis includes the evaluation of the potential implications to scope, cost estimate and schedule from the project risks identified in teh Zapata report. A number of factors could affect the decision to repair, the return-to-service date and repair costs incurred, including, but not limited to, state regulatory and NRC reviews, insurance recoveries from Nuclear Electric Insurance Limited (NEIL), the ability to obtain builder’s risk insurance with appropriate coverage, final engineering designs, vendor contract negotiations, the ultimate work scope completion, performance testing, weather and the impact of new information discovered during additional testing and analysis. We will proceed with the repair option only if there is a high degree of confidence that the repair can be successfully completed and licensed within the final estimated costs and schedule, and it is in the best interests of PEF’s customers, the joint owners and Duke Energy’s investors.

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through NEIL. NEIL provides insurance coverage for repair costs for covered events, as well as the cost of replacement power of up to $490 million per event when the unit is out of service as a result of these events. Actual replacement power costs have exceeded 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. NEIL has made payments on the first delamination; however, NEIL has withheld payment of approximately $70 million of replacement power cost claims and repair cost claims related to the first delamination event. NEIL has unresolved concerns and has not made any payments on the second delamination and has not provided a written coverage decision for either 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 that we believe them to owe under the applicable insurance policies. Consistent with the terms and procedures under the insurance coverage with NEIL, we have agreed to mediation

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prior to commencing any formal dispute resolution. We are in the process of providing information as requested by NEIL and currently have scheduled the mediation to commence in November 2012. Given the circumstances, accounting standards require full recovery to be probable to recognize an insurance receivable. As of September 30, 2012, PEF has no insurance receivables from NEIL related to either the first or second delamination. 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, as discussed above, through September 30, 2012:

(in millions)	Replacement Power Costs			Repair Costs
Spent to date	$	573		$	324
NEIL proceeds received to date		(162	)		(143	)
Balance for recovery(a)	$	411		$	181

(a) See discussion below of PEF's ability to recover prudently incurred fuel and purchased power costs and CR3 repair costs.

As a result of the 2012 settlement agreement with the FPSC, PEF will be permitted to recover prudently incurred fuel and purchased power costs through its fuel clause without regard for the absence of CR3 for the period from the beginning of the CR3 outage through the earlier of the return of CR3 to commercial service or December 31, 2016. 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.

As a result of the ongoing analysis of  repair options, including scope, schedule, cost estimate and project risks, PEF has determined that it is unlikely to be in a position to begin the repair of CR3 prior to December 31, 2012. Consistent with the 2012 settlement agreement regarding the timing of commencement of repairs, PEF recorded a regulatory liability of $100 million related to replacement power obligations. This amount is included within fuel used in electric generation and purchased power in the Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2012.

In the event that repair activities continue beyond December 31, 2016, the parties are not prohibited from contesting PEF’s right to recover replacement power costs incurred after 2016. 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 Duke Energy’s Board of Directors, will be the basis for project measurement. If costs exceed the board-approved estimate, overruns will be split evenly between Duke Energy 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. The

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wholesale portion of CR3 investments, which are not covered by the 2012 settlement agreement, totals approximately $130 million as of September 30, 2012. The recoverability of the wholesale portion of CR3 will continue to be evaluated as decisions are made regarding repair or retirement. Recovery of the wholesale portion of CR3 under the retirement option is at risk based on prior treatment of early retired plants in wholesale rates. 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. Retirement of the plant could impact funding obligations associated with PEF’s nuclear decommissioning trust fund.

PEF believes the actions taken and costs incurred in response to the CR3 delaminations 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.

PEF is a party to a master participation agreement and other related agreements with the joint owners of CR3 which convey certain rights and obligations on PEF and the joint owners. PEF is meeting with the joint owners on a regular basis to discuss the parties’ mutual obligations under these agreements and to better understand their views and positions on these issues. We cannot predict the outcome of this matter.

OTHER BASE RATE MATTERS

As a result 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 increase in revenue requirements effective with the first billing cycle of January 2013, while maintaining the current ROE range of 9.5 percent to 11.5 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 no adjustment for the three months ended September 30, 2012, and a $47 million benefit for the nine months ended September 30, 2012, which reduced O&M expense in its Statements of Operations and Comprehensive Income. Additionally, costs 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 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. In the month following CR3’s return to commercial service, PEF’s ROE range will increase to between 9.7 percent and 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. See the discussion above regarding recovery of CR3 investments if the plant is retired.

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. In 2011, the corresponding charge was recorded as a reduction of operating revenues in PEF’s Statements of Operations and Comprehensive Income.

LEVY

On July 30, 2008, PEF filed its COL application with the NRC for two Westinghouse Electric AP-1000 reactors at Levy, which the NRC docketed on October 6, 2008.  Various parties filed a joint petition to intervene in the Levy COL application. 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 Levy, 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, 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 has shifted 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

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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, Levy is considered to be PEF’s preferred baseload generation option.

Under the terms of the 2012 settlement agreement, PEF will begin residential cost-recovery of its proposed Levy project effective in the first billing cycle of January 2013 at the fixed rates contained in the settlement 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 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. PEF will true up any actual costs not recovered during the five-year period.

The 2012 settlement agreement also provides that PEF will treat the allocated wholesale cost of Levy (approximately $60 million) 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.

ANCLOTE UNITS 1 AND 2

On March 29, 2012, PEF announced plans to convert the 1,010-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 Environmental Cost Recovery Clause (ECRC). PEF believes this conversion is the most cost-effective alternative for Anclote to achieve and maintain compliance with applicable environmental regulations (See Note 5A). On September 13, 2012, the FPSC approved PEF’s request to seek cost recovery through the ECRC. PEF anticipates that both converted units will be placed in service by the end of 2013.

PEF COST OF REMOVAL RESERVE

The 2012 and 2010 settlement agreements provide 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. PEF may not reduce amortization expense if the reduction would cause PEF to exceed the appropriate high point of the ROE range, as established in the settlement agreements. Pursuant to the settlement agreements, PEF recognized a reduction in amortization expense of $60 million and $71 million for the three months ended September 30, 2012 and 2011, respectively. PEF recognized reductions in amortization expense of $118 million and $205 million for the nine months ended September 30, 2012 and 2011, respectively. PEF had eligible cost of removal reserves of $169 million remaining at September 30, 2012, which is 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.

C. OTHER REGULATORY MATTERS

On July 6, 2012, the NCUC issued an order initiating investigation and scheduling hearings addressing the timing of the Duke Energy Board of Directors’ decision on July 2, 2012, to replace William D. Johnson with James E. Rogers as President and Chief Executive Officer (CEO) of Duke Energy, as well as other related matters.

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Pursuant to the merger agreement, William D. Johnson, Chairman, President and CEO of Progress Energy became President and CEO of Duke Energy and James E. Rogers, Chairman, President and CEO of Duke Energy became Executive Chairman of Duke Energy upon close of the merger. Mr. Johnson subsequently resigned as the President and CEO of Duke Energy, effective July 3, 2012, and Mr. Rogers was appointed to be CEO.

Pursuant to the NCUC’s July 6, 2012 order, Mr. Rogers appeared before the NCUC on July 10, 2012, and provided testimony regarding the approval and closing of the merger and his replacement of Mr. Johnson as the President and CEO of Duke Energy. On July 19, 2012, Mr. Johnson, as well as E. Marie McKee and James B. Hyler, Jr., both former members of the Progress Energy Board of Directors and current members of the post-merger Duke Energy Board of Directors, appeared before the NCUC. Ann M. Gray and Michael G. Browning, both members of the pre-merger and post-merger Duke Energy Board of Directors, appeared before the NCUC on July 20, 2012. All provided testimony on the timing of the decision to replace Mr. Johnson with Mr. Rogers, as well as other related matters.

The NCUC’s order also requests that Duke Energy provide certain documents related to the issue for its review. Duke Energy also received an Investigative Demand issued by the North Carolina Department of Justice (NCDOJ) on July 6, 2012, requesting the production of certain documents related to the issues which are also the subject of the NCUC Investigation. Duke Energy’s responses to these requests were submitted on August 7, 2012. On August 1, 2012, the NCUC engaged the law firm of Jenner & Block to conduct an investigation of these matters. That investigation is underway and to date has involved the production of more documents to the NCUC and a series of informal interviews by Jenner & Block of a number of persons with knowledge of these matters, including executive officers of Duke Energy. This process is ongoing and will also involve interviews of the members of the legacy Duke Energy Board of Directors.

Duke Energy has also been contacted by the SEC to explain the circumstances surrounding the NCUC investigation and shareholder lawsuits in connection with the closing of the merger of Duke Energy and Progress Energy. A meeting was held with the SEC staff in late October. Duke Energy intends to continue to assist the SEC staff, as they request.

We are unable to predict the ultimate outcome of these proceedings.

D. PLANT RETIREMENTS AND ASSET RETIREMENT OBLIGATIONS

PEC filed a plan with the NCUC and the PSCSC to retire all of its coal-fired generating facilities in the Carolinas that do not have scrubbers. On October 1, 2011, PEC retired the Weatherspoon coal-fired generating units, on September 15, 2012, PEC retired the Lee coal-fired generating units, and on October 1, 2012, PEC retired the Cape Fear coal-fired generating units and the H.B. Robinson Unit 1 coal-fired unit. PEC expects to retire the Sutton coal-fired facility by the end of 2013.

In addition, on October 1, 2012, PEC retired six combustion turbine units in North Carolina, totaling approximately 100 MW of capacity.

The net carrying value of the remaining facilities at September 30, 2012, of $164 million and the net carrying value of the retired facilities of $57 million are included in generation facilities to be retired, net and regulatory assets, respectively, in the Consolidated Balance Sheets. The net carrying value of the retired facilities is expected to be recovered over a 10-year period as presented in our updated depreciation study filed with the NCUC and PSCSC. However, such recovery, including recovery of carrying costs on remaining book values, could be subject to future regulatory approvals and therefore cannot be assured.

PEF is considering the impact pending environmental regulations may have on the Crystal River Units 1 and 2 coal-fired steam turbines (CR1 and CR2), and the possibility of retiring these plants (See Note 5A).

During the three months ended September 30, 2012, we recorded increases to asset retirement obligations of $813 million, including $684 million at PEC and $129 million at PEF, with offsetting increases to asset retirement costs, included in property, plant and equipment in the Balance Sheets. These increases are the result of conforming with Duke Energy’s assumptions for the types of estimated costs in the obligations, primarily related to including nuclear spent fuel disposal in the calculation.

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5. COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Notes 21 and 22 in the 2011 Form 10-K are described below.

A. ENVIRONMENTAL MATTERS

The Progress Energy Registrants are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These regulations can be changed from time to time, imposing new obligations on the Progress Energy Registrants.

The following environmental matters impact all of the Progress Energy Registrants.

REMEDIATION ACTIVITIES

The Progress Energy Registrants are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing operations and sites formerly owned or used by Progress Energy entities. In some cases, Progress Energy no longer owns the property. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remediation requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Progress Energy Registrants could potentially be held responsible for contamination caused by other parties. In some instances, the Progress Energy Registrants may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. Reserves associated with remediation activities at certain sites have been recorded and it is anticipated that additional costs associated with remediation activities at certain sites will be incurred in the future. All of these sites generally are managed in the normal course of business or affiliate operations. The Progress Energy Registrants have accrued costs associated with remediation activities at some of their current and former sites, as well as other relevant environmental contingent liabilities. Management, in the normal course of business, continually assesses the nature and extent of known or potential environmentally related contingencies and records liabilities when losses become probable and are reasonably estimable. Costs associated with remediation activities within the Progress Energy Registrants’ operations are typically expensed unless regulatory recovery of the costs is deemed probable.

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 deferred credits and other liabilities in the Balance Sheets. Amounts accrued and expenditures for environmental loss contingencies presented below are for the nine months ended September 30, 2012 and 2011. Such amounts for the three months ended September 30, 2012 and 2011 were not material.

PROGRESS ENERGY
(in millions)	Total
Balance, December 31, 2011	$	23
Amount accrued for environmental loss contingencies		16
Expenditures for environmental loss contingencies		(7	)
Balance, September 30, 2012(a)	$	32
Balance, December 31, 2010	$	35
Amount accrued for environmental loss contingencies		7
Expenditures for environmental loss contingencies		(17	)
Balance, September 30, 2011(a)	$	25

(a) Expected to be paid out over one to 12 years.

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PEC
(in millions)	Total
Balance, December 31, 2011	$	11
Amount accrued for environmental loss contingencies		4
Expenditures for environmental loss contingencies		(2	)
Balance, September 30, 2012(a)	$	13
Balance, December 31, 2010	$	12
Amount accrued for environmental loss contingencies		-
Expenditures for environmental loss contingencies		(1	)
Balance, September 30, 2011(a)	$	11

(a) Expected to be paid out over one to ten years.

PEF
(in millions)	Total
Balance, December 31, 2011	$	12
Amount accrued for environmental loss contingencies		12
Expenditures for environmental loss contingencies		(5	)
Balance, September 30, 2012(a)	$	19
Balance, December 31, 2010	$	23
Amount accrued for environmental loss contingencies		7
Expenditures for environmental loss contingencies		(16	)
Balance, September 30, 2011(a)	$	14

(a) Expected to be paid out over one to 12 years.

PEC

PEC’s accruals relate to one former manufactured gas plant (MGP) site and other sites associated with PEC that have required, or are anticipated to require, investigation and/or remediation. Remediation of PEC’s other MGP sites has been substantially completed. During the nine months ended September 30, 2012, PEC completed a preliminary remedial action plan for its remaining MGP site, which indicates a range of viable remedial approaches with estimated costs up to $25 million. PEC has accrued approximately $7 million to reflect the estimated costs for the remedial approach considered to have more merit. 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.

PEF

PEF’s accruals 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 September 30, 2012, PEF’s accrual primarily relates to an MGP site located in Orlando, Fla. The potentially responsible parties (PRPs) for the Orlando MGP site have agreed to an interim allocation for the Orlando MGP site and are 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. During the nine months ended September 30, 2012, the PRPs received refined estimates for the range of viable remedial approaches. Additionally, the PRPs believe one approach has more merit than the other approaches; however, the recommendation has not been submitted to or approved by the United States Environmental Protection Agency (EPA) at this time. The PRPs for the Orlando MGP site intend 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 remedial approach considered to have more merit and its current allocation share, PEF accrued additional obligations of approximately $9 million during the nine months ended September 30, 2012, for remediation of soil and groundwater down to 50 feet. Based on current estimates for

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the range of viable remedial approaches and its current allocation share, PEF could incur additional obligations of up to approximately $8 million for remediation of soil and groundwater down to 50 feet. Results of an investigative study revealed the presence of MGP byproduct material at least 200 feet below 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.

CLEAN WATER ACT 316(b)

The EPA published its proposed cooling water intake structures rule on April 20, 2011. The proposed rule advances one main approach and three alternatives. The main approach establishes aquatic protection requirements for existing facilities and new on-site facility additions that withdraw 2 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Based on the main approach proposed, most, if not all of the coal, natural gas and nuclear-fueled steam electric-generating facilities in which the Progress Energy Registrants are either a whole or partial owner are likely affected sources unless retired prior to implementation of the 316(b) rule requirements. Additional sources, including some combined-cycle combustion turbine facilities may also be impacted, at least for intake modifications.

The EPA recently modified a previous settlement agreement that now calls for the EPA to finalize the 316(b) rule by June 2013. Compliance with portions of the rule could begin as early as 2016. Because of the wide range of potential outcomes, including the other three alternative proposals, the Progress Energy Registrants are unable to estimate their costs to comply at this time.

COAL COMBUSTION RESIDUALS (CCR) MANAGEMENT

On June 21, 2010, the EPA issued a proposal to regulate, under the Resource Conservation and Recovery Act, CCRs, a term the EPA uses to describe the coal combustion products associated with the generation of electricity. The EPA proposal contains two regulatory options whereby CCRs not employed in approved beneficial use applications would either be regulated as hazardous waste or would continue to be regulated as non-hazardous waste. We cannot predict the outcome of this rulemaking. However, based on the proposal, the cost of complying with the final regulation will be material. The timing of a final rule is uncertain. In response to a motion filed in federal court by environmental groups asking the court to compel the EPA to issue a final rule, the EPA filed a declaration on October 11, 2012, suggesting that it could take more than a year to complete the regulation.

CROSS-STATE AIR POLLUTION RULE (CSAPR)

On August 8, 2011, the final CSAPR was published in the Federal Register. The CSAPR established state-level annual SO2 and NOx budgets that were to take effect on January 1, 2012, and state-level ozone-season NOx budgets that were to take effect on May 1, 2012, allocating emission allowances to affected sources in each state equal to the state budget less an allowance set-aside for new sources. The budget levels were set to decline in 2014 for many states, including North Carolina. In South Carolina and Florida, the budgets were to remain constant. The rule allowed both intrastate and limited interstate allowance trading.

Numerous petitions for review of the CSAPR were filed with the United States Court of Appeals for the District of Columbia (D.C. Court of Appeals). On August 21, 2012, by a 2-1 decision, the D.C. Court of Appeals vacated the CSAPR. The court also directed the EPA to continue administering the Clean Air Interstate Rule (CAIR) that the Progress Energy Registrants have been complying with since 2009 pending completion of a remand rulemaking to replace CSAPR with a valid rule. CAIR requires additional Phase II reductions in SO2 and NOx emissions beginning in 2015. The court’s decision to vacate the CSAPR leaves the future of the rule uncertain. The EPA has filed a petition with the D.C. Court of Appeals for en banc rehearing of the CSAPR decision. If the court’s August 21, 2012 decision is upheld, the CAIR will remain in force for an unknown period of time until EPA develops a replacement rule. If the decision is overturned on rehearing, it is not known when EPA would move to implement the CSAPR.

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The Progress Energy Registrants cannot predict the outcome of the rehearing process or how it could affect future emission reduction requirements that might apply to the Progress Energy Registrants as a result of a potential CSAPR replacement rulemaking. The continued implementation of the CAIR pending the outcome of the rehearing process and a potential CSAPR replacement rulemaking, including the potential implementation of CAIR Phase II in 2015, will not result in the Progress Energy Registrants adding new emission controls.

MERCURY AND AIR TOXICS STANDARDS (MATS)

The final Mercury and Air Toxics Standards rule (previously referred to as the Utility maximum achievable control technology (MACT) Rule) was published in the Federal Register on February 16, 2012. The final rule establishes emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The rule requires sources to comply with the emission limits by April 16, 2015. Under the Clean Air Act, permitting authorities have the discretion to grant up to a 1-year compliance extension, on a case-by-case basis, to sources that are unable to complete the installation of emission controls before the compliance deadline. The Progress Energy Registrants continue to evaluate the requirements of the rule and develop strategies for complying with the rule’s requirements. Strategies to achieve compliance with the final MATS rule are likely to include installing new or upgrading existing air emission control equipment, developing monitoring processes and accelerating retirement of some coal-fired electric generating units. Due to significant investments in nitrogen oxides (NOx) and sulfur dioxide (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. For additional information, refer to Note 4.

Numerous petitions for review of the final MATS rule have been filed with the D.C. Court of Appeals. The court established a schedule for the litigation that has final briefs being filed on April 8, 2013. The Progress Energy Registrants cannot predict the outcome of the litigation or how it might affect the MATS requirements as they apply to the Progress Energy Registrants.

As finalized, the cost to the Progress Energy Registrants to comply with the regulation will be material.

CLEAN AIR VISIBILITY RULE (CAVR)

The EPA’s Clean Air Visibility Rule (CAVR) is an implementing regulation in its Regional Haze program that requires states to identify facilities, including power plants, built between August 1962 and August 1977 with the potential to produce emissions that affect visibility in certain specially protected areas, including national parks and wilderness areas, designated as Class I areas. To help restore visibility in those areas, states must require the identified facilities to install best available retrofit technology (BART) to control their emissions. PEF’s BART-eligible units are Anclote and CR1 and CR2. Under an agreement with the Florida Department of Environmental Protection (FDEP) that is reflected in a BART permit issued in final form on October 10, 2012, PEF will either retire its Crystal River Units No. 1 and No. 2 coal-fired steam turbines (CR1 and CR2) as coal-fired units by December 31, 2020 or install pollution control equipment by January 1, 2018. In addition, PEF will convert Anclote to 100 percent natural gas.

The FDEP is working with the EPA to complete development of an approvable regional haze state implementation plan by July 5, 2013, which is consistent with the BART permit issued by the FDEP on October 10, 2012. The outcome of these matters cannot be predicted.

EPA GREENHOUSE GAS NEW SOURCE PERFORMANCE STANDARDS (NSPS)

On April 13, 2012, the EPA published in the Federal Register its proposed rule to establish carbon dioxide (CO2) emissions standards for pulverized coal, integrated gasification combined cycle, and natural gas combined cycle electric-generating units that are permitted and constructed in the future. The proposal would not apply to any of the Progress Energy Registrants’ coal and natural gas electric generation plants that are currently under construction or in operation. Any future pulverized coal and integrated gasification combined cycle units will have to employ

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carbon capture and storage technology to meet the CO2 emission standard the EPA has proposed. The proposed standard will not require new natural gas combined cycle facilities to install carbon capture and storage technology.

Management does not expect any material impact on the Progress Energy Registrants’ future results of operations or cash flows based on the EPA’s proposal. The final rule, however, could be significantly different from the proposal. It is not known when the EPA might finalize the rule.

ESTIMATED COST AND IMPACTS OF EPA RULEMAKINGS

While the ultimate compliance requirements for the Progress Energy Registrants for MATS, Clean Water Act 316(b) and CCRs will not be known until all the rules have been finalized, for planning purposes, we currently estimate that if the decision is made to retire PEF’s CR1 and CR2, MATS compliance costs at the Utilities could range from $150 million to $320 million. If the units are not retired, PEF’s MATS compliance costs could exceed $1 billion. The Progress Energy Registrants also expect to incur increased fuel, purchased power, operation and maintenance, and other expenses in conjunction with these EPA regulations, and also expect to incur costs for replacement generation for potential coal-fired power plant retirements. Until the final regulatory requirements of the group of EPA regulations are known and can be fully evaluated, the potential compliance costs associated with these EPA regulatory actions are subject to considerable uncertainty. Therefore, the actual compliance costs incurred may be materially different from these estimates based on the timing and requirements of the final EPA regulations.

The Progress Energy Registrants intend to seek regulatory recovery of amounts incurred associated with regulated operations in complying with these regulations. Refer to Note 4 for further information regarding potential plant retirements and related regulatory filings.

B. LITIGATION

MERGER

On August 3, 2012, Duke Energy was served with a shareholder Derivative Complaint, which has been transferred to the North Carolina Business Court (Krieger v. Johnson, et al). The lawsuit names as defendants, William D. Johnson, James E. Rogers and the Legacy Duke Energy Directors. Duke Energy is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duty in granting excessive compensation to Mr. Johnson. We cannot predict the outcome of this matter.

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. In 2011, 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 in 2011 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 $113 million of damages with the U.S. Court of Federal Claims and the DOE. The total amount of damages could change during discovery, which is set to end on May 31, 2013. The Utilities may file subsequent damage claims as they incur additional costs. The next status conference to discuss trial dates is scheduled for May 10, 2013. We cannot predict the outcome of this matter.

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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 represented payment of the total judgment and a required premium equivalent to two years of interest at the then statutory rate, to the Broward County Clerk of Court bond account. The appellate briefing process has been completed. Oral argument on the appeal was held on September 27, 2011. On October 3, 2012, the Florida appellate court reversed the trial court ruling and directed a verdict on damages. The case was remanded to the trial court to determine whether specific performance is an appropriate remedy. On October 18, 2012, Global filed a Motion for Clarification and Rehearing of Panel Decision, which has yet to be ruled upon. On November 1, 2012, we filed a response in opposition to U.S. Global’s motion. 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 April 17, 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 outcome of 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.

C. 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 September 30, 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.

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At September 30, 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 September 30, 2012, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $219 million, including $45 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 September 30, 2012 and December 31, 2011, we had recorded liabilities related to guarantees and indemnifications to third parties of $28 million and $63 million, respectively. These amounts included $20 million and $37 million for PEF at September 30, 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 2) and the adjustment to the indemnification for the estimated future years’ joint owner replacement power costs related to the CR3 outage (See Note 8C of the 2011 Form 10-K). PEF’s liabilities decreased primarily due to the previously mentioned indemnification adjustment related to CR3. During the three and nine months ended September 30, 2012, our and the Utilities’ accruals and expenditures related to guarantees and indemnifications were not material. As current estimates change, 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 17).

D. OTHER COMMITMENTS AND CONTINGENCIES

As part of its normal business, the Progress Energy Registrants enter into various fixed-price, non-cancelable commitments to purchase or sell power (tolling agreements or power purchase contracts), take-or-pay arrangements, transportation or throughput agreements and other contracts that may or may not be recognized in the respective Balance Sheets. Some of these arrangements may be recognized at fair value in the respective Balance Sheets if such contracts meet the definition of a derivative and the normal purchase normal sale (NPNS) exception does not apply.

During the three and nine months ended September 30, 2012, there were no material changes in the Progress Energy Registrants’ other commitments and contingencies other than as follows:

PEC

As described in Note 22A in the 2011 Form 10-K, PEC entered into conditional agreements for firm pipeline transportation capacity to support PEC’s gas supply needs. As the transactions are subject to several conditions precedent, the estimated costs associated with these agreements were not included in PEC’s fuel commitments at December 31, 2011. The estimated total cost to PEC associated with these agreements at December 31, 2011, was approximately $1.510 billion, approximately $380 million of which relates to a capital lease. The agreements pertain to the period from July 2012 through May 2033. During the nine months ended September 30, 2012, the conditions precedent for two of the agreements, including the capital lease agreement, were satisfied. The agreements are through 2032 and have an estimated total cost of approximately $1.030 billion, including $20 million, $103 million, $103 million and $804 million, respectively, for less than one year, one to three years, three to five years and more than five years from December 31, 2011.

6. DEBT AND CREDIT FACILITIES

Significant changes to the Progress Energy Registrants’ debt and credit facilities since December 31, 2011, are as follows:

FIRST MORTGAGE BONDS

On May 18, 2012, PEC issued $500 million of 2.80% First Mortgage Bonds due May 15, 2022 and $500 million of 4.10% First Mortgage Bonds due May 15, 2042. The net proceeds were used to retire at maturity the $500 million

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outstanding aggregate principal balance of PEC’s 6.50% Notes due July 15, 2012, and a portion of PEC’s outstanding commercial paper and notes payable to affiliated companies.

OTHER DEBT

On March 8, 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.

AVAILABLE CREDIT FACILITIES

On July 2, 2012, the Parent terminated its $478 million RCA, and PEC and PEF terminated their respective $750 million RCAs and became borrowers under the Duke Energy Master Credit Facility (MCF). In November 2011, Duke Energy entered into a new $6.0 billion, five-year MCF, expiring in November 2016, with $4.0 billion available at closing and the remaining $2.0 billion available following consummation of the merger. In October 2012, Duke Energy reached an agreement with banks representing $5.63 billion of commitments under the MCF to extend the expiration date by one year to November 2017. Through November 2016, the available credit under this facility remains $6 billion. PEC and PEF each have borrowing capacity under the MCF up to $750 million. However, Duke Energy has the unilateral ability at any time to increase or decrease the borrowing sublimit of each borrower, subject to a maximum sublimit of $1.0 billion for PEC and PEF. Available capacity under the MCF for PEC and PEF has been reduced for certain amounts outstanding under the money pool arrangement described below. Available capacity for PEC and PEF as of September 30, 2012, was approximately $600 million for each utility. The Duke Energy MCF contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65% for each borrower, including PEC and PEF. Indebtedness as defined by the Duke Energy MCF includes certain letters of credit, surety bonds and guarantees not recorded in the Consolidated Balance Sheets. Following the merger, the cash needs of the Parent will be funded with dividends from the Utilities generated from their earnings and cash flows, and to a lesser extent, dividends from other subsidiaries; borrowings under an intercompany note with Duke Energy; and/or equity contributions from Duke Energy.

MONEY POOL

PEC, PEF and PESC receive support for their short-term borrowing needs through participation with Duke Energy and certain of its subsidiaries in a money pool arrangement. Under this arrangement, those companies with short-term funds may provide short-term loans to affiliates participating under this arrangement. The money pool is structured such that the participants separately manage their cash needs and working capital requirements. Accordingly, there is no net settlement of receivables and payables between the money pool participants. Per the terms of the money pool arrangement, the parent companies, including Duke Energy Corporation and Progress Energy, Inc., may loan funds to their participating subsidiaries, but may not borrow funds through the money pool.

Increases or decreases in money pool receivables are reflected within investing activities in the Progress Energy Registrants’ Statements of Cash Flows, while increases or decreases in money pool borrowings are reflected within financing activities in the Progress Energy Registrants’ Statements of Cash Flows.

CURRENT MATURITIES OF LONG-TERM DEBT

At September 30, 2012, PEC had $400 million of 5.125% First Mortgage Bonds due September 15, 2013 classified as current maturities of long-term debt in the Consolidated Balance Sheets. PEC expects to fund this obligation with proceeds from additional borrowings.

At September 30, 2012, PEF had $425 million of 4.80% First Mortgage Bonds due March 1, 2013 classified as current maturities of long-term debt in the Balance Sheets. PEF expects to fund this obligation with proceeds from additional borrowings.

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7. GOODWILL

In the third quarter of 2012, Progress Energy changed its goodwill impairment testing date for the PEC and PEF reporting units from October 31 to August 31. The change in the goodwill impairment test date is preferable as it better aligns the annual goodwill impairment testing procedures for PEC and PEF with the other reporting units of Duke Energy. This change in accounting principle did not accelerate, delay, avoid, or cause a goodwill impairment charge. Neither the change in the goodwill impairment testing date nor the merger resulted in any changes to the PEC or PEF reporting units. Due to significant judgments and estimates that are utilized in a goodwill impairment analysis, we determined it was impracticable to objectively determine, without the use of hindsight, projected cash flows and related valuation estimates as of each August 31 for periods prior to August 31, 2012. As such, we have prospectively applied the change in the annual goodwill impairment testing date from August 31, 2012. The results of our 2012 annual test of goodwill indicated the carrying amounts of goodwill were not impaired.

8. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

The Progress Energy Registrants utilize various derivative instruments to manage risks primarily associated with commodity prices and interest rates. The primary use of energy commodity derivatives is to hedge the generation portfolio against the changes in the prices of power and fuel. Interest rate derivatives are entered into to manage interest rate risk associated with variable-rate and fixed-rate borrowings.

Certain derivative instruments qualify for hedge accounting and are designated as cash flow hedges, while others either do not qualify as accounting hedges (such as economic hedges) or have not been designated as hedges (herein after referred to as undesignated contracts). All derivative instruments not meeting the criteria for the normal purchases or sales exception are recognized as either assets or liabilities at fair value in the Balance Sheets. As PEC and PEF meet the criteria for regulatory accounting treatment, the majority of the derivative contracts entered into by PEC and PEF are not designated as hedges since gains and losses on such contracts are deferred as regulatory liabilities and assets, respectively. Thus, there is no immediate earnings impact associated with changes in fair values of such derivative contracts. Cash flows relative to derivative instruments are considered operating activities based on the nature of the underlying transactions.

For derivative instruments that qualify and are designated as cash flow hedges, the effective portion of the gain or loss is reported as a component of Accumulated Other Comprehensive Income (AOCI) and reclassified into earnings in the same period or periods during which the hedged transactions affect earnings. Any gains or losses on the derivative that represent either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

A. COMMODITY PRICE RISK

The Progress Energy Registrants are exposed to the impact of market changes in the future prices of natural gas, coal, fuel oil, electricity and other energy-related products marketed and purchased as a result of our ownership of energy-related assets. With respect to commodity price risks associated with electricity generation, PEC and PEF are exposed to changes including, but not limited to, the cost of the coal, natural gas and fuel oil used to generate electricity, the prices of electricity in wholesale markets, the cost of capacity and electricity purchased for resale in wholesale markets and the cost of emissions allowances primarily at the coal fired power plants. Risks associated with commodity price changes on future operations are closely monitored and, where appropriate, various commodity contracts are used to mitigate the effect of such fluctuations on operations. Exposure to commodity price risk is influenced by a number of factors, including, but not limited to, the term of the contracts, the liquidity of the market and delivery location.

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COMMODITY CASH FLOW HEDGES

The Progress Energy Registrants use commodity instruments, such as swaps, futures, forwards and options, to protect margins for a portion of future revenues and fuel and purchased power expenses.

UNDESIGNATED CONTRACTS

The Progress Energy Registrants use derivative contracts as economic hedges to manage the market risk exposures that arise from providing electricity generation and capacity to large energy customers, energy aggregators, retail customers and other wholesale companies. Undesignated contracts may include contracts not designated as a hedge, contracts that do not qualify for hedge accounting, derivatives that do not or no longer qualify for the normal purchases or sales scope exemption, and de-designated hedge contracts. These undesignated contracts expire as late as 2015.

PEC uses derivative contracts as economic hedges to manage the market risk exposures that arise from electricity generation. PEC has also entered into firm power sale agreements, some of which are accounted for as derivative instruments, as part of the Interim FERC Mitigation in connection with Progress Energy's merger with Duke Energy (See Note 2). Undesignated contracts at September 30, 2012 are primarily associated with forward purchases and sales of electricity and forward purchases of fuel used in electricity generation.

PEF uses derivative contracts as economic hedges to manage the market risk exposures that arise from electricity generation. Undesignated contracts at September 30, 2012 are primarily associated with forward purchases of fuel used in electricity generation.

B. INTEREST RATE RISK

The Progress Energy Registrants are exposed to risk resulting from changes in interest rates as a result of their issuances or anticipated issuance of variable and fixed-rate debt and commercial paper. Interest rate exposure is managed by limiting variable-rate exposures to a percentage of total debt and by monitoring the effects of market changes in interest rates. To manage risk associated with changes in interest rates, the Progress Energy Registrants may enter into financial contracts; primarily interest rate swaps and U.S. Treasury lock agreements. Additionally, in anticipation of certain fixed-rate debt issuances, a series of forward starting interest rate swaps may be executed to lock in components of the market interest rates at the time and terminated prior to or upon the issuance of the corresponding debt. When these transactions occur within a business that meets the criteria for regulatory accounting treatment, these contracts may be treated as undesignated and any pre-tax gain or loss recognized from inception to termination of the hedges would be recorded as a regulatory liability or asset and amortized as a component of interest expense over the life of the debt. Alternatively, these derivatives may be designated as hedges whereby, any pre-tax gain or loss from inception to termination of the hedges would be recorded in AOCI and amortized as a component of interest expense over the life of the debt.

During the third quarter of 2012, $117 million and $42 million in pre-tax deferred net losses on derivative instruments related to interest rate cash flow hedges for regulated operations were reclassified from AOCI to regulatory assets at PEC and PEF, respectively.

The following tables show the notional amounts for derivatives related to interest rate risk:

Notional Amounts of Derivative Instruments Related to Interest Rate
	Progress Energy		PEC		PEF
(in millions)	September 30, 2012
Undesignated contracts	$	100	$	50	$	50
(in millions)	December 31, 2011
Cash flow hedges	$	500	$	250	$	50

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C. VOLUMES

The following tables show information relating to the volume of the Progress Energy Registrants’ outstanding commodity derivative activity. Amounts disclosed represent the notional volumes of commodities contracts accounted for at fair value. For option contracts, notional amounts include only delta-equivalent volumes which represent the notional volumes times the probability of exercising the option based on current price volatility. Volumes associated with contracts qualifying for the normal purchase or sales exceptions have been excluded from the tables below. Amounts disclosed represent the absolute value of notional amounts. Contractual amounts have been netted where offsetting purchase and sale contracts exist with identical delivery locations and times of delivery. Where all commodity positions are perfectly offset, no quantities are shown below. For additional information on notional dollar amounts of debt subject to derivative contracts accounted for at fair value, see “Interest Rate Risk” section above.

Underlying Notional Amounts for Commodity Derivative Instruments Accounted for At Fair Value
	Progress Energy		PEC		PEF
	September 30, 2012
Commodity contracts
Electricity-energy (Gigawatt-hours)(a)		1,850		1,850		-
Electricity-capacity (Gigawatt-months)(a)		5		5		-
Natural gas (millions of decatherms)		297		89		208
Fuel oil (millions of gallons)		6		-		6
	December 31, 2011
Commodity contracts
Natural gas (millions of decatherms)		347		103		244
Fuel oil (millions of gallons)		10		-		10

(a) Interim FERC Mitigation power sales agreements entered into in connection with the merger with Duke Energy.

40

D. DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

The following tables show fair value amounts of derivative contracts and the line item(s) in the Balance Sheets in which such amounts are included. The fair values of derivative contracts are presented on a gross basis, even when the derivative instruments are subject to master netting arrangements where the Progress Energy Registrants net the fair value of derivative contracts subject to master arrangements with the same counterparty in the Balance Sheets. Cash collateral payables and receivables associated with the derivative contracts have not been netted against the fair value amounts.

Location and Fair Value of Derivatives Reflected in the Balance Sheets
		Progress Energy						PEC					PEF
Instrument / Balance Sheet location		September 30, 2012
(in millions)	Asset			Liability			Asset			Liability			Asset		Liability
Derivatives designated as hedging instruments
Commodity contracts
Derivative liabilities, current					$	1					$	-			$	1
Total derivatives designated as hedging   instruments						1						-				1
Derivatives not designated as hedging instruments
Commodity contracts(a)
Investments and other assets: other		$	1			-		$	-			-	$	1		-
Derivative liabilities, current			8			220			3			74		5		146
Deferred credits and other liabilities: other			14			209			2			74		12		135
Interest rate contracts(a)
Derivative liabilities, current						23						11				12
CVOs(b)
Deferred credits and other liabilities: other						4						-				-
Total derivatives not designated as   hedging instruments			23			456			5			159		18		293
Total derivatives		$	23		$	457		$	5		$	159	$	18	$	294

(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 Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (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.

41

		Progress Energy						PEC					PEF
Instrument / Balance Sheet location	December 31, 2011
(in millions)	Asset			Liability			Asset			Liability			Asset		Liability
Derivatives designated as hedging instruments
Commodity contracts
Derivative liabilities, current					$	2					$	-			$	2
Deferred credits and other liabilities: other						1						-				1
Interest rate contracts
Derivative liabilities, current						76						38				-
Deferred credits and other liabilities: other						17						9				8
Total derivatives designated as hedging   instruments						96						47				11
Derivatives not designated as hedging instruments
Commodity contracts(a)
Derivative liabilities, current		$	5			357		$	-			91	$	5		266
Deferred credits and other liabilities: other			-			332			-			110		-		222
CVOs(b)
Current liabilities: other						14						-				-
Total derivatives not designated as   hedging instruments			5			703			-			201		5		488
Total derivatives		$	5		$	799		$	-		$	248	$	5	$	499

(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. In 2011, we repurchased and continue to hold 80.1 million CVOs in a negotiated settlement agreement and subsequent tender offer.

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The following tables show the amount of gains and losses recognized on derivative instruments designated and qualifying as cash flow hedges by type of derivative contract and the Statements line items in which such gains and losses are included.

Cash Flow Hedges - Location and Amount of Pre-Tax Gains and (Losses) Recognized in Comprehensive  Income
	Progres  Energy						PEC					PEF
	Three months ended September 30
(in millions)	2012			2011			2012		2011			2012		2011
Pre-tax gains (losses) recognized in OCI(a)
Commodity contracts	$	1		$	(1	)	$	-	$	-		$	1	$	(1	)
Interest rate contracts(b)		-			(111	)		-		(58	)		-		(27	)
Total pre-tax gains (losses) recognized in   OCI	$	1		$	(112	)	$	-	$	(58	)	$	1	$	(28	)
Location of pre-tax gains (losses) reclassified   from OCI into income(a)
Interest rate contracts(b)
Interest expense	$	(2	)	$	(3	)	$	-	$	(2	)	$	-	$	-
Total pre-tax gains (losses) reclassified from   OCI into income	$	(2	)	$	(3	)	$	-	$	(2	)	$	-	$	-
Location of pre-tax gains (losses) recognized   in income on derivatives(c)
Interest rate contracts(b)
Interest expense	$	-		$	(1	)	$	-	$	(1	)	$	-	$	-
Total pre-tax gains (losses) recognized in   income on derivatives	$	-		$	(1	)	$	-	$	(1	)	$	-	$	-

(a)	Effective portion.
(b)	Amounts in AOCI 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.
(c)	Related to ineffective portion and amount excluded from effectiveness testing.

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	Progress Energy						PEC						PEF
	Nine months ended September 30
(in millions)	2012			2011			2012			2011			2012			2011
Pre-tax gains (losses) recognized in OCI(a)
Commodity contracts	$	1		$	(1	)	$	-		$	-		$	1		$	(1	)
Interest rate contracts(b)		(11	)		(134	)		(7	)		(67	)		(2	)		(35	)
Total pre-tax gains (losses) recognized in   OCI	$	(10	)	$	(135	)	$	(7	)	$	(67	)	$	(1	)	$	(36	)
Location of pre-tax gains (losses) reclassified   from OCI into income(a)
Interest rate contracts(b)
Interest expense	$	(12	)	$	(9	)	$	(5	)	$	(5	)	$	(2	)	$	-
Total pre-tax gains (losses) reclassified from   OCI into income	$	(12	)	$	(9	)	$	(5	)	$	(5	)	$	(2	)	$	-
Location of pre-tax gains (losses) recognized   in income on derivatives(c)
Interest rate contracts(b)
Interest expense	$	-		$	(3	)	$	-		$	(1	)	$	-		$	-
Total pre-tax gains (losses) recognized in   income on derivatives	$	-		$	(3	)	$	-		$	(1	)	$	-		$	-

(a)	Effective portion.
(b)	Amounts in AOCI 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.
(c)	Related to ineffective portion and amount excluded from effectiveness testing.

PROGRESS ENERGY

At September 30, 2012 and December 31, 2011, $71 million and $232 million, respectively, of pre-tax deferred net losses on derivative instruments related to interest rate cash flow hedges remained in AOCI and $5 million pre-tax loss is expected to be recognized in earnings during the next 12 months as the hedged transactions occur.

PEC

At December 31, 2011, $116 million of pre-tax deferred net losses on derivative instruments related to interest rate cash flow hedges remained in AOCI. At September 30, 2012, such losses were reclassified to regulatory assets.

PEF

At December 31, 2011, $41 million of pre-tax deferred net losses on derivative instruments related to interest rate cash flow hedges remained in AOCI. At September 30, 2012, such losses were reclassified to regulatory assets.

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The following tables show the amount of the pre-tax gains and losses recognized on undesignated contracts by type of derivative instrument and the line item(s) in the Statements of Operations and Comprehensive Income in which such gains and losses are included or deferred in the Balance Sheets as regulatory assets and liabilities.

Undesignated Contracts - Location and Amount of Pre-Tax Gains and (Losses) Recognized in Income or as  Regulatory Assets or Liabilities
	Progress Energy						PEC						PEF
	Three months ended September 30
(in millions)	2012			2011			2012			2011			2012			2011
Location of pre-tax gains and (losses)   recognized in earnings
Commodity contracts
Regulated electric revenue	$	(9	)	$	-		$	(9	)	$	-		$	-		$	-
Fuel used in electric generation and   purchased power(a)		(135	)		(91	)		(35	)		(20	)		(100	)		(71	)
Interest rate contracts
Interest expense(b)		(4	)		-			(3	)		-			(1	)		-
Total pre-tax gains (losses) recognized in   earnings	$	(148	)	$	(91	)	$	(47	)	$	(20	)	$	(101	)	$	(71	)
Location of pre-tax gains and (losses)   recognized as regulatory assets or liabilities
Commodity contracts(c)
Regulatory asset	$	60		$	(157	)	$	15		$	(42	)	$	45		$	(115	)
Interest rate contracts(b)
Regulatory asset		2			-			2			-			-			-
Total pre-tax gains (losses) recognized as   regulatory assets or liabilities	$	62		$	(157	)	$	17		$	(42	)	$	45		$	(115	)
Location of pre-tax gains and (losses)   recognized in income on derivatives
Fair value loss transition adjustment
Regulated electric revenue	$	-		$	1		$	-		$	1		$	-		$	-
CVOs
Other income and expenses, net		(1	)		(63	)		-			-			-			-
Total pre-tax gains (losses) recognized in   income on derivatives	$	(1	)	$	(62	)	$	-		$	1		$	-		$	-

(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts in regulatory assets and liabilities related to terminated hedges are reclassified to earnings as the interest expense is recorded. The hedges will be amortized to interest expense over the term of the related debt.
(c)	Amounts are recorded in regulatory assets and liabilities in the Balance Sheets until derivatives are settled.

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	Progress Energy						PEC						PEF
	Nine months ended September 30
(in millions)	2012			2011			2012			2011			2012			2011
Location of pre-tax gains and (losses)   recognized in earnings
Commodity contracts
Regulated electric revenue	$	(9	)	$	-		$	(9	)	$	-		$	-		$	-
Fuel used in electric generation and   purchased power(a)		(395	)		(219	)		(100	)		(42	)		(295	)		(177	)
Interest rate contracts
Interest expense(b)		(4	)		-			(3	)		-			(1	)		-
Total pre-tax gains (losses) recognized in   earnings	$	(408	)	$	(219	)	$	(112	)	$	(42	)	$	(296	)	$	(177	)
Location of pre-tax gains and (losses)   recognized as regulatory assets or liabilities
Commodity contracts(c)
Regulatory asset	$	(108	)	$	(201	)	$	(34	)	$	(55	)	$	(74	)	$	(146	)
Interest rate contracts(b)
Regulatory asset		2			-			2			-			-			-
Total pre-tax gains (losses) recognized as   regulatory assets or liabilities	$	(106	)	$	(201	)	$	(32	)	$	(55	)	$	(74	)	$	(146	)
Location of pre-tax gains and (losses)   recognized in income on derivatives
Commodity contracts
Regulated electric revenue	$	2		$	1		$	2		$	1		$	-		$	-
Fair value loss transition adjustment
Regulated electric revenue		1			1			1			1			-			-
CVOs
Other income and expenses, net		7			(59	)		-			-			-			-
Total pre-tax gains (losses) recognized in   income on derivatives	$	10		$	(57	)	$	3		$	2		$	-		$	-

(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts in regulatory assets and liabilities related to terminated hedges are reclassified to earnings as the interest expense is recorded. The hedges will be amortized to interest expense over the term of the related debt.
(c)	Amounts are recorded in regulatory assets and liabilities in the Balance Sheets until derivatives are settled.

E. CREDIT RISK

Certain of PEC and PEF’s derivative contracts contain contingent features, such as material adverse change clauses or payment acceleration clauses that could result in immediate payments, the posting of letters of credit or the termination of the derivative contract before maturity if specific events occur, such as a downgrade in the individual company’s credit rating below investment grade.

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The following tables show information with respect to derivative contracts that are in a net liability position and contain objective credit-risk-related payment provisions. The amounts disclosed in the table below represent the aggregate fair value amounts of such derivative instruments at the end of the reporting period, the aggregate fair value of assets that are already posted as collateral under such derivative instruments at the end of the reporting period and the aggregate fair value of the additional assets that would need to be transferred in the event that credit-risk-related contingent features were triggered.

Information Regarding Derivative Instruments that Contain Credit-Risk-Related Contingent Features
	Progress Energy		PEC			PEF
(in millions)	September 30, 2012
Aggregate fair value amounts of derivative instruments in a net liability   position	$	325		$	118		$	207
Collateral already posted		74			13			61
Additional cash collateral or letters of credit in the event credit-risk-related   contingent features were triggered at the end of the reporting period		251			105			146
(in millions)	December 31, 2011
Aggregate fair value amounts of derivative instruments in a net liability   position	$	489		$	152		$	337
Collateral already posted		147			24			123
Additional cash collateral or letters of credit in the event credit-risk-related   contingent features were triggered at the end of the reporting period		342			128			214

NETTING OF CASH COLLATERAL AND DERIVATIVE ASSETS AND LIABILITIES UNDER MASTER NETTING ARRANGEMENTS

In accordance with applicable accounting rules, the Progress Energy Registrants have elected to offset fair value amounts (or amounts that approximate fair value) recognized in their Balance Sheets related to cash collateral amounts receivable or payable against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting agreement. The amounts disclosed in the table below represent the receivables related to the right to reclaim cash collateral and payables related to the obligation to return cash collateral under master netting arrangements. See Note 9 for additional information on fair value disclosures related to derivatives.

Information Regarding Cash Collateral under Master Netting Arrangements
		Progress Energy						PEC						PEF
	September 30, 2012
(in millions)	Receivables			Payables			Receivables			Payables			Receivables			Payables
Amounts offset against net   derivative positions		$	73		$	-		$	13		$	-		$	60		$	-
Amounts not offset against net   derivative positions			1			-			-			-			1			-
	December 31, 2011
(in millions)	Receivables			Payables			Receivables			Payables			Receivables			Payables
Amounts offset against net   derivative positions		$	140		$	-		$	23		$	-		$	117		$	-
Amounts not offset against net   derivative positions			3			-			-			-			3			-

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9. FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES

Under existing accounting guidance, fair value is considered to be the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date. The fair value definition focuses on an exit price, which is the price that would be received to sell an asset or paid to transfer a liability versus an entry price, which would be the price paid to acquire an asset or received to assume a liability.

The Progress Energy Registrants classify recurring and non-recurring fair value measurements based on the following fair value hierarchy, as prescribed by the accounting guidance for fair value, which prioritizes the inputs to valuation techniques used to measure fair value into three levels:

Level 1 – unadjusted quoted prices in active markets for identical assets or liabilities that the Progress Energy Registrants have the ability to access. An active market for the asset or liability is one in which transactions for the asset or liability occurs with sufficient frequency and volume to provide ongoing pricing information. The Progress Energy Registrants do not adjust quoted market prices on Level 1 for any blockage factor.

Level 2 – a fair value measurement utilizing inputs other than a quoted market price that are observable, either directly or indirectly, for the asset or liability. Level 2 inputs include, but are not limited to, quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active and inputs other than quoted market prices that are observable for the asset or liability, such as interest rate curves and yield curves observable at commonly quoted intervals, volatilities, credit risk and default rates. A Level 2 measurement cannot have more than an insignificant portion of the valuation based on unobservable inputs.

Level 3 – any fair value measurements which include unobservable inputs for the asset or liability for more than an insignificant portion of the valuation. A level 3 measurement may be based primarily on Level 2 inputs.

The fair value accounting guidance for financial instruments permits entities to elect to measure many financial instruments and certain other items at fair value that are not required to be accounted for at fair value under other GAAP. There are no financial assets or financial liabilities that are not required to be accounted for at fair value under GAAP for which the option to record at fair value has been elected by the Progress Energy Registrants. However, in the future, the Progress Energy Registrants may elect to measure certain financial instruments at fair value in accordance with this accounting guidance.

Nuclear Decommissioning Trust (NDTs) 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 CVOs, which are derivatives, in connection with the acquisition of Florida Progress. CVOs are further discussed in Note 8. At September 30, 2011, we determined the fair value of the CVOs based on the purchase price in a negotiated settlement agreement (a Level 3 input) and we classified CVOs as Level 3. The CVOs were previously recorded at fair value based on quoted prices from a less-than-active market and classified as Level 2. In November 2011, we commenced a public tender offer that expired on February 15, 2012. At September 30, 2012 and December 31, 2011, all CVOs not tendered, have been classified as Level 2 based on observable prices in the less-than-active market.

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. The Progress Energy Registrants’ policy for the recognition of transfers between levels of the fair value hierarchy is to recognize the transfer at the end of the period. There were no transfers into (out of) Levels 1, 2 and 3 during the periods other than the CVO transfer previously discussed.
 

48

Valuation methods of the primary fair value measurements disclosed below are as follows:

Investments in equity securities – Investments in equity securities, other than those accounted for as equity and cost method investments, are typically valued at the closing price in the principal active market as of the last business day of the quarter. Principal active markets for equity prices include published exchanges such as NASDAQ and NYSE. Foreign equity prices are translated from their trading currency using the currency exchange rate in effect at the close of the principal active market. Prices have not been adjusted to reflect for after-hours market activity. The majority of investments in equity securities are valued using Level 1 measurements.

Investments in debt securities – Most debt investments (including those held in the NDT) are valued based on a calculation using interest rate curves and credit spreads applied to the terms of the debt instrument (maturity and coupon interest rate) and consider the counterparty credit rating. Most debt valuations are Level 2 measurements. If the market for a particular fixed income security is relatively inactive or illiquid, the measurement is a Level 3 measurement. U.S. Treasury debt is typically a Level 1 measurement.

Commodity derivatives – The pricing for commodity derivatives is primarily a calculated value which incorporates the forward price and is adjusted for liquidity (bid-ask spread), credit or non-performance risk (after reflecting credit enhancements such as collateral) and discounted to present value. The primary difference between a Level 2 and a Level 3 measurement relates to the level of activity in forward markets for the commodity. If the market is relatively inactive, the measurement is deemed to be a Level 3 measurement. Commodity derivatives with clearinghouses are classified as Level 1 measurements.

The following tables provide the fair value measurement amounts for financial assets and liabilities recorded at fair value on our and the Utilities’ Balance Sheets. Derivative amounts in the tables below exclude cash collateral amounts, which are disclosed in Note 8. See Note 10 for additional information related to investments by major security type.

PROGRESS ENERGY
(in millions)	Total			Level 1		Level 2			Level 3
September 30, 2012
Nuclear decommissioning trust fund equity securities	$	1,226		$	1,220	$	6		$	-
Nuclear decommissioning trust fund debt securities and other		618			131		487			-
Other long-term available-for-sale debt securities and other(a)		60			21		39			-
Derivative assets(b)		1			-		1			-
Total assets		1,905			1,372		533			-
Derivative liabilities(c)		(435	)		-		(399	)		(36	)
Net assets	$	1,470		$	1,372	$	134		$	(36	)

(in millions)	Total			Level 1		Level 2			Level 3
December 31, 2011
Nuclear decommissioning trust fund equity securities	$	1,062		$	1,061	$	1		$	-
Nuclear decommissioning trust fund debt securities and other		585			87		498			-
Other long-term available-for-sale debt securities and other(a)		20			20		-			-
Derivative assets(b)		5			-		5			-
Total assets		1,672			1,168		504			-
Derivative liabilities(c)		(799	)		-		(775	)		(24	)
Net assets	$	873		$	1,168	$	(271	)	$	(24	)

(a)	Included in Other within Investments and Other Assets in the Consolidated Balance Sheets.
(b)	Included in Prepayments and Other Current Assets within Current Assets and Other within Investments and Other Assets in the Consolidated Balance Sheets.
(c)	Included in Derivative Liabilities within Current Liabilities and Other within Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.

49

PEC
(in millions)	Total			Level 1		Level 2			Level 3
September 30, 2012
Nuclear decommissioning trust fund equity securities	$	797		$	797	$	-		$	-
Nuclear decommissioning trust fund debt securities and other		426			105		321			-
Other long-term available-for-sale debt securities and other(a)		6			6		-			-
Total assets		1,229			908		321			-
Derivative liabilities(c)		(155	)		-		(119	)		(36	)
Net assets	$	1,074		$	908	$	202		$	(36	)
(in millions)	Total			Level 1		Level 2			Level 3
December 31, 2011
Nuclear decommissioning trust fund equity securities	$	690		$	690	$	-		$	-
Nuclear decommissioning trust fund debt securities and other		398			81		317			-
Other long-term available-for-sale debt securities and other(a)		6			6		-			-
Total assets		1,094			777		317			-
Derivative liabilities(c)		(248	)		-		(224	)		(24	)
Net assets	$	846		$	777	$	93		$	(24	)

(a)	Included in Other within Investments and Other Assets in the Consolidated Balance Sheets.
(b)	Included in Prepayments and Other Current Assets within Current Assets and Other within Investments and Other Assets in the Consolidated Balance Sheets.
(c)	Included in Derivative Liabilities within Current Liabilities and Other within Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.

PEF
(in millions)	Total			Level 1		Level 2			Level 3
September 30, 2012
Nuclear decommissioning trust fund equity securities	$	429		$	423	$	6		$	-
Nuclear decommissioning trust fund debt securities and other		192			26		166			-
Other long-term available-for-sale debt securities and other(a)		41			2		39			-
Derivative assets(b)		1			-		1			-
Total assets		663			451		212			-
Derivative liabilities(c)		(276	)		-		(276	)		-
Net assets	$	387		$	451	$	(64	)	$	-
(in millions)	Total			Level 1		Level 2			Level 3
December 31, 2011
Nuclear decommissioning trust fund equity securities	$	372		$	371	$	1		$	-
Nuclear decommissioning trust fund debt securities and other		187			6		181			-
Other long-term available-for-sale debt securities and other(a)		1			1		-			-
Derivative assets(b)		5			-		5			-
Total assets		565			378		187			-
Derivative liabilities(c)		(499	)		-		(499	)		-
Net assets	$	66		$	378	$	(312	)	$	-

(a)	Included in Other within Investments and Other Assets in the Balance Sheets.
(b)	Included in Prepayments and Other Current Assets within Current Assets and Other within Investments and Other Assets in the Balance Sheets.
(c)	Included in Derivative Liabilities within Current Liabilities and Other within Deferred Credits and Other Liabilities in the Balance Sheets.

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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.

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 periods ended September 30 follows:

PROGRESS ENERGY
	Three months ended September 30					Nine months ended September 30
(in millions)	2012			2011		2012			2011
Derivatives, net at beginning of period	$	30		$	37	$	24		$	36
Total pre-tax realized or unrealized gains   included in earnings − regulated electric		(2	)		-		(2	)		-
Total (gains) losses, included in the consolidated   Balance Sheet as regulatory asset or liability		(4	)		6		2			7
Issuances		16			-		16			-
Settlements		(4	)		-		(4	)		-
Transfers into Level 3 − CVOs		-			74		-			74
Derivatives, net at end of period	$	36		$	117	$	36		$	117

PEC
	Three months ended September 30					Nine months ended September 30
(in millions)	2012			2011		2012			2011
Derivatives, net at beginning of period	$	28		$	37	$	24		$	36
Total pre-tax realized or unrealized gains   included in earnings − regulated electric		(2	)		-		(2	)		-
Total (gains) losses, included in the consolidated   Balance Sheet as regulatory asset or liability		(2	)		5		2			6
Issuances		16			-		16			-
Settlements		(4	)		-		(4	)		-
Derivatives, net at end of period	$	36		$	42	$	36		$	42

During the three and nine months ended September 30, 2012 and 2011, PEF’s assets and liabilities classified as Level 3 were not material.

Substantially all unrealized gains and losses on derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment. Unrealized losses on the change in fair value of our CVOs are discussed in Note 8. 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. 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. For the commodity derivative contracts classified as Level 3, the pricing inputs for natural gas and electricity forward price curves are not observable for the full term of the related contracts. In isolation, increases (decreases) in unobservable natural gas forward prices would result in favorable (unfavorable) fair value adjustments for gas purchase contracts. In isolation, increases (decreases) in unobservable electricity forward prices would result in unfavorable (favorable) fair value adjustments for electricity sales contracts. We regularly evaluate and validate the pricing inputs we use to estimate fair value of

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gas purchase contracts 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’s derivative liabilities classified as Level 3 follows:

PROGRESS ENERGY
(in millions)	Fair Value			Valuation Technique	Unobservable Input	Range
September 30, 2012
Commodity natural   gas hedges		$	27	Discounted cash flow	Forward natural gas curves -   price per MMBtu	$	4.178	-	4.588
FERC mitigation   power sale agreements			9	Discounted cash flow	Forward electricity curves -   price per MWh		24.88	-	49.78

PEC
(in millions)	Fair Value			Valuation Technique	Unobservable Input	Range
September 30, 2012
Commodity natural   gas hedges		$	27	Discounted cash flow	Forward natural gas curves -   price per MMBtu	$	4.178	-	4.588
FERC mitigation   power sale agreements			9	Discounted cash flow	Forward electricity curves -   price per MWh		24.88	-	49.78

ADDITIONAL FAIR VALUE DISCLOSURES

At September 30, 2012 and December 31, 2011, the fair value of cash and cash equivalents, accounts and notes receivable, accounts payable, notes payable and commercial paper and non-recourse notes payable of variable interest entities are not materially different from their carrying amounts because of the short-term nature of these instruments and/or because the stated rates approximate market rates.

The fair value of our long-term debt, including current maturities, is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined are not necessarily indicative of the amounts the Progress Energy Registrants could have settled in current markets. The fair value of the long-term debt is determined using Level 2 measurements.

	September 30, 2012				December 31, 2011
(in millions)	Book Value		Fair Value		Book Value		Fair Value
Progress Energy	$	13,776	$	16,160	$	13,152	$	15,518
PEC		4,838		5,352		4,206		4,735
PEF		4,672		5,646		4,681		5,633

10. INVESTMENTS IN DEBT AND EQUITY SECURITIES

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities, which are reported at fair value in the Balance Sheets with unrealized gains and losses excluded from earnings and reported either as a regulatory asset or liability.

Our available-for-sale securities are primarily comprised of investments held in PEC’s and PEF’s NDTs, pursuant to NRC requirements, to fund certain costs of decommissioning the Utilities’ nuclear plants as discussed in Note 5C of the 2011Form 10-K, as well as investments in a grantor trust at PEF related to other post-retirement benefit plans. Progress Energy classifies its investments in debt and equity securities held within the PEC and PEF NDTs and the PEF grantor trust as long-term.

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The investments within the PEC and PEF NDTs and the PEF grantor trust are managed by independent investment managers with discretion to buy, sell and invest pursuant to the objectives set forth by the trust agreements. Therefore, we and the Utilities have limited oversight of the day-to-day management of these investments. Since day-to-day investment decisions, including buy and sell decisions, are made by the investment manager, the ability to hold investments in unrealized loss positions is outside our and the Utilities’ control. Accordingly, all unrealized gains and losses associated with equity securities within the PEC and PEF NDTs and the PEF grantor trust are considered other-than-temporary and are recognized immediately when the fair value of individual investments is less than the cost basis of the investment. Pursuant to regulatory accounting, substantially all realized and unrealized gains and losses associated with investments in debt and equity securities within the PEC and PEF NDTs and the PEF grantor trust are deferred as a regulatory asset or liability. As a result, there is no immediate impact on our or the Utilities’ earnings. Therefore, the following tables include the unrealized gains and losses for the NDT and the PEF grantor trust funds based on the original cost of the trust investments.

The following tables summarize Progress Energy’s, PEC’s and PEF’s available-for-sale securities at September 30, 2012 and December 31, 2011:

PROGRESS ENERGY
(in millions)	Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2012
Nuclear decommissioning trust funds
Equity securities	$	1,226	$	21	$	534
Corporate debt securities		85		-		9
Municipal bonds		134		1		10
U.S. government bonds		295		-		17
Other		104		1		3
Total nuclear decommissioning trust funds		1,844		23		573
Other investments
Municipal bonds		39		-		-
Other		21		-		-
Total	$	1,904	$	23	$	573
December 31, 2011
Nuclear decommissioning trust funds
Equity securities	$	1,062	$	29	$	412
Corporate debt securities		86		-		6
Municipal bonds		127		2		7
U.S. government bonds		268		-		18
Other		87		-		1
Total nuclear decommissioning trust funds		1,630		31		444
Other investments
Other		20		-		-
Total	$	1,650	$	31	$	444

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PEC
(in millions)	Fair Value			Unrealized Losses			Unrealized Gains
September 30, 2012
Nuclear decommissioning trust funds
Equity securities		$	797		$	15		$	340
Corporate debt securities			75			-			8
Municipal bonds			61			-			4
U.S. government bonds			230			-			15
Other			60			-			1
Total nuclear decommissioning trust funds			1,223			15			368
Other investments
Other			6			-			-
Total		$	1,229		$	15		$	368
December 31, 2011
Nuclear decommissioning trust funds
Equity securities		$	690		$	20		$	262
Corporate debt securities			69			-			5
Municipal bonds			55			-			3
U.S. government bonds			225			-			16
Other			62			-			1
Total nuclear decommissioning trust funds			1,101			20			287
Other investments
Other			6			-			-
Total		$	1,107		$	20		$	287

PEF
(in millions)	Fair Value			Unrealized Losses			Unrealized Gains
September 30, 2012
Nuclear decommissioning trust funds
Equity securities		$	429		$	6		$	194
Corporate debt securities			10			-			1
Municipal bonds			73			1			6
U.S. government bonds			65			-			2
Other			44			1			2
Total nuclear decommissioning trust funds			621			8			205
Other investments
Municipal bonds			39			-			-
Other			2			-			-
Total		$	662		$	8		$	205
December 31, 2011
Nuclear decommissioning trust funds
Equity securities		$	372		$	9		$	150
Corporate debt securities			17			-			1
Municipal bonds			72			2			4
U.S. government bonds			43			-			2
Other			25			-			-
Total nuclear decommissioning trust funds			529			11			157
Other investments
Other			1			-			-
Total		$	530		$	11		$	157

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The table below summarizes the maturity date for available-for-sale debt securities held by Progress Energy, PEC and PEF at September 30, 2012:

(in millions)	< 1 Year		1-5 Years		6-10 Years		Thereafter		Total
Progress Energy	$	13	$	125	$	136	$	301	$	575
PEC		11		102		72		194		379
PEF		2		18		55		82		157

The following tables present selected information about Progress Energy’s, PEC’s and PEF’s sales of available-for-sale securities during the three and nine months ended September 30, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.

PROGRESS ENERGY
	Three months ended September 30					Nine months ended September 30
(in millions)		2012		2011			2012		2011
Proceeds		$	274	$	1,062		$	794	$	4,254
Realized gains			8		9			23		24
Realized losses			6		11			12		20

PEC
	Three months ended September 30					Nine months ended September 30
(in millions)			2012		2011			2012		2011
Proceeds		$	101	$	136		$	351	$	386
Realized gains			4		4			14		10
Realized losses			2		4			5		9

PEF
	Three months ended September 30					Nine months ended September 30
(in millions)			2012		2011			2012		2011
Proceeds		$	173	$	926		$	443	$	3,861
Realized gains			4		5			9		14
Realized losses			4		7			7		11

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The fair values and gross unrealized losses of available-for-sale debt and equity securities, which are in an unrealized loss position for which other-than-temporary investment losses have not been recorded in earnings, summarized by investment type and length of time that the securities have been in continuous loss position, are presented in the tables below for Progress Energy, PEC and PEF at September 30, 2012 and December 31, 2011:

PROGRESS ENERGY
(in millions)	Fair Value				Unrealized Loss Positions > 12 months			Unrealized Loss Positions < 12 months
September 30, 2012
Nuclear decommissioning trust funds
Equity securities		$	89			$	13		$	8
Corporate debt securities			3				-			-
Municipal bonds			14				1			-
U.S. government bonds			10				-			-
Other			1				-			1
Total nuclear decommissioning trust funds			117				14			9
Other investments
Other			4				-			-
Total		$	121			$	14		$	9
December 31, 2011
Nuclear decommissioning trust funds
Equity securities		$	112			$	10		$	19
Corporate debt securities			20				-			-
Municipal bonds			21				2			-
U.S. government bonds			(23	)			-			-
Other			6				-			-
Total		$	136			$	12		$	19

PEC
(in millions)	Fair Value			Unrealized Loss Positions > 12 months			Unrealized Loss Positions < 12 months
September 30, 2012
Nuclear decommissioning trust funds
Equity securities		$	56		$	10		$	5
Corporate debt securities			2			-			-
Municipal bonds			5			-			-
U.S. government bonds			11			-			-
Other			-			-			-
Total		$	74		$	10		$	5
December 31, 2011
Nuclear decommissioning trust funds
Equity securities		$	69		$	10		$	10
Corporate debt securities			10			-			-
Municipal bonds			8			-			-
U.S. government bonds			9			-			-
Other			2			-			-
Total		$	98		$	10		$	10

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PEF
(in millions)	Fair Value			Unrealized Loss Positions > 12 months		Unrealized Loss Positions < 12 months
September 30, 2012
Nuclear decommissioning trust funds
Equity securities	$	33		$	3	$	3
Municipal bonds		9			1		-
Other		1			-		1
Total nuclear decommissioning trust funds		43			4		4
Other investments
Other		4			-		-
Total	$	47		$	4	$	4
December 31, 2011
Nuclear decommissioning trust funds
Equity securities	$	43		$	-	$	9
Corporate debt securities		10			-		-
Municipal bonds		13			2		-
U.S. government bonds		(32	)		-		-
Other		4			-		-
Total	$	38		$	2	$	9

Unrealized losses on investments within the PEC and PEF NDTs and the PEF grantor trust are deferred as regulatory assets pursuant to regulatory accounting treatment.

11. VARIABLE INTEREST ENTITIES

A variable interest entity (VIE) is an entity that is evaluated for consolidation using more than a simple analysis of voting control. The analysis to determine whether an entity is a VIE considers contracts with an entity, credit support for an entity, the adequacy of the equity investment of an entity and the relationship of voting power to the amount of equity invested in an entity. This analysis is performed either upon the creation of a legal entity or upon the occurrence of an event requiring reevaluation, such as a significant change in the entity’s assets or activities. If an entity is determined to be a VIE, a qualitative analysis of control determines the party that consolidates a VIE based on what party has the power to direct the most significant activities of the VIE that impact its economic performance as well as what party has rights to receive benefits or is obligated to absorb losses that are significant to the VIE. The analysis of the party that consolidates a VIE is a continual reassessment.

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A. CONSOLIDATED VIEs

The following table shows the VIE that Progress Energy, through its subsidiary PEC consolidates and how the entity impacts Progress Energy’s and PEC’s respective Consolidated Balance Sheets. No financial support was provided to the consolidated VIE during the nine months ended September 30, 2012 and the year ended 2011, or is expected to be provided in the future, that was not previously contractually required.

(in millions)	September 30, 2012		December 31, 2011
Net property, plant and equipment(a)	$	12	$	12
Prepayments and other current assets(a)		2		1
Net assets of consolidated VIEs	$	14	$	13

(a) 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. 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.

B. NON-CONSOLIDATED VIEs

Progress Energy has variable interests in the FPC Capital I Trust (the Trust), which is a VIE of which we are not the primary beneficiary (See Note 17). Amounts reflected in the Consolidated Balance Sheets of Progress Energy related to the Trust are a $9 million equity investment (included in investments and other assets, other) at September 30, 2012 and December 31, 2011, and long-term debt, affiliate of $274 million and $273 million at September 30, 2012 and December 31, 2011, respectively. Our maximum exposure to loss that could potentially be recorded through earnings in future periods is the $9 million equity investment in the Trust.

PEC

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

PEF

PEF has no significant variable interests in VIEs.

12. BENEFIT PLANS

COSTS OF BENEFIT PLANS

Net periodic benefit costs disclosed in the following tables for the qualified pension, non-qualified pension and other post-retirement benefit plans represent the cost of the respective benefit plan to the Progress Energy Registrants for the periods presented. However, portions of the net periodic benefit costs disclosed in the tables below have been capitalized as a component of property, plant and equipment.

Each of the Utilities participate in the qualified pension plans, non-qualified pension plans and other post-retirement benefit plans sponsored by Progress Energy. The net periodic benefit costs shown in the tables below represent their allocated cost of the respective benefit plan for the periods presented. Additionally, the Utilities are allocated their proportionate share of pension and other post-retirement benefit costs for PESC employees that provide support to the Utilities. These allocated amounts are included in the governance and shared services costs for the Utilities discussed in Note 15.

In conjunction with the merger, we offered a voluntary severance plan to certain employees in November 2011. The voluntary severance plan included additional coverage of healthcare costs to certain eligible employees. The cost of the healthcare benefits are reflected in the tables below as special termination costs. See further discussion at Note 13.

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The components of the net periodic benefit cost for the respective Progress Energy Registrants for the three months ended September 30 were:

PROGRESS ENERGY
	Qualified						Non-Qualified				Other Post-Retirement
	Pension Plans						Pension Plans				Benefit Plans
(in millions)	2012			2011			2012		2011		2012		2011
Service cost	$	16		$	13		$	-	$	-	$	5	$	3
Interest cost on projected benefit obligation		32			33			2		2		11		10
Expected return on plan assets		(48	)		(45	)		-		-		-		-
Amortization of prior service cost (a)		2			2			-		-		-		-
Amortization net transition liability(a)		-			-			-		-		1		1
Amortization of actuarial loss(a)		24			15			1		1		10		3
Special termination costs		-			-			-		-		5		-
Other		1			-			-		-		-		-
Net periodic cost	$	27		$	18		$	3	$	3	$	32	$	17

(a) Adjusted to reflect PEF’s rate treatment. See Note 17B in the 2011 Form 10-K.

PEC
	Qualified						Non-Qualified				Other Post-Retirement
	Pension Plans						Pension Plans				Benefit Plans
(in millions)	2012			2011			2012		2011		2012		2011
Service cost	$	6		$	5		$	-	$	-	$	2	$	2
Interest cost on projected benefit obligation		15			15			1		1		6		5
Expected return on plan assets		(25	)		(23	)		-		-		-		-
Amortization of prior service cost		2			1			-		-		-		-
Amortization net transition liability		-			-			-		-		-		-
Amortization of actuarial loss		9			7			-		-		6		1
Special termination costs		-			-			-		-		2		-
Other		1			-			-		-		-		-
Net periodic cost	$	8		$	5		$	1	$	1	$	16	$	8

PEF
	Qualified						Non-Qualified				Other Post-Retirement
	Pension Plans						Pension Plans				Benefit Plans
(in millions)	2012			2011			2012		2011		2012		2011
Service cost	$	8		$	6		$	-	$	-	$	2	$	1
Interest cost on projected benefit obligation		14			14			1		1		4		4
Expected return on plan assets		(21	)		(19	)		-		-		-		-
Amortization net transition liability		-			-			-		-		1		1
Amortization of actuarial loss		13			8			-		-		3		2
Special termination costs		-			-			-		-		1		-
Net periodic cost	$	14		$	9		$	1	$	1	$	11	$	8

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The components of the net periodic benefit cost for the respective Progress Energy Registrants for the nine months ended September 30 were:

PROGRESS ENERGY
	Qualified						Non-Qualified				Other Post-Retirement
	Pension Plans						Pension Plans				Benefit Plans
(in millions)	2012			2011			2012		2011		2012			2011
Service cost	$	47		$	39		$	1	$	1	$	12		$	8
Interest cost on projected benefit obligation		95			98			6		7		32			30
Expected return on plan assets		(141	)		(136	)		-		-		(1	)		(1	)
Amortization of prior service cost (a)		7			5			-		-		-			-
Amortization of net transition liability(a)		-			-			-		-		3			4
Amortization of actuarial loss(a)		69			47			3		2		25			9
Special termination cost		-			-			-		-		5			-
Other		1			-			-		-		-			-
Net periodic cost	$	78		$	53		$	10	$	10	$	76		$	50

(a) Adjusted to reflect PEF’s rate treatment. See Note 17B in the 2011 Form 10-K.

PEC
	Qualified						Non-Qualified				Other Post-Retirement
	Pension Plans						Pension Plans				Benefit Plans
(in millions)	2012			2011			2012		2011		2012		2011
Service cost	$	19		$	15		$	1	$	1	$	6	$	3
Interest cost on projected benefit obligation		43			46			1		1		17		15
Expected return on plan assets		(72	)		(68	)		-		-		-		-
Amortization of prior service cost		6			4			-		-		-		-
Amortization of net transition liability		-			-			-		-		-		1
Amortization of actuarial loss		28			19			1		-		14		4
Special termination cost		-			-			-		-		2		-
Other		1			-			-		-		-		-
Net periodic cost	$	25		$	16		$	3	$	2	$	39	$	23

PEF
	Qualified						Non-Qualified				Other Post-Retirement
	Pension Plans						Pension Plans				Benefit Plans
(in millions)	2012			2011			2012		2011		2012			2011
Service cost	$	22		$	18		$	-	$	-	$	5		$	3
Interest cost on projected benefit obligation		42			43			2		2		13			13
Expected return on plan assets		(61	)		(59	)		-		-		(1	)		(1	)
Amortization of net transition liability		-			-			-		-		2			3
Amortization of actuarial loss		36			25			-		-		9			6
Special termination cost		-			-			-		-		1			-
Net periodic cost	$	39		$	27		$	2	$	2	$	29		$	24

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BENEFIT OBLIGATIONS

Upon consummation of the merger with Duke Energy, all defined benefit plan obligations were remeasured. Progress Energy, PEC and PEF updated the assumptions used to determine their accrued benefit obligations and prospective net periodic benefit costs. The weighted-average assumptions used to determine benefit obligations are as follows:

	Qualified Pension Benefits			Non-Qualified Pension Benefits			Other Post-Retirement Benefits
Discount rate		4.60	%		4.60	%		4.60	%
Rate of increase in future compensation
Bargaining		4.00	%		N/A			N/A
Supplementary plans		N/A			5.25	%		N/A
Expected long-term rate of return on plan assets		8.00	%		N/A			N/A

The salary increase for qualified pension benefits relates to bargaining employees only. Our primary defined benefit plan for non-bargaining employees is a “cash balance” plan that uses the traditional unit credit method for purposes of measuring the benefit obligation. Under the traditional unit credit method, no assumptions are included about future changes in compensation, and the accumulated benefit obligation and projected benefit obligation are the same.

The assumed health care cost trend rates for our other post-retirement benefit plans are as follows:

Health care cost trend rate assumed for 2012	8.75	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.00	%
Year that the rate reaches the ultimate trend rate	2020

As a result of the remeasurement, we recorded net increases in our benefit obligations of $122 million, including $40 million for PEC and $75 million for PEF. These net increases were primarily offset by a $128 million increase in our regulatory assets, including $44 million for PEC and $75 million for PEF. In addition, $39 million of investments previously reported as plan assets of PEF’s benefit plans were reclassified to investments and other assets, other in the Balance Sheets at September 30, 2012.

CONTRIBUTIONS

To date in 2012, we have made contributions directly to pension plan assets of approximately $146 million for us, including $71 million for PEC and $74 million for PEF. Our contributions during the nine months ended September 30, 2012 totaled $122 million, including $60 million for PEC and $61 million for PEF. Future amounts we contribute may be impacted by recently enacted legislation as well as other factors.

Additionally, we sponsor employee savings plans that cover substantially all employees. We made pre-tax employer contributions of $12 million and $12 million for the three months ended September 30, 2012 and 2011, respectively. We made pre-tax employer contributions of $35 million and $34 million for the nine months ended September 30, 2012 and 2011, respectively. The Utilities participate in our employee savings plans. The following table shows the respective expense related to their proportionate share of pre-tax employer contributions.

	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
PEC	$	7	$	6	$	18	$	18
PEF		4		4		11		11

61

13. SEVERANCE

In conjunction with the merger, in November 2011, Duke Energy and Progress Energy offered a voluntary severance plan to certain eligible employees. As this is a voluntary severance plan, all severance benefits offered under this plan are considered special termination benefits under U.S. GAAP. Special termination benefits are measured upon employee acceptance and recorded immediately absent any significant retention period. If a significant retention period exists, the cost of the special termination benefits are recorded ratably over the retention period. Approximately 1,100 employees of the combined company, including approximately 650 employees of Progress Energy, accepted the termination benefits during the voluntary window period, which closed on November 30, 2011. The estimated amount of severance payments for Duke Energy associated with this voluntary plan and other severance benefits through 2014, excluding amounts incurred through September 30, 2012, are expected to range from $80 million to $110 million and most of the costs will be charged to Duke Energy Carolinas, PEC and PEF.

Amounts included in the following table represent severance expense recorded by the Progress Energy Registrants during 2012, which is included within O&M expense in the Statements of Operations and Comprehensive Income. The Progress Energy Registrants recorded insignificant amounts for severance expense during 2011.

(in millions)	Three months ended September 30, 2012		Nine months ended September 30, 2012
Progress Energy	$	66	$	66
PEC		42		42
PEF		24		24

Amounts included in the table below represent the severance liability for our past and ongoing severance plans.

(in millions)	Balance at December 31, 2011		Provisions / Adjustments		Cash Reductions			Balance at September 30, 2012
Progress Energy	$	5	$	53	$	(15	)	$	43
PEC		5		26		(7	)		24
PEF		-		10		(3	)		7

62

14. INCOME TAXES AND OTHER TAXES

INCOME TAXES

Progress Energy and its subsidiaries file income tax returns in the U.S. with federal and various state governmental authorities. Progress Energy and its subsidiaries have a tax sharing agreement where the separate return method is used to allocate tax expenses and benefits to the subsidiaries whose investments or results of operations provide these tax expenses and benefits. The accounting for income taxes essentially represents the income taxes that each of these subsidiaries would incur if it were a separate company filing its own tax return as a C-corporation.

The effective tax rates for each of the Progress Energy Registrants are as follows:

	Three months ended September 30						Nine months ended September 30
	2012			2011			2012			2011
Progress Energy		32.8	%		37.8	%		34.7	%		36.9	%
PEC		31.9	%		33.4	%		31.6	%		34.2	%
PEF		35.9	%		37.0	%		36.9	%		37.0	%

For the three and nine months ended September 30, 2012, Progress Energy’s effective tax rate decreased primarily due to a decrease in pretax income as well as a decrease in the change in fair value of outstanding CVOs.

In addition, for the three and nine months ended September 30, 2012, PEC’s effective tax rate decreased primarily due to a decrease in pretax income.

In addition, for the three and nine months ended September 30, 2012, PEF’s effective tax rate had an insignificant change.

EXCISE TAXES

Certain excise taxes levied by state or local governments are collected by the Utilities from their customers. Taxes that are required to be paid regardless of the ability to collect from the customer are accounted for on a gross basis. When the Utilities act as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis. Excise taxes accounted for on a gross basis and recorded as revenues and other tax expense in the respective Statements of Operations and Comprehensive Income were as follows:

	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
PEC	$	33	$	33	$	85	$	86
PEF		62		63		156		159
Progress Energy	$	95	$	96	$	241	$	245

63

15. RELATED PARTY TRANSACTIONS

The Progress Energy Registrants engage in related party transactions, which are generally performed at cost and in accordance with the applicable state and federal commission regulations. Refer to the Balance Sheets for balances due to or due from related parties. Amounts related to transactions with related parties included in the Statements of Operations and Comprehensive Income are presented in the following table:

	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
PROGRESS ENERGY
Corporate governance and shared services provided by Duke Energy(a)	$	31	$	-	$	31	$	-
Corporate governance and shared services provided to Duke Energy(b)		30		-		30		-
JDA revenues(c)		37		-		37		-
JDA expenses(d)		8		-		8		-
Indemnification coverage expenses(e)		7		-		7		-
PEC
Corporate governance and shared service expenses(a)	$	72	$	48	$	183	$	155
JDA revenues(c)		37		-		37		-
JDA expenses(d)		8		-		8		-
Indemnification coverage expenses(e)		3		-		3		-
PEF
Corporate governance and shared service expenses(a)	$	52	$	41	$	136	$	122
Indemnification coverage expenses(e)		4		-		4		-

(a)	Progress Energy Registrants are charged their proportionate share of corporate governance and other costs by PESC (only applicable to PEC and PEF) and an unconsolidated affiliate that is a consolidated affiliate of Duke Energy. Corporate governance and other shared costs are primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These expenses are recorded in O&M in the Statements of Operations and Comprehensive Income.
(b)	PESC charges a proportionate share of corporate governance and other costs to unconsolidated affiliates that are consolidated affiliates of Duke Energy. Corporate governance and other shared costs are primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These charges are recorded as an offset to O&M in the Statements of Operations and Comprehensive Income.
(c)	Effective with the consummation of the merger, PEC and Duke Energy Carolinas began to participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customers' rates (See Note 4). The revenues from the sale of power to Duke Energy Carolinas are recorded in regulated electric revenues in the Consolidated Statements of Operations and Comprehensive Income.
(d)	Effective with the consummation of the merger, PEC and Duke Energy Carolinas began to participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customers' rates (See Note 4). The expenses from the purchase of power from Duke Energy Carolinas are recorded in fuel used in electric generation and purchased power in the Consolidated Statements of Operations and Comprehensive Income.
(e)	Effective with the consummation of the merger, Progress Energy Registrants incur expenses related to certain indemnification coverages through Bison, Duke Energy's wholly owned captive insurance subsidiary. These expenses are recorded in O&M in the Statements of Operations and Comprehensive Income.

Prior to the merger, PEC and PEF participated in an internal money pool, administered by PESC, to more effectively utilize cash resources and to reduce outside short-term borrowings. The money pool was also used to settle intercompany balances. Effective with the consummation of the merger, the Progress Energy Registrants began to participate in a money pool arrangement with Duke Energy (See Note 6). Interest income and expense associated with money pool activity were immaterial for the three and nine months ended September 30, 2012 and 2011.

In addition, the Parent has issued $300 million in guarantees for certain payments of two wholly owned indirect subsidiaries (See Note 17).

64

16. NEW ACCOUNTING STANDARDS

The following new accounting standards were adopted by the Progress Energy Registrants subsequent to September 30, 2011 and the impact of such adoption, if applicable, has been presented in the respective Consolidated Financial Statements of the Progress Energy Registrants:

ASC 220 — Comprehensive Income. In June 2011, the FASB amended the existing requirements for presenting comprehensive income in financial statements primarily to increase the prominence of items reported in other comprehensive income (OCI) and to facilitate the convergence of U.S. GAAP and International Financial Reporting Standards (IFRS). Specifically, the revised guidance eliminates the option previously provided to present components of OCI as part of the statement of changes in stockholders’ equity. Accordingly, all non-owner changes in stockholders’ equity are required to be presented either in a single continuous statement of comprehensive income or in two separate but consecutive financial statements. For the Progress Energy Registrants, this revised guidance was effective on a retrospective basis for interim and annual periods beginning January 1, 2012. The adoption of this standard changed the presentation of the Progress Energy Registrants’ financial statements but did not affect the calculation of net income, comprehensive income or earnings per share.

ASC 820 — Fair Value Measurements and Disclosures. In May 2011, the FASB amended existing requirements for measuring fair value and for disclosing information about fair value measurements. This revised guidance results in a consistent definition of fair value, as well as common requirements for measurement and disclosure of fair value information between U.S. GAAP and IFRS. In addition, the amendments set forth enhanced disclosure requirements with respect to recurring Level 3 measurements, nonfinancial assets measured or disclosed at fair value, transfers between levels in the fair value hierarchy, and assets and liabilities disclosed but not recorded at fair value. For the Progress Energy Registrants, the revised fair value measurement guidance was effective on a prospective basis for interim and annual periods beginning January 1, 2012. The adoption of this new guidance did not have a significant impact on the Progress Energy Registrants’ disclosures or their consolidated results of operations, cash flows, or financial position.

ASC 350 — Intangibles–Goodwill and Other. In September 2011, the FASB amended existing goodwill impairment testing accounting guidance to provide an entity testing goodwill for impairment with the option of performing a qualitative assessment prior to calculating the fair value of a reporting unit in step one of a goodwill impairment test. Under this revised guidance, a qualitative assessment would require an evaluation of economic, industry, and company-specific considerations. If an entity determines, on a basis of such qualitative factors, that the fair value of a reporting unit is more likely than not less than the carrying value of a reporting unit, then step one and if necessary, step two of the impairment test must be performed. Otherwise, no further impairment testing would be required. The revised goodwill impairment testing accounting guidance was effective for the Progress Energy Registrants’ annual and interim goodwill impairment tests performed for fiscal years beginning January 1, 2012. The adoption of this new guidance did not have a significant impact on the Progress Energy Registrants’ disclosures or their consolidated results of operations, cash flows, or financial position.

The following new Accounting Standards Update (ASU) has been issued, but has not yet been adopted by the Progress Energy Registrants, as of September 30, 2012.

ASC 210 — Balance Sheet. In December 2011, the FASB issued revised accounting guidance to amend the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve comparability of balance sheets prepared under U.S. GAAP and IFRS. The revised disclosure guidance affects all companies that have financial instruments and derivative instruments that are either offset in the balance sheet (i.e., presented on a net basis) or subject to an enforceable master netting arrangement and/or similar agreement. The revised guidance requires that certain enhanced quantitative and qualitative disclosures be made with respect to a company’s netting arrangements and/or rights of setoff associated with its financial instruments and/or derivative instruments including associated collateral. For the Progress Energy Registrants, the revised disclosure guidance is effective on a retrospective basis for interim and annual periods beginning January 1, 2013. Other than additional disclosures, this revised guidance does not impact the consolidated results of operations, cash flows or financial position of Progress Energy.

65

17. 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 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 these entities 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 this VIE have not been presented because we believe that such information is not material to investors.

Presented below are the condensed consolidating Statements of Operations and Comprehensive Income, Balance Sheets and Statements of 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.

66

Condensed Consolidating Statement of Operations and Comprehensive Income
Three months ended September 30, 2012
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
Operating revenues
Regulated electric	$	-		$	1,382		$	1,394	$	(1	)	$	2,775
Non-regulated electric and other		-			10			4		(1	)		13
Total operating revenues		-			1,392			1,398		(2	)		2,788
Operating expenses
Fuel used in electric generation and purchased power		-			799			597		-			1,396
Operation, maintenance and other		-			247			378		1			626
Depreciation and amortization		-			39			135		-			174
Property and other taxes		-			100			63		(3	)		160
Impairment charges		-			-			55		-			55
Total operating expenses		-			1,185			1,228		(2	)		2,411
Gains on sales of other assets and other, net		-			1			1		-			2
Operating income		-			208			171		-			379
Equity in earnings of consolidated subsidiaries		203			-			-		(203	)		-
Other income and expenses, net		(1	)		12			23		(2	)		32
Interest expense, net		63			67			53		(1	)		182
Income from continuing operations before   income taxes		139			153			141		(204	)		229
Income tax (benefit) expense from continuing   operations		(16	)		55			43		(7	)		75
Income from continuing operations		155			98			98		(197	)		154
Income from discontinued operations, net of tax		-			2			1		-			3
Net income		155			100			99		(197	)		157
Less:  Net income attributable to noncontrolling   interests		-			1			-		1			2
Net income attributable to Duke Energy Corporation	$	155		$	99		$	99	$	(198	)	$	155
Comprehensive income, net of tax
Comprehensive income	$	253		$	118		$	170	$	(286	)	$	255
Comprehensive income attributable to noncontrolling   interests, net of tax		-			(1	)		-		(1	)		(2	)
Comprehensive income attributable to Duke Energy   Corporation	$	253		$	117		$	170	$	(287	)	$	253

67

Condensed Consolidating Statement of Operations and Comprehensive Income
Three months ended September 30, 2011
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Regulated electric	$	-		$	1,414		$	1,330		$	(1	)	$	2,743
Non-regulated electric and other		-			9			2			(1	)		10
Total operating revenues		-			1,423			1,332			(2	)		2,753
Operating expenses
Fuel used in electric generation and purchased power		-			690			544			-			1,234
Operation, maintenance and other		2			225			265			2			494
Depreciation and amortization		-			39			136			-			175
Property and other taxes		-			106			58			-			164
Total operating expenses		2			1,060			1,003			2			2,067
Gains on sales of other assets and other, net		-			1			-			-			1
Operating (loss) income		(2	)		364			329			(4	)		687
Equity in earnings of consolidated subsidiaries		391			-			-			(391	)		-
Other income and expenses, net		(63	)		2			14			3			(44	)
Interest expense, net		80			52			41			(1	)		172
Income from continuing operations before   income taxes		246			314			302			(391	)		471
Income tax (benefit) expense from continuing   operations		(45	)		116			103			4			178
Income from continuing operations		291			198			199			(395	)		293
Income (loss) from discontinued operations, net   of tax		-			1			(1	)		-			-
Net income		291			199			198			(395	)		293
Less:  Net income attributable to noncontrolling   interests		-			1			-			1			2
Net income attributable to Duke Energy Corporation	$	291		$	198		$	198		$	(396	)	$	291
Comprehensive income, net of tax
Comprehensive income	$	226		$	182		$	165		$	(345	)	$	228
Comprehensive income attributable to noncontrolling   interests, net of tax		-			(1	)		-			(1	)		(2	)
Comprehensive income attributable to Duke Energy   Corporation	$	226		$	181		$	165		$	(346	)	$	226

68

Condensed Consolidating Statement of Operations and Comprehensive Income
Nine months ended September 30, 2012
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
Operating revenues
Regulated electric	$	-		$	3,576		$	3,561	$	(2	)	$	7,135
Non-regulated electric and other		-			26			17		-			43
Total operating revenues		-			3,602			3,578		(2	)		7,178
Operating expenses
Fuel used in electric generation and purchased power		-			1,849			1,450		-			3,299
Operation, maintenance and other		4			668			1,120		6			1,798
Depreciation and amortization		-			158			413		-			571
Property and other taxes		-			272			175		(7	)		440
Impairment charges		-			-			55		-			55
Total operating expenses		4			2,947			3,213		(1	)		6,163
Gains on sales of other assets and other, net		-			2			2		-			4
Operating (loss) income		(4	)		657			367		(1	)		1,019
Equity in earnings of consolidated subsidiaries		489			-			-		(489	)		-
Other income and expenses, net		8			32			58		(1	)		97
Interest expense, net		193			210			157		-			560
Income from continuing operations before   income taxes		300			479			268		(491	)		556
Income tax (benefit) expense from continuing   operations		(68	)		177			88		(4	)		193
Income from continuing operations		368			302			180		(487	)		363
Income from discontinued operations, net   of tax		-			10			-		-			10
Net income		368			312			180		(487	)		373
Less:  Net income attributable to noncontrolling   interests		-			3			-		2			5
Net income attributable to Duke Energy Corporation	$	368		$	309		$	180	$	(489	)	$	368
Comprehensive income, net of tax
Comprehensive income	$	467		$	331		$	250	$	(576	)	$	472
Comprehensive income attributable to noncontrolling   interests, net of tax		-			(3	)		-		(2	)		(5	)
Comprehensive income attributable to Duke Energy   Corporation	$	467		$	328		$	250	$	(578	)	$	467

69

Condensed Consolidating Statement of Operations and Comprehensive Income
Nine months ended September 30, 2011
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Operating revenues
Regulated electric	$	-		$	3,639		$	3,524		$	(2	)	$	7,161
Non-regulated electric and other		-			24			11			-			35
Total operating revenues		-			3,663			3,535			(2	)		7,196
Operating expenses
Fuel used in electric generation and purchased power		-			1,804			1,382			-			3,186
Operation, maintenance and other		6			659			829			6			1,500
Depreciation and amortization		-			112			396			-			508
Property and other taxes		-			274			168			(5	)		437
Total operating expenses		6			2,849			2,775			1			5,631
Gains on sales of other assets and other, net		-			2			-			-			2
Operating (loss) income		(6	)		816			760			(3	)		1,567
Equity in earnings of consolidated subsidiaries		832			-			-			(832	)		-
Other income and expenses, net		(59	)		25			54			1			21
Interest expense, net		216			193			134			(1	)		542
Income from continuing operations before   income taxes		551			648			680			(833	)		1,046
Income tax (benefit) expense from continuing   operations		(100	)		240			243			3			386
Income from continuing operations		651			408			437			(836	)		660
Loss from discontinued operations, net of tax		-			(2	)		(2	)		-			(4	)
Net income		651			406			435			(836	)		656
Less:  Net income attributable to noncontrolling   interests		-			3			-			2			5
Net income attributable to Duke Energy Corporation	$	651		$	403		$	435		$	(838	)	$	651
Comprehensive income, net of tax
Comprehensive income	$	569		$	384		$	393		$	(772	)	$	574
Comprehensive income attributable to noncontrolling   interests, net of tax		-			(3	)		-			(2	)		(5	)
Comprehensive income attributable to Duke Energy   Corporation	$	569		$	381		$	393		$	(774	)	$	569

70

Condensed Consolidating Balance Sheet
September 30, 2012
(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Current assets
Cash and cash equivalents	$	-	$	38	$	19	$	-		$	57
Receivables, net		-		435		495		-			930
Notes receivable from affiliated companies		676		-		209		(885	)		-
Inventory		-		618		749		(1	)		1,366
Prepayments and other current assets		59		417		293		(96	)		673
Total current assets		735		1,508		1,765		(982	)		3,026
Investments and other assets
Nuclear decommissioning trust funds		-		621		1,223		-			1,844
Investment in consolidated subsidiaries		14,171		-		-		(14,171	)		-
Goodwill		-		-		-		3,655			3,655
Other		151		232		695		(546	)		532
Total investments and other assets		14,322		853		1,918		(11,062	)		6,031
Net property, plant and equipment		-		10,885		13,126		156			24,167
Regulatory assets and deferred debits
Regulatory assets		-		1,446		1,885		-			3,331
Other		23		49		30		(6	)		96
Total regulatory assets and deferred debits		23		1,495		1,915		(6	)		3,427
Total assets	$	15,080	$	14,741	$	18,724	$	(11,894	)	$	36,651
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	-	$	435	$	403	$	-		$	838
Notes payable to affiliated companies		843		431		246		(885	)		635
Other		75		1,120		1,164		(96	)		2,263
Total current liabilities		918		1,986		1,813		(981	)		3,736
Long-term debt		3,992		4,237		4,435		-			12,664
Long-term debt, affiliate		-		309		-		(35	)		274
Deferred credits and other liabilities
Deferred income taxes		-		960		2,091		(542	)		2,509
Asset retirement obligations		-		514		1,623		-			2,137
Regulatory liabilities		-		880		1,667		157			2,704
Other		20		923		1,432		6			2,381
Total deferred credits and other liabilities		20		3,277		6,813		(379	)		9,731
Preferred stock of subsidiaries		-		34		59		-			93
Equity
Common shareholders' equity		10,150		4,895		5,604		(10,499	)		10,150
Noncontrolling interests		-		3		-		-			3
Total equity		10,150		4,898		5,604		(10,499	)		10,153
Total liabilities and equity	$	15,080	$	14,741	$	18,724	$	(11,894	)	$	36,651

71

Condensed Consolidating Balance Sheet
December 31, 2011
(in millions)	Parent		Subsidiary Guarantor		Non- Guarantor Subsidiaries		Other			Progress Energy, Inc.
ASSETS
Current assets
Cash and cash equivalents	$	117	$	92	$	21	$	-		$	230
Receivables, net		-		367		516		-			883
Notes receivable from affiliated companies		53		-		219		(272	)		-
Inventory		-		659		770		-			1,429
Prepayments and other current assets		127		418		297		(64	)		778
Total current assets		297		1,536		1,823		(336	)		3,320
Investments and other assets
Nuclear decommissioning trust funds		-		559		1,088		-			1,647
Investment in consolidated subsidiaries		14,043		-		-		(14,043	)		-
Goodwill		-		-		-		3,655			3,655
Other		118		189		675		(478	)		504
Total investments and other assets		14,161		748		1,763		(10,866	)		5,806
Net property, plant and equipment		-		10,455		11,677		160			22,292
Regulatory assets and deferred debits
Regulatory assets		-		1,629		1,795		-			3,424
Other		22		51		22		(6	)		89
Total regulatory assets and deferred debits		22		1,680		1,817		(6	)		3,513
Total assets	$	14,480	$	14,419	$	17,080	$	(11,048	)	$	34,931
LIABILITIES AND EQUITY
Current liabilities
Notes payable and commercial paper	$	250	$	233	$	188	$	-		$	671
Current maturities of long-term debt		450		10		502		(1	)		961
Notes payable to affiliated companies		-		238		34		(272	)		-
Other		199		1,030		1,221		(63	)		2,387
Total current liabilities		899		1,511		1,945		(336	)		4,019
Long-term debt		3,543		4,671		3,704		-			11,918
Long-term debt, affiliate		-		309		-		(36	)		273
Deferred credits and other liabilities
Deferred income taxes		-		757		1,903		(467	)		2,193
Asset retirement obligations		-		369		896		-			1,265
Regulatory liabilities		-		1,024		1,543		160			2,727
Other		17		1,012		1,384		5			2,418
Total deferred credits and other liabilities		17		3,162		5,726		(302	)		8,603
Preferred stock of subsidiaries		-		34		59		-			93
Equity
Common shareholders' 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
Total liabilities and equity	$	14,480	$	14,419	$	17,080	$	(11,048	)	$	34,931

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Condensed Consolidating Statement of Cash Flows
Nine months ended September 30, 2012
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	335		$	733		$	865		$	(483	)	$	1,450
Investing activities
Capital expenditures		-			(573	)		(1,122	)		-			(1,695	)
Purchases of available-for-sale securities		-			(562	)		(385	)		-			(947	)
Proceeds from sales and maturities of available-for-sale  securities		-			561			359			1			921
Notes due from affiliate		(624	)		-			10			614			-
Other		24			13			75			-			112
Net cash used by investing activities		(600	)		(561	)		(1,063	)		615			(1,609	)
Financing activities
Proceeds from the:
Issuance of long-term debt		444			-			988			-			1,432
Issuance of common stock related to employee   benefit plans		6			-			-			-			6
Payments for the redemption of long-term debt		(450	)		(9	)		(502	)		-			(961	)
Notes payable and commercial paper		(250	)		(233	)		(188	)		-			(671	)
Distributions to noncontrolling interests		-			(3	)		-			(3	)		(6	)
Dividends paid		(445	)		-			-			-			(445	)
Dividends paid to parent		-			(173	)		(310	)		483			-
Notes payable to affiliate		843			193			212			(613	)		635
Other		-			(1	)		(4	)		1			(4	)
Net cash provided (used) by financing activities		148			(226	)		196			(132	)		(14	)
Net decrease in cash and cash equivalents		(117	)		(54	)		(2	)		-			(173	)
Cash and cash equivalents at beginning of period		117			92			21			-			230
Cash and cash equivalents at end of period	$	-		$	38		$	19		$	-		$	57

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Condensed Consolidating Statement of Cash Flows
Nine months ended September 30, 2011
(in millions)	Parent			Subsidiary Guarantor			Non- Guarantor Subsidiaries			Other			Progress Energy, Inc.
Net cash provided by operating activities	$	659		$	664		$	863		$	(928	)	$	1,258
Investing activities
Capital expenditures		-			(626	)		(1,021	)		-			(1,647	)
Purchases of available-for-sale securities		-			(4,099	)		(438	)		-			(4,537	)
Proceeds from sales and maturities of available-for-sale   securities		-			4,101			408			-			4,509
Notes due from affiliate		(83	)		22			(23	)		84			-
Contributions to consolidated subsidiaries		(11	)		-			-			11			-
Other		(6	)		102			5			(1	)		100
Net cash used by investing activities		(100	)		(500	)		(1,069	)		94			(1,575	)
Financing activities
Proceeds from the:
Issuance of long-term debt		494			296			496			-			1,286
Issuance of common stock related to employee   benefit plans		42			-			-			-			42
Payments for the redemption of long-term debt		(700	)		(309	)		(1	)		-			(1,010	)
Notes payable and commercial paper		45			-			-			-			45
Distributions to noncontrolling interests		-			(4	)		-			(2	)		(6	)
Dividends paid		(550	)		-			-			-			(550	)
Dividends paid to parent		-			(478	)		(450	)		928			-
Notes payable to affiliate		-			84			-			(84	)		-
Contributions from parent		-			10			1			(11	)		-
Other		-			1			(2	)		3			2
Net cash (used) provided by financing activities		(669	)		(400	)		44			834			(191	)
Net decrease in cash and cash equivalents		(110	)		(236	)		(162	)		-			(508	)
Cash and cash equivalents at beginning of period		110			270			231			-			611
Cash and cash equivalents at end of period	$	-		$	34		$	69		$	-		$	103

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is separately filed by Progress Energy, PEC and PEF. As used in this report, Progress Energy, which includes 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 the Utilities. The term “Progress Energy Registrants” refers collectively to the three separate registrants: Progress Energy, PEC and PEF. Information contained herein relating to PEC and PEF individually is filed by such company on its own behalf. Neither of the Utilities makes any representation as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself.

MD&A should be read in conjunction with the accompanying financial statements found elsewhere in this report and in conjunction with the 2011 Form 10-K.

MERGER WITH DUKE ENERGY

On July 2, 2012, Progress Energy consummated the merger with Duke Energy, and became a direct wholly owned subsidiary of Duke Energy. Under the terms of the merger agreement, each share of Progress Energy common stock was converted into 0.87083 shares of Duke Energy common stock as adjusted for the one-for-three reverse stock split of Duke Energy stock effected in conjunction with, and immediately prior to, the merger. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock was converted into an option to acquire, or an equity award relating to, 0.87083 shares of Duke Energy common stock. The total consideration transferred in the merger was based on the closing price of Duke Energy common shares on July 2, 2012, valued at $18 billion. The merger is being recorded using the acquisition method of accounting. Under SEC regulations, the Progress Energy Registrants have not reflected the impacts of acquisition accounting in their financial statements based on the significance of the Progress Energy Registrants’ outstanding public debt securities. See Note 2 for additional information regarding the merger.

The information presented in this Form 10-Q for the three and nine months ended September 30, 2012 and 2011, are presented solely for the Progress Energy Registrants on a stand-alone basis. The results of our operations were included in Duke Energy’s results of operations beginning on July 2, 2012.

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PROGRESS ENERGY

INTRODUCTION

Progress Energy is a public utility holding company engaged in the regulated electric utility business. Progress Energy’s wholly owned subsidiaries, PEC and PEF, are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida.

BASIS OF PRESENTATION

The results of operations and variance discussion for Progress Energy is presented in a reduced disclosure format in accordance with General Instruction H(2) of Form 10-Q.

	Nine months ended September 30
(in millions)	2012		2011			Increase (decrease)
Operating revenues	$	7,178	$	7,196		$	(18	)
Operating expenses		6,163		5,631			532
Gains on sale of other assets and other, net		4		2			2
Operating income		1,019		1,567			(548	)
Other income and expenses, net		97		21			76
Interest expense		560		542			18
Income before income taxes		556		1,046			(490	)
Income tax expense		193		386			(193	)
Income (loss) from discontinued operations, net of tax		10		(4	)		14
Less: net income attributable to noncontrolling interests		5		5			-
Net income attributable to Duke Energy Corporation	$	368	$	651		$	(283	)

The decrease in Progress Energy’s net income attributable to Duke Energy Corporation for the nine months ended September 30, 2012, compared to September 30, 2011, was primarily due to the following factors:

OPERATING REVENUES

The decrease was primarily due to:

·   A $141 million decrease in sales to retail customers primarily due to unfavorable weather conditions. The Utilities’ weather statistics for heating degree days in 2012 were more unfavorable compared to the same period in 2011, while weather statistics for cooling degree days were less favorable in 2012 compared to the same period in 2011.

Partially offsetting this decrease were:

·   A $93 million increase in sales to wholesale customers primarily due to JDA revenues from Duke Energy Carolinas (See Note 4A), the impact of an amended capacity contract with a major customer that began in 2012 and new contracts with major customers;

·   A $14 million increase in other operating revenues at PEF primarily due to higher OATT rates; and

·   A $13 million increase in clause-recoverable regulatory revenues at PEC primarily due to increased spending on new and existing DSM programs.

OPERATING EXPENSES

The increase was primarily due to:

·   A $298 million increase in O&M expense primarily due to higher costs to achieve the merger with Duke Energy and PEC's higher nuclear plant outage costs;

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·   A $113 million increase in fuel used in electric generation and purchased power primarily due to an increase in deferred fuel expense at PEF due to higher under-recovered fuel costs in 2011 as a result of higher system requirements driven by 2011’s favorable weather conditions and the impact of establishing a regulatory liability for replacement power in accordance with PEF’s 2012 settlement agreement (See Note 4B), partially offset by lower natural gas prices and lower system requirements as result of unfavorable weather conditions in 2012 at PEF;

·   A $63 million increase in depreciation and amortization primarily due to a decrease in the reduction of the cost of removal component of amortization expense as allowed under PEF’s 2012 and 2010 settlement agreements (See Note 4B), higher ECRC amortization due to less over-recovery at PEF and higher depreciable asset base at PEC, partially offset by lower nuclear cost-recovery amortization primarily related to the Levy project; and

·   A $55 million increase in impairment charges primarily due to the probable disallowance of transmission project costs, which are a portion of the FERC Mitigation charges included in the costs to achieve the merger with Duke Energy (See Note 2).

OTHER INCOME AND EXPENSES, NET

The increase was primarily due to the $63 million prior-year pretax unrealized loss to record the change in fair value of the CVOs. The change in fair value was determined by an October 3, 2011 settlement agreement with a CVO holder to purchase all of their CVOs at a negotiated purchase price. The settlement agreement also led to a subsequent tender offer to remaining CVO holders at the same purchase price. Accordingly, we determined the purchase price included in the settlement agreement represented the fair value of CVOs at September 30, 2011.

INTEREST EXPENSE

The increase was primarily due to the prior-year favorable settlement of 2004 and 2005 income tax audits.

INCOME TAX EXPENSE

The decrease was primarily due to a decrease in pretax income. The effective tax rate for the nine months ended September 30, 2012 and 2011, was 34.7% and 36.9%, respectively. The decrease in the effective tax rate is primarily due to the decrease in pretax income as well as the decrease for the change of fair value of outstanding CVOs.

MATTERS IMPACTING FUTURE PROGRESS ENERGY RESULTS

The decision related to repairing or retiring 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 the reactor after repair. In addition, the scope and estimated costs of necessary repairs of the delamination of CR3 could prove more extensive than is currently identified, such repairs could prove not to be feasible resulting in the retirement of the unit, the costs of repair and/or replacement power could exceed estimates and insurance coverage or may not be recoverable through the regulatory process; the occurrence of any of which could adversely affect Progress Energy’s results of operations.

PEC filed a rate case in North Carolina in October 2012. This rate case is needed to recover the cost of plant modernization and other capital investments in generation, transmission and distribution systems, as well as increased expenditures for nuclear plants and personnel, vegetation management and other operating costs. Progress Energy’s earnings could be adversely impacted if this rate case is denied or delayed by the state regulatory commission.

The ability to integrate with Duke Energy businesses and realize cost savings and any other synergies expected from the merger with Duke Energy could be different from what Progress Energy expects and may have a significant impact on Progress Energy’s results of operations.

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PEC

PEC is a direct wholly owned subsidiary of Progress Energy. PEC’s principal lines of business include generation, transmission and distribution of electricity in parts of North Carolina and South Carolina.

	Three months ended September 30							Nine months ended September 30
(in  millions)	2012		2011		Increase (decrease)			2012		2011		Increase (decrease)
Operating revenues	$	1,398	$	1,331	$	67		$	3,578	$	3,534	$	44
Operating expenses		1,227		1,007		220			3,218		2,792		426
Gains on sale of other assets   and other, net		1		-		1			2		1		1
Operating income		172		324		(152	)		362		743		(381	)
Other income and expenses, net		21		16		5			57		55		2
Interest expense		52		41		11			156		134		22
Income before income taxes		141		299		(158	)		263		664		(401	)
Income tax expense		45		100		(55	)		83		227		(144	)
Less: preferred stock dividend   requirement		1		1		-			2		2		-
Net income available to parent	$	95	$	198	$	(103	)	$	178	$	435	$	(257	)
Gigawatt-hours sales		17,331		16,028		1,303			43,964		43,614		350

The following table shows the percent changes in gigawatt-hour (GWh) sales and average number of customers for the current three and nine month periods compared to the same periods in the prior year. Except as otherwise noted, the below percentages represent billed sales only and are not weather normalized.

Increase (decrease) over prior year	Three Months Ended September 30, 2012		Nine Months Ended September 30, 2012
Residential sales(a)	(3.9) %		(10.8) %
General service sales(a)	1.2  %		(1.9) %
Industrial sales(a)	(3.4) %		(1.9) %
Wholesale power sales	48.9  %	(c)	19.1  %	(c)
Total PEC sales(b)	8.1  %		0.8  %
Average number of customers	0.9  %		0.8  %

(a)	Major components of PEC's retail sales.
(b)	Consists of all components of PEC's sales, including all billed and unbilled retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.
(c)	Increase is primarily due to sales related to the JDA with Duke Energy Carolinas and Interim FERC Mitigation as a result of the consummation of the merger (See Note 4A). Higher sales from the JDA did not have a material impact on earnings as the higher revenues were offset by higher related fuel expense.

THREE MONTHS ENDED SEPTEMBER 30, 2012, AS COMPARED TO SEPTEMBER 30, 2011

The decrease in PEC’s net income available to parent for the three months ended September 30, 2012, compared to September 30, 2011, was primarily due to the following factors:

OPERATING REVENUES

The increase was primarily due to:

·   A $65 million increase in sales to wholesale customers primarily due to JDA revenues from Duke Energy Carolinas and a new contract that began in July 2012; and

·   A $31 million increase in fuel revenues driven primarily by Interim FERC Mitigation wholesale fuel revenue. Fuel revenues represent sales to retail and wholesale customers.

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Partially offsetting these increases was:

·   A $33 million decrease in sales to retail customers primarily due to unfavorable weather conditions. The number of cooling degree days for the three months ended September 30, 2012 was 3% above normal compared to 17% above normal in the same period in 2011. In addition, heating degree days for the three months ended September 30, 2012 were 11% below normal compared to 27% above normal in the same period in 2011.

OPERATING EXPENSES

The increase was primarily due to:

·   A $111 million increase in O&M expenses primarily due to higher costs to achieve the merger with Duke Energy and the prior-year non-capital portion of a favorable judgment from spent fuel litigation, partially offset by lower storm costs;

·   A $55 million increase in impairment charges primarily due to the probable disallowance of transmission project costs, which are a portion of the FERC Mitigation charges included in the costs to achieve the merger with Duke Energy; and

·   A $53 million increase in fuel used in electric generation and purchased power primarily due to higher volume driven by the JDA and Interim FERC Mitigation.

INTEREST EXPENSE

The increase was primarily due to the prior-year favorable settlement of 2004 and 2005 income tax audits and higher interest expense on long-term debt due to higher average debt outstanding.

INCOME TAX EXPENSE

The decrease was primarily due to a decrease in pretax income. The effective tax rate for the three months ended September 30, 2012 and 2011, was 31.9% and 33.4%, respectively. The decrease in the effective tax rate is primarily due to the decrease in pretax income.

NINE MONTHS ENDED SEPTEMBER 30, 2012, AS COMPARED TO SEPTEMBER 30, 2011

The decrease in PEC’s net income available to parent for the nine months ended September 30, 2012, compared to September 30, 2011, was primarily due to the following factors:

OPERATING REVENUES

The increase was primarily due to:

·   A $71 million increase in sales to wholesale customers primarily due to JDA revenues from Duke Energy Carolinas, the impact of an amended capacity contract with a major customer that began in May 2012 and a new contract that began in July 2012;

·   A $40 million increase in fuel revenues driven primarily by Interim FERC Mitigation wholesale fuel revenue; and

·   A $13 million increase in clause-recoverable regulatory revenues primarily due to increased spending on new and existing DSM programs.

Partially offsetting these increases was:

·   An $89 million decrease in sales to retail customers primarily due to unfavorable weather conditions. The number of heating degree days for the nine months ended September 30, 2012 was 28% below normal compared to 5% below normal in the same period in 2011. In addition, cooling degree days for the nine months ended September 30, 2012 were 4% above normal compared to 22% above normal in the same period in 2011.

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OPERATING EXPENSES

The increase was primarily due to:

·   A $283 million increase in O&M expenses primarily due to higher nuclear plant outage costs, higher costs to achieve the merger with Duke Energy and the prior-year non-capital portion of a favorable judgment from spent fuel litigation, partially offset by lower storm costs. The higher nuclear plant outage costs are primarily due to three extended nuclear refueling outages in 2012 compared to only one outage during the same period in 2011; and

·   A $68 million increase in fuel used in electric generation and purchased power primarily due to the impact of higher rates and a change in generation mix, which was driven by nuclear refueling outages in 2012, partially offset by a lower disallowance of replacement power costs resulting from the performance of nuclear plants and the impact of lower system requirements resulting from unfavorable weather conditions; and

·   A $55 million increase in impairment charges primarily due to the probable disallowance of transmission project costs, which are a portion of the FERC Mitigation charges included in the costs to achieve the merger with Duke Energy.

INTEREST EXPENSE

The increase was primarily due to higher interest expense on long-term debt due to higher average debt outstanding and the prior-year settlement of 2004 and 2005 income tax audits.

INCOME TAX EXPENSE

The decrease was primarily due to a decrease in pretax income. The effective tax rate for the nine months ended September 30, 2012 and 2011, was 31.6% and 34.2%, respectively. The decrease in the effective tax rate is primarily due to the decrease in pretax income.

MATTERS IMPACTING FUTURE PEC RESULTS

PEC filed a rate case in North Carolina in October 2012. This rate case is needed to recover the cost of plant modernization and other capital investments in generation, transmission and distribution systems, as well as increased expenditures for nuclear plants and personnel, vegetation management and other operating costs. PEC’s earnings could be adversely impacted if this rate case is denied or delayed by the state regulatory commission.

The ability to integrate with Duke Energy businesses and realize cost savings and any other synergies expected from the merger with Duke Energy could be different from what PEC expects and may have a significant impact on PEC’s results of operations.

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PEF

INTRODUCTION

PEF is an indirect wholly owned subsidiary of Progress Energy. PEF’s principal lines of business include generation, transmission and distribution of electricity in parts of Florida.

BASIS OF PRESENTATION

The results of operations and variance discussion for PEF is presented in a reduced disclosure format in accordance with General Instruction H(2) of Form 10-Q.

	Nine months ended September 30
(in  millions)	2012		2011		Increase (decrease)
Operating revenues	$	3,594	$	3,655	$	(61	)
Operating expenses		2,938		2,842		96
Gains on sale of other assets and other, net		2		2		-
Operating income		658		815		(157	)
Other income and expenses, net		29		24		5
Interest expense		194		176		18
Income before income taxes		493		663		(170	)
Income tax expense		182		245		(63	)
Less: preferred stock dividend requirement		1		1		-
Net income available to parent	$	310	$	417	$	(107	)
Gigawatt-hours sales		29,814		31,306		(1,492	)

The following table shows the percent changes in GWh sales and average number of customers for the current three and nine month periods compared to the same periods in the prior year. Except as otherwise noted, the below percentages represent billed sales only and are not weather normalized.

Increase (decrease) over prior year		Three months ended September 30, 2012		Nine months ended September 30, 2012
Residential sales(a)		(7.6)	%	(7.9)	%
General service sales(a)		(2.7)	%	(1.3)	%
Industrial sales(a)		(2.2)	%	(3.1)	%
Wholesale power sales		(31.5)	%	(37.7)	%
Total PEF sales(b)		(4.4)	%	(4.8)	%
Average number of customers		0.9	%	0.8	%
(a)	Major components of PEF's retail sales.
(b)	Consists of all components of PEF's sales, including all billed and unbilled retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

The decrease in PEF’s net income available to parent for the nine months ended September 30, 2012, compared to September 30, 2011, was primarily due to the following factors:

OPERATING REVENUES

The decrease was primarily due to:

·   A $56 million decrease in fuel and capacity revenues driven primarily by unfavorable weather conditions that impacted wholesale and retail fuel revenues, partially offset by the impact of higher residential fuel rates. Also, PEF had lower capacity revenues resulting from a lower capacity rate and the lower sales volume; and

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·   A $36 million decrease in sales to retail customers primarily due to unfavorable weather conditions. The number of heating degree days for the nine months ended September 30, 2012 was 30% below normal compared to 2% above normal in the same period in 2011. In addition, cooling degree days for the nine months ended September 30, 2012 were 5% above normal compared to 9% above normal in the same period in 2011.

Partially offsetting these decreases were:

·   A $21 million increase in sales to wholesale customers primarily due to a new contract with a major customer; and

·   A $14 million increase in other operating revenues primarily due to higher OATT rates.

OPERATING EXPENSES

The increase was primarily due to:

·   A $46 million increase in depreciation and amortization primarily due to a decrease in the reduction of the cost of removal component of amortization expense as allowed under the 2012 and 2010 settlement agreements (See Note 4B) and higher ECRC amortization due to less over-recovery, partially offset by lower nuclear cost-recovery amortization primarily related to the Levy project; and

·   A $45 million increase in fuel used in electric generation and purchased power primarily due to an increase in deferred fuel expense due to higher under-recovered fuel costs in 2011 as a result of higher system requirements driven by favorable weather and the impact of establishing a regulatory liability for replacement power in accordance with the 2012 settlement agreement (See Note 4B). These increases were partially offset by lower natural gas prices and lower system requirements as a result of unfavorable weather conditions and a lower CR3 indemnification charge for the estimated joint owner replacement power costs.

INTEREST EXPENSE

The increase was primarily due to the prior-year favorable settlement of 2004 and 2005 income tax audits.

INCOME TAX EXPENSE

The decrease was primarily due to a decrease in pretax income. The effective tax rate for the nine months ended September 30, 2012 and 2011, was 36.9% and 37.0%, respectively.

MATTERS IMPACTING FUTURE PEF RESULTS

The decision related to repairing or retiring 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 the reactor after repair. In addition, the scope and estimated costs of necessary repairs of the delamination of CR3 could prove more extensive than is currently identified, such repairs could prove not to be feasible resulting in the retirement of the unit, the costs of repair and/or replacement power could exceed estimates and insurance coverage or may not be recoverable through the regulatory process; the occurrence of any of which could adversely affect PEF’s results of operations.

The ability to integrate with Duke Energy businesses and realize cost savings and any other synergies expected from the merger with Duke Energy could be different from what PEF expects and may have a significant impact on PEF’s results of operations.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion of our liquidity and capital resources is on a consolidated basis, except as noted. Our significant cash requirements arise primarily from the capital-intensive nature of the Utilities’ operations, including capital expansion projects, fleet modernization and other expenditures for environmental compliance. The Utilities’ operating cash flow, intercompany borrowings, our participation in the Duke Energy MCF, our ability to access the

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long-term debt capital markets and/or equity contributions from Duke Energy provide our sources of liquidity, as discussed further below.

Historically, we had substantial operations associated with the production and sale of coal-based solid synthetic fuels, which qualified for federal income tax credits so long as certain requirements were satisfied. A portion of these tax credits has yet to be realized in cash due to the difference in timing of when tax credits are recognized for financial reporting purposes and realized for tax purposes. At September 30, 2012, we have carried forward $868 million of deferred tax credits that do not expire. Certain substantial changes in ownership of Progress Energy, such as the merger with Duke Energy, can impact the timing of the utilization of tax credit carry forwards. Also, realization of these tax credits is dependent upon our future taxable income, which is expected to be generated primarily by the Utilities.

CASH FLOW INFORMATION

Cash flow information for Progress Energy and PEF is omitted pursuant to General Instruction H(2) to Form 10-Q.

PEC

The following table summarizes PEC’s cash flows:

	Nine months ended September 30
(in millions)	2012			2011
Cash flows provided by (used in):
Operating activities	$	853		$	888
Investing activities		(1,049	)		(1,094	)
Financing activities		195			43
Net decrease in cash and cash equivalents		(1	)		(163	)
Cash and cash equivalents at beginning of period		20			230
Cash and cash equivalents at end of period	$	19		$	67

OPERATING CASH FLOWS

The following table summarizes key components of PEC’s operating cash flows.

	Nine months ended September 30
(in millions)	2012			2011
Net income	$	180		$	437
Noncash adjustments to net income		759			690
Contributions to qualified pension plans		(60	)		(207	)
Working capital		(26	)		(32	)
Net cash provided by operating activities	$	853		$	888

The decrease in cash provided by operating activities in 2012 as compared to 2011 was driven primarily by:

·   A decrease in net income adjusted for noncash and non-operating items in 2012 as compared to 2011.

This decrease was partially offset by:

·   A $147 million decrease in pension plan funding.

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INVESTING CASH FLOWS

The following table summarizes key components of PEC's investing cash flows.

	Nine months ended September 30
(in millions)	2012			2011
Capital expenditures	$	(1,098	)	$	(1,010	)
Available for sale securities, net		(26	)		(29	)
Notes due from affiliate		-			(59	)
Other investing items		75			4
Net cash used in investing activities	$	(1,049	)	$	(1,094	)

The decrease in cash used in investing activities in 2012 as compared to 2011 was primarily driven by:

·   The receipt of a DOE award in the current year of which $62 million was applicable to past capitalized spent fuel storage costs;

·   Changes in advances with affiliates of $59 million; and

·   Lower nuclear fuel purchases of $58 million due to prior year purchases made in anticipation of 2012’s three nuclear refueling outages.

These decreases were partially offset by:

·   An increase in capital expenditures, excluding nuclear fuel, of $146 million primarily due to spending on nuclear and transmission projects, partially offset by decreased spending on generation projects.

FINANCING CASH FLOWS

The following table summarizes key components of PEC's financing cash flows.

	Nine months ended September 30
(in millions)	2012			2011
Issuances of long-term debt, net	$	486		$	495
Notes payable and commercial paper		24			-
Dividends paid		(312	)		(452	)
Other financing items		(3	)		-
Net cash provided by financing activities	$	195		$	43

The increase in cash provided by financing activities in 2012 as compared to 2011 was primarily driven by:

·   A $140 decrease in payments of dividends to the Parent; and

·   A change in notes payable to affiliates of $212 million.

These increases were partially offset by:

·   Commercial paper repayments of $188 million in the current year.

CAPITAL RESOURCES

SIGNIFICANT NOTES PAYABLE AND LONG-TERM DEBT ACTIVITIES - 2012

On March 1, 2012, the Parent, as a well-known seasoned issuer, PEC and PEF filed a combined shelf registration statement with the SEC, which became effective upon filing with the SEC. The registration statement is effective for three years and does not limit the amount or number of various securities that can be issued. On July 3, 2012, the Parent deregistered its equity securities from the registration statement in connection with the merger, but retained its ability to issue senior debt securities and junior subordinated debentures under the registration statement.

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However, we do not expect the Parent to issue any new securities of these types in the future. Under PEC’s and PEF’s registration statements, they may issue various long-term debt securities and preferred stock.

On March 8, 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.

On May 18, 2012, PEC issued $500 million of 2.80% First Mortgage Bonds due May 15, 2022 and $500 million of 4.10% First Mortgage Bonds due May 15, 2042. The net proceeds were used to retire at maturity the $500 million outstanding aggregate principal balance of PEC’s 6.50% Notes due July 15, 2012 and a portion of PEC’s outstanding commercial paper and notes payable to affiliated companies.

MONEY POOL ARRANGEMENTS

PEC, PEF and PESC receive support for their short-term borrowing needs through participation with Duke Energy and certain of its subsidiaries in a money pool arrangement. Under this arrangement, those companies with short-term funds may provide short-term loans to participating affiliates. The money pool is structured such that the participants separately manage their cash needs and working capital requirements. Accordingly, there is no net settlement of receivables and payables between the money pool participants. Per the terms of the money pool arrangement, the parent companies, including Duke Energy Corporation and Progress Energy, Inc., may loan funds to their participating subsidiaries, but may not borrow funds through the money pool. The internal money pools that our subsidiaries participated in prior to the merger were terminated upon consummation of the merger.

AVAILABLE CREDIT FACILITIES AND RESTRICTIVE DEBT COVENANTS

On July 2, 2012, the Parent terminated its $478 million RCA, and PEC and PEF terminated their respective $750 million RCAs and became borrowers under the Duke Energy MCF. In November 2011, Duke Energy entered into a new $6.0 billion, five-year MCF, with $4.0 billion available at closing and the remaining $2.0 billion available following consummation of the merger. In October 2012, Duke Energy reached an agreement with banks representing $5.63 billion of commitments under the MCF to extend the expiration date by one year to November 2017. Through November 2016, the available credit under this facility remains $6 billion. PEC and PEF each have borrowing capacity under the MCF up to $750 million. However, Duke Energy has the unilateral ability at any time to increase or decrease the borrowing sublimit of each borrower, subject to a maximum sublimit of $1.0 billion each for PEC and PEF. Following the merger, the cash needs of the Parent will be funded with dividends from the Utilities generated from their earnings and cash flows, and to a lesser extent, dividends from other subsidiaries; borrowings under an intercompany note from Duke Energy and/or equity contributions from Duke Energy. None of the Progress Energy Registrants will issue commercial paper following the merger.

At September 30, 2012, the current portion of our long-term debt was $838 million, including $403 million and $435 million at PEC and PEF, respectively. PEC and PEF expect to fund their respective $400 million First Mortgage Bonds due September 15, 2013 and $425 million First Mortgage Bonds due March 1, 2013, with proceeds from additional borrowings.

FIRST MORTGAGE BOND RESTRICTIONS

PEC’s and PEF’s first mortgage bonds are secured under their respective mortgage indentures. Each mortgage constitutes a first lien on substantially all of the fixed properties of the respective company, subject to certain permitted encumbrances and exceptions. The lien of each mortgage also covers subsequently acquired property. Each mortgage allows the issuance of additional first mortgage bonds based on property additions, retirements of first mortgage bonds and the deposit of cash if certain conditions are satisfied. Each issuer is required to pass a “net earnings” test in order to issue new first mortgage bonds, other than on the basis of retired bonds under certain circumstances. The test requires that the issuer’s adjusted net earnings, which are calculated based on results for 12 consecutive months within the prior 15 to 18 months, be at least twice the annual interest requirement for bonds currently outstanding and to be outstanding. PEF’s ratio of net earnings to the annual interest requirement for bonds outstanding was slightly above 2.0 times during certain twelve-month periods ending in the quarter ended September 30, 2012, and thus PEF can currently issue first mortgage bonds. However, as discussed in Note 4B,

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PEF’s net earnings have been impacted by charges recorded for amounts to be refunded to customers under the terms of a February 2012 settlement agreement approved by the FPSC, which may impact future net earnings tests. In the event PEF’s long-term debt requirements exceed their first mortgage bond capacity, it can access alternative sources of capital, including, but not limited, to issuing unsecured public debt or through private placement, borrowing under the money pool, entering into bilateral direct loan arrangements, and, if necessary, utilizing the available capacity under the Duke Energy MCF.

RESTRICTIVE DEBT COVENANTS

The Progress Energy Registrants’ debt and credit agreements contain various financial and other covenants. The Duke Energy MCF contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65% for each borrower. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of September 30, 2012, each of the Progress Energy Registrants was in compliance with all covenants related to its significant debt agreements. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the significant debt or credit agreements contain material adverse change clauses.

CREDIT RATINGS

On July 25, 2012, Standard and Poor’s (S&P) affirmed Duke Energy and Progress Energy's short-term credit ratings of A-2. S&P also affirmed its ratings on PEC, PEF and other legacy Duke Energy subsidiaries’ first-mortgage bonds at A. However, S&P lowered its corporate credit rating for Duke Energy and other legacy Duke Energy subsidiaries to BBB+ from A- with a negative outlook, citing lack of transparency and heightened regulatory risk around the CEO transition. S&P affirmed Progress Energy’s corporate credit rating and its subsidiaries’ ratings at BBB+ as well as its A-2 short-term rating. S&P’s negative outlook for Duke Energy and all of its subsidiaries is based on increased regulatory risk in North Carolina and Florida and concerns over Duke Energy’s ability to successfully integrate Progress Energy.

On July 3, 2012, Moody’s Investors Service, Inc. (Moody’s) affirmed their ratings for the newly merged Duke Energy and its subsidiaries with a stable outlook. On July 6, 2012, Fitch Ratings initiated coverage on Duke Energy and its subsidiaries. These ratings are investment grade and are on stable outlook. On June 22, 2012, Fitch Ratings affirmed their ratings for the Progress Energy Registrants prior to the merger consummation.

A further downgrade below the current investment grade ratings of Duke Energy, legacy Duke Energy SEC registrant subsidiaries and the Progress Energy Registrants (collectively, the Duke Energy Registrants), would likely result in an increase in the entities’ borrowing costs, perhaps significantly. In addition, the Duke Energy Registrants’ potential pool of investors and funding sources would likely decrease. A downgrade below investment grade could also require the Duke Energy Registrants to post additional collateral in the form of letters of credit or cash under various commodity contracts and credit agreements and trigger termination clauses in some interest rate derivative agreements, which would require cash payments. All of these events would likely reduce the Duke Energy Registrants’ liquidity and profitability and could have a material adverse effect on the Duke Energy Registrants’ financial position, results of operations or cash flows.

REGULATORY MATTERS AND RECOVERY OF COSTS

Regulatory matters, including the CR3 outage and nuclear cost recovery, as discussed in Note 4 and “Other Matters – Nuclear,” and recovery of environmental costs, as discussed in Note 5, may impact our future liquidity and financing activities. The impacts of these matters, including the timing of recoveries from ratepayers, can be both a source of and a use of future liquidity resources. Energy legislation enacted in recent years may impact our liquidity over the long term, including among others, provisions regarding cost recovery, mandated renewable portfolio standards, DSM and EE.

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OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

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

GUARANTEES

At September 30, 2012, PEC’s guarantees have not changed materially from what was reported in the 2011 Form 10-K.

Effective with the consummation of the merger with Duke Energy on July 2, 2012, PEC and Duke Energy Carolinas have guaranteed to provide $650 million in system fuel savings for retail customers in North Carolina and South Carolina (See Note 2).

MARKET RISK AND DERIVATIVES

Under PEC’s risk management policy, PEC may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 8 in this quarterly report and, “Management’s Discussion and Analysis of Quantitative and Qualitative Disclosures About Market Risk” in the 2011 Form 10-K for a discussion of market risk and derivatives.

CONTRACTUAL OBLIGATIONS

PEC enters into contracts that require cash payment at specified periods, based on specified minimum quantities and prices. During the nine months ended September 30, 2012, there were no material changes in PEC’s contractual obligations outside the ordinary course of business. For an in-depth discussion of PEC’s contractual obligations, see Note22A and “MD&A – Contractual Obligations” in the 2011 Form 10-K.

OTHER MATTERS

ENVIRONMENTAL MATTERS

The table below summarizes the status of key environmental regulations that impact or may impact the Progress Energy Registrants. See Note 5A for a detailed discussion of each regulation.

	Status	Primarily Regulates	Compliance Strategy
Impacting Solid Waste
CCR
	Final rule is not expected before 2013	Storage, use and disposal of coal ash and flue gas desulfurization materials	Proposed rule included two significantly different options. Compliance method cannot be determined until the rule is finalized

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	Status	Primarily Regulates	Compliance Strategy
Impacting Air Quality
CAIR / CSAPR
	CAIR in effect pending resolution of appeal of CSAPR	NOx, SO2	Previously installed air pollution controls and fleet modernization projects, and use of emission allowances
MATS
	Compliance due April 2015 with provisions for one-year extension from state agencies on case-by- case basis	Mercury and other hazardous metals, acid gases, hydrogen fluoride, dioxin/furan from coal- and oil-fired steam electric generating units	Previously installed air pollution controls and fleet modernization projects largely address for PEC; for PEF, additional controls and/or fleet modernization required
CAVR – BART provisions
	Final requirements for PEF BART eligible units under development	NOx, SO2 and particulate matter	Assessing BART impact; PEF has obtained permits addressing CAVR – BART requirements for NOx, SO2 and particulate matter
NSPS
	Proposed rule issued   March 27, 2012	Greenhouse gas	Case-by-case determination for new units
Impacting Water Quality
316(b)
	Final rules are expected by June 27, 2013	Cooling water intake structures for steam-electric power plants	Modification of traveling screens; assessment of environmental impacts and alternative technologies for reducing those impacts; and possible installation of new technologies

NUCLEAR

Nuclear generating units are regulated by the NRC. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit or take some combination of these actions, depending upon its assessment of the severity of the situation, until compliance is achieved. Our nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs, uprates and certain other modifications.

FUKUSHIMA RESPONSE

Following the events at the Fukushima Daiichi nuclear power station in Japan, we conducted thorough inspections at each of our four nuclear sites during 2011. The initial inspections have not identified any significant vulnerabilities, however, we are reviewing designs to evaluate safety margins to external events. Emergency-response capabilities,

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written procedures and engineering specifications were reviewed to verify each site’s ability to respond in the unlikely event of station blackout. In 2012, we are working within the nuclear industry to improve the safety standards and margin using the three layers of safety approach used in the U.S.: protection, mitigation and emergency response. Emergency equipment is currently being added at each station to perform key safety functions in the event that backup power sources are lost permanently. These improvements are in addition to the numerous layers of safety measures and systems previously in place.

In March 2011, the NRC formed a task force to conduct a comprehensive review of processes and regulations to determine whether the agency should make additional improvements to the nuclear regulatory system. On July 13, 2011, the task force proposed a set of improvements designed to ensure protection, enhance accident mitigation, strengthen emergency preparedness and improve efficiency of NRC programs. The recommendations were further prioritized into three tiers based on the safety enhancement level. On March 12, 2012, the NRC issued three regulatory orders requiring safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at a plant, ensuring reliable hardened containment vents and enhancing spent fuel pool instrumentation. On August 30, 2012, the NRC issued implementation guidance to enable power plants to achieve compliance with the orders issued in March 2012. Plants are then required to submit implementation plans to the NRC by February 28, 2013, and complete implementation of the safety enhancements within two refueling outages or by December 31, 2016, whichever comes first. Each plant is also required to reassess their seismic and flooding hazards using present-day methods and information, conduct inspections to ensure protection against hazards in the current design basis, and re-evaluate emergency communications systems and staffing levels. In May 2012, the NRC issued guidance on re-evaluating emergency communications systems and staffing levels and performing seismic and flooding walkdowns. The NRC is expected to issue guidance on performing seismic and flooding re-evaluations in November 2012. On July 13, 2012 the NRC outlined plans for implementing Tier 2 and Tier 3 recommendations.

We are committed to compliance with all safety enhancements ordered by the NRC in connection with the March 12, 2012 regulatory orders noted above, the cost of which could be material. Until such time as the NRC mandated reassessment of flooding and seismic hazards is complete the exact scope and cost of compliance modifications to our four sites will not be known. With the NRC’s continuing review of the remaining recommendations, we cannot predict to what extent the NRC will impose additional licensing and safety-related requirements, or the costs of complying with such requirements. The tight timeframe required to complete the necessary safety enhancements by no later than 2016 could lead to even higher costs. Upon receipt of additional guidance from the NRC and a collaborative industry review, we will be able to determine our implementation plan and associated costs. See Item 1A, “Risk Factors”, in the 2011 Form 10-K for further discussion of applicable risk factors.

CR3 OUTAGE

In September 2009, 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, it was determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when an opening was created 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 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 evaluates possible 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.

PEF continues to analyze the various aspects of the repair option as well as the option of early retirement. This analysis includes the evaluation of the potential implications to scope, cost estimate and schedule from the project risks identified in the Zapata report. A number of factors could affect the decision to repair, the return-to-service date and repair costs incurred, including, but not limited to, state regulatory and NRC reviews, insurance recoveries from NEIL, the ability to obtain builder’s risk insurance with appropriate coverage, final engineering designs, vendor contract negotiations, the ultimate work scope completion, performance testing, weather and the impact of

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new information discovered during additional testing and analysis. We will proceed with the repair option only if there is a high degree of confidence that the repair can be successfully completed and licensed within the final estimated costs and schedule, and it is in the best interests of PEF’s customers, the joint owners and Duke Energy’s investors (See Note 4B).

POTENTIAL NEW CONSTRUCTION

See Note 4 for discussion of the status of potential construction of new nuclear units.

SPENT NUCLEAR FUEL MATTERS

See Note 5B for discussion of the status of the Utilities’ contracts with the DOE for spent nuclear fuel storage.

LEGAL

We are subject to federal, state and local legislation and court orders. The specific issues, the status of the issues, accruals associated with issue resolutions and our associated exposures are discussed in detail in Note 5B.

NEW ACCOUNTING STANDARDS

See Note 16 for a discussion of the impact of new accounting standards.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no significant changes from the disclosures presented in the 2011 Form 10-K. For an in-depth discussion of PEC’s market risks, see “Management’s Discussion and Analysis of Quantitative and Qualitative Disclosures about Market Risk” in the 2011 Form 10-K.

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ITEM 4. CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by the Progress Energy Registrants in the reports they file or submit under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms.

Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Progress Energy Registrants in the reports they file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, the Progress Energy Registrants have evaluated the effectiveness of their disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2012, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance of compliance.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, the Progress Energy Registrants have evaluated changes in internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended September 30, 2012, and have concluded no change has materially affected, or is reasonably likely to affect, internal control over financial reporting.

On July 2, 2012, the previously announced merger between Duke Energy and Progress Energy was consummated. Duke Energy is currently in the process of integrating Progress Energy’s operations and will be conducting control reviews pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. See Notes 2, 4 and 5 for additional information relating to the merger.

PART II.  OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Legal aspects of certain matters are set forth in PART I, Item 1 (See Note 4 and Note 5B).

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Item 1A, “Risk Factors,” to the 2011 Form 10-K, which could materially affect our business, financial condition or financial results. The risks described in the 2011 Form 10-K are not the only risks facing us.

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ITEM 6.  EXHIBITS

(a)   Exhibits

Exhibit Number	Description	Progress Energy	PEC	PEF
*3(a)	Articles of Incorporation of Progress Energy, Inc. (filed as Exhibit 3.1 to Current Report on Form 8-K dated July 2, 2012, File No. 1-15929).	X
*3(b)	Bylaws of Progress Energy, Inc. (filed as Exhibit 3.2 to Current Report on Form 8-K dated July 2, 2012, File No. 1-15929).	X
*10	Credit Agreement, dated as of November 18, 2011, among Duke Energy Corporation and certain of its subsidiaries party thereto, as Borrowers, the lenders listed therein and Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.1 to Duke Energy Corporation’s Current Report on Form 8-K filed on November 25, 2011, File No. 1-32853).		X	X
18	Preferability Letter of Deloitte & Touche	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

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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.

** Attached as Exhibit 101 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 September 30, 2012, formatted in Extensible Business Reporting Language (XBRL): (i) the Unaudited Condensed Consolidated Statements of Operations and 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.

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.

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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: November 8, 2012	(Registrants)
	By: /s/ Lynn J. Good
	Lynn J. Good
	Executive Vice President and Chief Financial Officer
	By: /s/ Steven K. Young
	Steven K. Young
	Vice President, Chief Accounting Officer and Controller

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EX-18

Exhibit 18

November 8, 2012

Progress Energy, Inc.

410 South Wilmington Street

Raleigh, North Carolina 27601

Dear Sirs/Madams:

At your request, we have read the description included in your Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended September 30, 2012, of the facts relating to your change in the date of the annual goodwill impairment test from October 31 to August 31. We believe, on the basis of the facts so set forth and other information furnished to us by appropriate officials of the Company, that the accounting change described in your Form 10-Q is to an alternative accounting principle that is preferable under the circumstances.

We have not audited any consolidated financial statements of Progress Energy, Inc. and its consolidated subsidiaries as of any date or for any period subsequent to December 31, 2011. Therefore, we are unable to express, and we do not express, an opinion on the facts set forth in the above-mentioned Form 10-Q, on the related information furnished to us by officials of the Company, or on the financial position, results of operations, or cash flows of Progress Energy, Inc. and its consolidated subsidiaries as of any date or for any period subsequent to December 31, 2011.

Yours truly,

/s/ DELOITTE & TOUCHE LLP

Charlotte, North Carolina

EX-31.A

Exhibit 31(a)

CERTIFICATION

I, James E. Rogers, certify that:

1.   I have reviewed this Quarterly Report on Form 10-Q of Progress Energy, Inc.;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)   Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 8, 2012	By: /s/ James E. Rogers
	James E. Rogers
	Chief Executive Officer

EX-31.B

Exhibit 31(b)

CERTIFICATION

I, Lynn J. Good, certify that:

1.   I have reviewed this Quarterly Report on Form 10-Q of Progress Energy, Inc.;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)   Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 8, 2012	By: /s/ Lynn J. Good
	Lynn J. Good
	Chief Financial Officer

EX-31.C

Exhibit 31(c)

CERTIFICATION

I, James E. Rogers, certify that:

1.   I have reviewed this Quarterly Report on Form 10-Q of Carolina Power & Light Company;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)   Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 8, 2012	By: /s/ James E. Rogers
	James E. Rogers
	Chief Executive Officer

EX-31.D

Exhibit 31(d)

CERTIFICATION

I, Lynn J. Good, certify that:

1.   I have reviewed this Quarterly Report on Form 10-Q of Carolina Power & Light Company;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)   Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 8, 2012	By: /s/ Lynn J. Good
	Lynn J. Good
	Chief Financial Officer

EX-31.E

Exhibit 31(e)

CERTIFICATION

I, James E. Rogers, certify that:

1.   I have reviewed this Quarterly Report on Form 10-Q of Florida Power Corporation;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)   Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 8, 2012	By: /s/ James E. Rogers
	James E. Rogers
	Chief Executive Officer

EX-31.F

Exhibit 31(f)

CERTIFICATION

I, Lynn J. Good, certify that:

1.   I have reviewed this Quarterly Report on Form 10-Q of Florida Power Corporation;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)   Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 8, 2012	By: /s/ Lynn J. Good
	Lynn J. Good
	Chief Financial Officer

EX-32.A

Exhibit 32(a)

CERTIFICATION FURNISHED PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Progress Energy, Inc. (the “Company”) for the period ended September 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, James E. Rogers, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)           the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(2)           the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ James E. Rogers

James E. Rogers

Chief Executive Officer

November 8, 2012

This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended.

EX-32.B

Exhibit 32(b)

CERTIFICATION FURNISHED PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Progress Energy, Inc. (the “Company”) for the period ended September 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Lynn J. Good, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)           the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(2)           the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Lynn J. Good

Lynn J. Good

Chief Financial Officer

November 8, 2012

This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended.

EX-32.C

Exhibit 32(c)

CERTIFICATION FURNISHED PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Carolina Power & Light Company (the “Company”) for the period ended September 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, James E. Rogers, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)           the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(2)           the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ James E. Rogers

James E. Rogers

Chief Executive Officer

November 8, 2012

This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended.

EX-32.D

Exhibit 32(d)

CERTIFICATION FURNISHED PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Carolina Power & Light Company (the “Company”) for the period ended September 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Lynn J. Good, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)           the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(2)           the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Lynn J. Good

Lynn J. Good

Chief Financial Officer

November 8, 2012

This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended.

EX-32.E

Exhibit 32(e)

CERTIFICATION FURNISHED PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Florida Power Corporation (the “Company”) for the period ended September 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, James E. Rogers, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)           the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(2)           the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

U/s/ James E. Rogers

James E. Rogers

Chief Executive Officer

November 8, 2012

This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended.

EX-32.F

Exhibit 32(f)

CERTIFICATION FURNISHED PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Florida Power Corporation (the “Company”) for the period ended September 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Lynn J. Good, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)           the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(2)           the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Lynn J. Good

Lynn J. Good

Chief Financial Officer

November 8, 2012

This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended.

XML

Merger Agreement (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended			6 Months Ended	9 Months Ended					3 Months Ended	9 Months Ended	12 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2012		Sep. 30, 2011	Jun. 30, 2012	Sep. 30, 2012		Sep. 30, 2011	Jul. 02, 2012	Dec. 31, 2011	Sep. 30, 2012 Other Duke Subsidiaries [Member]	Sep. 30, 2012 Other Duke Subsidiaries [Member]	Sep. 30, 2012 Other Duke Subsidiaries [Member]	Sep. 30, 2012 PEC [Member]	Sep. 30, 2011 PEC [Member]	Sep. 30, 2012 PEC [Member]	Sep. 30, 2011 PEC [Member]	Sep. 30, 2012 PEC [Member]	Sep. 30, 2012 PEF [Member]	Sep. 30, 2011 PEF [Member]	Sep. 30, 2012 PEF [Member]	Sep. 30, 2011 PEF [Member]	Sep. 30, 2012 PEF [Member]
Discontinued operations attributable to controlling interests
Income (loss) from discontinued operations, net of tax	$ 3		$ 0		$ 10		$ (4)
Discontinued operations, pre-tax gain from indemnification reversals					18
Merger Agreement [Line Items]
Merger Share Exchange Ratio, Adjusted								0.87083
Settlement agreement, fuel savings	650				650
Interim FERC Mitigation Rate Reduction					65
Community support and charitable contributions					99
FERC Mitigation					71										71
Severance Charges	66				66								42		42			24		24
Community support, charitable contributions and other					63										54					9
Total charges recognized					200										167					33
Cost to achieve the merger, pre-tax	218		14		241		32						180	7	194	17		38	7	47	15
Estimated exit cost liability	17				17
Exit cost liability recognized	2	[1]		5	7					1	1	1	1		4		8	0		2		3
Estimated exit cost liability expense allocation											4				9					4
Exit cost liability	$ 12	[2]		$ 10	$ 12	[2]			$ 5

[1] PEC, PEF and other Duke Energy subsidiaries recognized exit costs of $1 million, $- million and $1 million, respectively, for the three months ended September 30, 2012, and $4 million, $2 million and $1 million, respectively, for the nine months ended September 30, 2012.

[2] Expense related to the recognition of the cumulative exit cost liability at September 30, 2012, was attributed to PEC, PEF and other Duke Energy subsidiaries totaling $8 million, $3 million and $1 million, respectively.

XML

Benefit Plans - Assets of Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
PEF [Member]
Assets Of Benefit Plans [Line Items]
Plan assets reclassified to investments	$ 39
Pension Benefits [Member]
Assets Of Benefit Plans [Line Items]
Employer contributions made directly to pension plan assets	122
Pension Benefits [Member] | PEC [Member]
Assets Of Benefit Plans [Line Items]
Employer contributions made directly to pension plan assets	60
Pension Benefits [Member] | PEF [Member]
Assets Of Benefit Plans [Line Items]
Employer contributions made directly to pension plan assets	$ 61

XML

Risk Management Activities and Derivatives Transactions (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011		Dec. 31, 2011
Risk Management Activities And Derivative Transactions Disclosure [Line Items]
Undesignated hedges termination dates					2,015
Notional amounts of derivative instruments related to interest rate
Cash flow hedges									$ 500
Undesignated contracts	100				100
Underlying notional amounts for commodity derivative instruments accounted for at fair value
Electricity-energy (Gigawatt-hours)	1,850	[1]			1,850	[1]
Electricity-capacity (Gigawatt-months)	5	[1]			5	[1]
Natural gas (millions of decatherms)	297,000,000				297,000,000				347,000,000
Fuel Oil (millions of gallons)	6,000,000				6,000,000				10,000,000
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	23				23				5
Location and fair value amounts of derivatives (Liability)	457				457				799
Fair Value Of Derivative Instruments Parenthetical Information
CVO's in connection with the acquisition of Florida Progress during 2000	98.6				98.6				98.6
CVO's repurchased in connection with the negotiated settlement agreement and subsequent tender offer	83.4				83.4				80.1
Information regarding derivative instruments that contain credit-risk-related contingent features
Aggregate fair value amounts of derivative instruments in a net liability position	325				325				489
Collateral already posted	74				74				147
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered at the end of the reporting period	251				251				342
Information regarding cash collateral under master netting arrangements
Amounts offset against net derivative positions (right to reclaim cash collateral)	73				73				140
Amounts not offset against net derivative positions (right to reclaim cash collateral)	1				1				3
PEC [Member]
Risk Management Activities And Derivative Transactions Disclosure [Line Items]
Undesignated hedges termination dates					2,015
Notional amounts of derivative instruments related to interest rate
Cash flow hedges									250
Undesignated contracts	50				50
Underlying notional amounts for commodity derivative instruments accounted for at fair value
Electricity-energy (Gigawatt-hours)	1,850	[1]			1,850	[1]
Electricity-capacity (Gigawatt-months)	5	[1]			5	[1]
Natural gas (millions of decatherms)	89,000,000				89,000,000				103,000,000
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	5				5				0
Location and fair value amounts of derivatives (Liability)	159				159				248
Information regarding derivative instruments that contain credit-risk-related contingent features
Aggregate fair value amounts of derivative instruments in a net liability position	118				118				152
Collateral already posted	13				13				24
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered at the end of the reporting period	105				105				128
Information regarding cash collateral under master netting arrangements
Amounts offset against net derivative positions (right to reclaim cash collateral)	13				13				23
Amounts not offset against net derivative positions (right to reclaim cash collateral)	0				0				0
PEF [Member]
Risk Management Activities And Derivative Transactions Disclosure [Line Items]
Undesignated hedges termination dates					2,015
Notional amounts of derivative instruments related to interest rate
Cash flow hedges									50
Undesignated contracts	50				50
Underlying notional amounts for commodity derivative instruments accounted for at fair value
Natural gas (millions of decatherms)	208,000,000				208,000,000				244,000,000
Fuel Oil (millions of gallons)	6,000,000				6,000,000				10,000,000
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	18				18				5
Location and fair value amounts of derivatives (Liability)	294				294				499
Information regarding derivative instruments that contain credit-risk-related contingent features
Aggregate fair value amounts of derivative instruments in a net liability position	207				207				337
Collateral already posted	61				61				123
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered at the end of the reporting period	146				146				214
Information regarding cash collateral under master netting arrangements
Amounts offset against net derivative positions (right to reclaim cash collateral)	60				60				117
Amounts not offset against net derivative positions (right to reclaim cash collateral)	1				1				3
Derivatives Designated As Hedging Instruments [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)	1				1				96
Cash flow hedges-location and amount of pre-tax gains and (losses)
Pre-tax gains (losses) recognized in OCI	1		(112)		(10)		(135)
Location of pre-tax gains (losses) reclassified from OCI into income	(2)		(3)		(12)		(9)
Location of pre-tax gains (losses) recognized in income on derivatives	0		(1)		0		(3)
Derivatives Designated As Hedging Instruments [Member] | PEC [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)	0				0				47
Cash flow hedges-location and amount of pre-tax gains and (losses)
Pre-tax gains (losses) recognized in OCI	0		(58)		(7)		(67)
Location of pre-tax gains (losses) reclassified from OCI into income	0		(2)		(5)		(5)
Location of pre-tax gains (losses) recognized in income on derivatives	0		(1)		0		(1)
Derivatives Designated As Hedging Instruments [Member] | PEF [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)	1				1				11
Cash flow hedges-location and amount of pre-tax gains and (losses)
Pre-tax gains (losses) recognized in OCI	1		(28)		(1)		(36)
Location of pre-tax gains (losses) reclassified from OCI into income	0		0		(2)		0
Location of pre-tax gains (losses) recognized in income on derivatives	0		0		0		0
Derivatives Not Designated As Hedging Instruments [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	23				23				5
Location and fair value amounts of derivatives (Liability)	456				456				703
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in earnings	(148)		(91)		(408)		(219)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities	62		(157)		(106)		(201)
Location of pre-tax gains and (losses) recognized in income on derivatives	(1)		(62)		10		(57)
Derivatives Not Designated As Hedging Instruments [Member] | PEC [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	5				5				0
Location and fair value amounts of derivatives (Liability)	159				159				201
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in earnings	(47)		(20)		(112)		(42)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities	17		(42)		(32)		(55)
Location of pre-tax gains and (losses) recognized in income on derivatives	0		1		3		2
Derivatives Not Designated As Hedging Instruments [Member] | PEF [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	18				18				5
Location and fair value amounts of derivatives (Liability)	293				293				488
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in earnings	(101)		(71)		(296)		(177)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities	45		(115)		(74)		(146)
Location of pre-tax gains and (losses) recognized in income on derivatives	0		0		0		0
Interest Rate Derivatives [Member] | PEC [Member]
Risk Management Activities And Derivative Transactions Disclosure [Line Items]
Pre-tax deferred net losses related to interest rate hedges relcassed from AOCI to regulatory assets	117				117
Interest Rate Derivatives [Member] | PEF [Member]
Risk Management Activities And Derivative Transactions Disclosure [Line Items]
Pre-tax deferred net losses related to interest rate hedges relcassed from AOCI to regulatory assets	42				42
Interest Rate Derivatives [Member] | Derivatives Designated As Hedging Instruments [Member]
Cash flow hedges-location and amount of pre-tax gains and (losses)
Amount of pre-tax gains (losses) recorded in AOCI	71				71				232
Next 12 months amount to reclass to interest expense					5
Interest Rate Derivatives [Member] | Derivatives Designated As Hedging Instruments [Member] | PEC [Member]
Cash flow hedges-location and amount of pre-tax gains and (losses)
Amount of pre-tax gains (losses) recorded in AOCI									116
Interest Rate Derivatives [Member] | Derivatives Designated As Hedging Instruments [Member] | PEF [Member]
Cash flow hedges-location and amount of pre-tax gains and (losses)
Amount of pre-tax gains (losses) recorded in AOCI									41
Interest Rate Derivatives [Member] | Other Comprehensive Income (Loss) [Member] | Derivatives Designated As Hedging Instruments [Member]
Cash flow hedges-location and amount of pre-tax gains and (losses)
Pre-tax gains (losses) recognized in OCI	0	[2],[3]	(111)	[2],[3]	(11)	[2],[3]	(134)	[2],[3]
Interest Rate Derivatives [Member] | Other Comprehensive Income (Loss) [Member] | Derivatives Designated As Hedging Instruments [Member] | PEC [Member]
Cash flow hedges-location and amount of pre-tax gains and (losses)
Pre-tax gains (losses) recognized in OCI	0	[2],[3]	(58)	[2],[3]	(7)	[2],[3]	(67)	[2],[3]
Interest Rate Derivatives [Member] | Other Comprehensive Income (Loss) [Member] | Derivatives Designated As Hedging Instruments [Member] | PEF [Member]
Cash flow hedges-location and amount of pre-tax gains and (losses)
Pre-tax gains (losses) recognized in OCI	0	[2],[3]	(27)	[2],[3]	(2)	[2],[3]	(35)	[2],[3]
Interest Rate Derivatives [Member] | Interest Expense [Member] | Derivatives Designated As Hedging Instruments [Member]
Cash flow hedges-location and amount of pre-tax gains and (losses)
Location of pre-tax gains (losses) reclassified from OCI into income	(2)	[2],[3]	(3)	[2],[3]	(12)	[2],[3]	(9)	[2],[3]
Location of pre-tax gains (losses) recognized in income on derivatives	0	[3],[4]	(1)	[3],[4]	0	[3],[4]	(3)	[3],[4]
Interest Rate Derivatives [Member] | Interest Expense [Member] | Derivatives Designated As Hedging Instruments [Member] | PEC [Member]
Cash flow hedges-location and amount of pre-tax gains and (losses)
Location of pre-tax gains (losses) reclassified from OCI into income	0	[2],[3]	(2)	[2],[3]	(5)	[2],[3]	(5)	[2],[3]
Location of pre-tax gains (losses) recognized in income on derivatives	0	[3],[4]	(1)	[3],[4]	0	[3],[4]	(1)	[3],[4]
Interest Rate Derivatives [Member] | Interest Expense [Member] | Derivatives Designated As Hedging Instruments [Member] | PEF [Member]
Cash flow hedges-location and amount of pre-tax gains and (losses)
Location of pre-tax gains (losses) reclassified from OCI into income	0	[2],[3]	0	[2],[3]	(2)	[2],[3]	0	[2],[3]
Location of pre-tax gains (losses) recognized in income on derivatives	0	[3],[4]	0	[3],[4]	0	[3],[4]	0	[3],[4]
Interest Rate Derivatives [Member] | Interest Expense [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in earnings	(4)	[5]	0	[5]	(4)	[5]	0	[5]
Interest Rate Derivatives [Member] | Interest Expense [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEC [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in earnings	(3)	[5]	0	[5]	(3)	[5]	0	[5]
Interest Rate Derivatives [Member] | Interest Expense [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEF [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in earnings	(1)	[5]	0	[5]	(1)	[5]	0	[5]
Interest Rate Derivatives [Member] | Derivative Liabilities, Current [Member] | Derivatives Designated As Hedging Instruments [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)									76
Interest Rate Derivatives [Member] | Derivative Liabilities, Current [Member] | Derivatives Designated As Hedging Instruments [Member] | PEC [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)									38
Interest Rate Derivatives [Member] | Derivative Liabilities, Current [Member] | Derivatives Designated As Hedging Instruments [Member] | PEF [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)									0
Interest Rate Derivatives [Member] | Derivative Liabilities, Current [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)	23	[6]			23	[6]
Interest Rate Derivatives [Member] | Derivative Liabilities, Current [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEC [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)	11	[6]			11	[6]
Interest Rate Derivatives [Member] | Derivative Liabilities, Current [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEF [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)	12	[6]			12	[6]
Interest Rate Derivatives [Member] | Deferred Credits And Other Liabilities [Member] | Derivatives Designated As Hedging Instruments [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)									17
Interest Rate Derivatives [Member] | Deferred Credits And Other Liabilities [Member] | Derivatives Designated As Hedging Instruments [Member] | PEC [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)									9
Interest Rate Derivatives [Member] | Deferred Credits And Other Liabilities [Member] | Derivatives Designated As Hedging Instruments [Member] | PEF [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)									8
Interest Rate Derivatives [Member] | Regulatory Asset [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities	2	[5]	0	[5]	2	[5]	0	[5]
Interest Rate Derivatives [Member] | Regulatory Asset [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEC [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities	2	[5]	0	[5]	2	[5]	0	[5]
Interest Rate Derivatives [Member] | Regulatory Asset [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEF [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities	0	[5]	0	[5]	0	[5]	0	[5]
Commodity Derivatives [Member] | Other Comprehensive Income (Loss) [Member] | Derivatives Designated As Hedging Instruments [Member]
Cash flow hedges-location and amount of pre-tax gains and (losses)
Pre-tax gains (losses) recognized in OCI	1	[2]	(1)	[2]	1	[2]	(1)	[2]
Commodity Derivatives [Member] | Other Comprehensive Income (Loss) [Member] | Derivatives Designated As Hedging Instruments [Member] | PEC [Member]
Cash flow hedges-location and amount of pre-tax gains and (losses)
Pre-tax gains (losses) recognized in OCI	0	[2]	0	[2]	0	[2]	0	[2]
Commodity Derivatives [Member] | Other Comprehensive Income (Loss) [Member] | Derivatives Designated As Hedging Instruments [Member] | PEF [Member]
Cash flow hedges-location and amount of pre-tax gains and (losses)
Pre-tax gains (losses) recognized in OCI	1	[2]	(1)	[2]	1	[2]	(1)	[2]
Commodity Derivatives [Member] | Regulated electric revenue [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in earnings	(9)				(9)
Location of pre-tax gains and (losses) recognized in income on derivatives					2		1
Commodity Derivatives [Member] | Regulated electric revenue [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEC [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in earnings	(9)				(9)
Location of pre-tax gains and (losses) recognized in income on derivatives					2		1
Commodity Derivatives [Member] | Regulated electric revenue [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEF [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in income on derivatives					0		0
Commodity Derivatives [Member] | Cost Of Regulated Electric [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in earnings	(135)	[7]	(91)	[7]	(395)	[7]	(219)	[7]
Commodity Derivatives [Member] | Cost Of Regulated Electric [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEC [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in earnings	(35)	[7]	(20)	[7]	(100)	[7]	(42)	[7]
Commodity Derivatives [Member] | Cost Of Regulated Electric [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEF [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in earnings	(100)	[7]	(71)	[7]	(295)	[7]	(177)	[7]
Commodity Derivatives [Member] | Investments And Other Assets, Other [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	1	[6]			1	[6]
Commodity Derivatives [Member] | Investments And Other Assets, Other [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEC [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	0	[6]			0	[6]
Commodity Derivatives [Member] | Investments And Other Assets, Other [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEF [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	1	[6]			1	[6]
Commodity Derivatives [Member] | Derivative Liabilities, Current [Member] | Derivatives Designated As Hedging Instruments [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)	1				1				2
Commodity Derivatives [Member] | Derivative Liabilities, Current [Member] | Derivatives Designated As Hedging Instruments [Member] | PEC [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)	0				0				0
Commodity Derivatives [Member] | Derivative Liabilities, Current [Member] | Derivatives Designated As Hedging Instruments [Member] | PEF [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)	1				1				2
Commodity Derivatives [Member] | Derivative Liabilities, Current [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	8	[6]			8	[6]			5	[6]
Location and fair value amounts of derivatives (Liability)	220	[6]			220	[6]			357	[6]
Commodity Derivatives [Member] | Derivative Liabilities, Current [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEC [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	3	[6]			3	[6]			0	[6]
Location and fair value amounts of derivatives (Liability)	74	[6]			74	[6]			91	[6]
Commodity Derivatives [Member] | Derivative Liabilities, Current [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEF [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	5	[6]			5	[6]			5	[6]
Location and fair value amounts of derivatives (Liability)	146	[6]			146	[6]			266	[6]
Commodity Derivatives [Member] | Deferred Credits And Other Liabilities [Member] | Derivatives Designated As Hedging Instruments [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)									1
Commodity Derivatives [Member] | Deferred Credits And Other Liabilities [Member] | Derivatives Designated As Hedging Instruments [Member] | PEC [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)									0
Commodity Derivatives [Member] | Deferred Credits And Other Liabilities [Member] | Derivatives Designated As Hedging Instruments [Member] | PEF [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)									1
Commodity Derivatives [Member] | Deferred Credits And Other Liabilities [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	14	[6]			14	[6]			0	[6]
Location and fair value amounts of derivatives (Liability)	209	[6]			209	[6]			332	[6]
Commodity Derivatives [Member] | Deferred Credits And Other Liabilities [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEC [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	2	[6]			2	[6]			0	[6]
Location and fair value amounts of derivatives (Liability)	74	[6]			74	[6]			110	[6]
Commodity Derivatives [Member] | Deferred Credits And Other Liabilities [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEF [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Asset)	12	[6]			12	[6]			0	[6]
Location and fair value amounts of derivatives (Liability)	135	[6]			135	[6]			222	[6]
Commodity Derivatives [Member] | Regulatory Asset [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities	60	[8]	(157)	[8]	(108)	[8]	(201)	[8]
Commodity Derivatives [Member] | Regulatory Asset [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEC [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities	15	[8]	(42)	[8]	(34)	[8]	(55)	[8]
Commodity Derivatives [Member] | Regulatory Asset [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEF [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities	45	[8]	(115)	[8]	(74)	[8]	(146)	[8]
CVOs [Member] | Other Income And Expense [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in income on derivatives	(1)		(63)		7		(59)
CVOs [Member] | Other Current Liabilities [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)									14	[9]
CVOs [Member] | Deferred Credits And Other Liabilities [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Location and fair value of derivatives
Location and fair value amounts of derivatives (Liability)	4	[10]			4	[10]
Fair Value Loss Transition Adjustment [Member] | Regulated electric revenue [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in income on derivatives	0		1		1		1
Fair Value Loss Transition Adjustment [Member] | Regulated electric revenue [Member] | Derivatives Not Designated As Hedging Instruments [Member] | PEC [Member]
Undesignated contracts-location and amount of pre-tax gains and (losses)
Location of pre-tax gains and (losses) recognized in income on derivatives	$ 0		$ 1		$ 1		$ 1

[1] Interim FERC Mitigation power sales agreements entered into in connection with the merger with Duke Energy.

[2] Effective portion.

[3] Amounts in AOCI 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] Related to ineffective portion and amount excluded from effectiveness testing.

[5] Amounts in regulatory assets and liabilities related to terminated hedges are reclassified to earnings as the interest expense is recorded. The hedges will be amortized to interest expense over the term of the related debt.

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

[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 assets and liabilities in the Balance Sheets until derivatives are settled.

[9] 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. In 2011, we repurchased and continue to hold 80.1 million CVOs in a negotiated settlement agreement and subsequent tender offer.

[10] As discussed in Note 16 in the 2011 Form 10-K, the Parent issued 98.6 million Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (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.

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Benefit Plans - Contribution and Benefit Payment Expectations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Defined Contribution Benefit And Other Postretirement Plans Disclosure [Abstract]
Defined contribution plan, cost recognized	$ 12	$ 12	$ 35	$ 34
PEC [Member]
Defined Contribution Benefit And Other Postretirement Plans Disclosure [Abstract]
Defined contribution plan, cost recognized	7	6	18	18
PEF [Member]
Defined Contribution Benefit And Other Postretirement Plans Disclosure [Abstract]
Defined contribution plan, cost recognized	4	4	11	11
Pension Benefits [Member]
Contribution And Benefit Payment [Line Items]
2012 expected contributions	146		146
Pension Benefits [Member] | PEC [Member]
Contribution And Benefit Payment [Line Items]
2012 expected contributions	71		71
Pension Benefits [Member] | PEF [Member]
Contribution And Benefit Payment [Line Items]
2012 expected contributions	$ 74		$ 74

XML

Debt and Credit Facilities - Debt and Credit Facilities (Details) (USD $)	9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011
Long-term debt [Line Items]
Current maturities of long-term debt	$ 838,000,000	$ 961,000,000
Duke Energy [Member]
RCAs and available capacity [Line Items]
Available capacity	4,000,000,000
Line of credit facility, conditional capacity	2,000,000,000
MCF expiring November 2017 [Member] | Duke Energy [Member]
RCAs and available capacity [Line Items]
Facility size	5,630,000,000
Parent [Member]
Long-term debt [Line Items]
Current maturities of long-term debt	0	450,000,000
RCAs and available capacity [Line Items]
RCA termination date	July 2, 2012
Available capacity	478,000,000
Parent [Member] | Senior Notes Due April 15, 2012
Long-term debt [Line Items]
Maturity date	Apr. 15, 2012
Maturities of debt	450,000,000
Debt instrument, interest rate stated percentage	6.85%
Parent [Member] | Senior Notes Due April 1, 2022
Long-term debt [Line Items]
Debt instrument, face amount	450,000,000
Maturity date	Apr. 01, 2022
Debt instrument issuance date	March 8, 2012
Debt instrument, interest rate stated percentage	3.15%
PEC [Member]
Long-term debt [Line Items]
Current maturities of long-term debt	403,000,000	502,000,000
RCAs and available capacity [Line Items]
Available capacity	600,000,000
Facility size	750,000,000
Line of credit facility, conditional capacity	1,000,000,000
PEC [Member] | Notes Due July 15, 2012 [Member]
Long-term debt [Line Items]
Maturity date	Jul. 15, 2012
Maturities of debt	500,000,000
Debt instrument, interest rate stated percentage	6.50%
PEC [Member] | First Mortgage Bonds [Member]
Long-term debt [Line Items]
Maturity date	Sep. 15, 2013
Debt instrument, interest rate stated percentage	5.125%
Current maturities of long-term debt	400,000,000
PEC [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds Due May 15, 2022
Long-term debt [Line Items]
Debt instrument, face amount	500,000,000
Maturity date	May 15, 2022
Debt instrument issuance date	May 18, 2012
Debt instrument, interest rate stated percentage	2.80%
PEC [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds Due May 15, 2042 [Member]
Long-term debt [Line Items]
Debt instrument, face amount	500,000,000
Maturity date	May 15, 2042
Debt instrument issuance date	May 18, 2012
Debt instrument, interest rate stated percentage	4.10%
PEF [Member]
Long-term debt [Line Items]
Current maturities of long-term debt	435,000,000	10,000,000
RCAs and available capacity [Line Items]
Available capacity	600,000,000
Facility size	750,000,000
Line of credit facility, conditional capacity	1,000,000,000
PEF [Member] | First Mortgage Bonds [Member]
Long-term debt [Line Items]
Maturity date	Mar. 01, 2013
Debt instrument, interest rate stated percentage	4.80%
Current maturities of long-term debt	$ 425,000,000

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Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2012

Variable Interest Entity [Line Items]

Variable interest entity consolidated

(in millions)		September 30, 2012		December 31, 2011
Net property, plant and equipment(a)		$	12	$	12
Prepayments and other current assets(a)			2		1
Net assets of consolidated VIEs		$	14	$	13
(a)	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. 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.

PEC [Member]

Variable Interest Entity [Line Items]

Variable interest entity consolidated

(in millions)		September 30, 2012		December 31, 2011
Net property, plant and equipment(a)		$	12	$	12
Prepayments and other current assets(a)			2		1
Net assets of consolidated VIEs		$	14	$	13
(a)	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. 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.

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Reconciliations of effective income tax rate to the statutory federal income tax rate
Effective income tax rate	32.80%	37.80%	34.70%	36.90%
Excise Taxes [Abstract]
Excise taxes	$ 95	$ 96	$ 241	$ 245
PEC [Member]
Reconciliations of effective income tax rate to the statutory federal income tax rate
Effective income tax rate	31.90%	33.40%	31.60%	34.20%
Excise Taxes [Abstract]
Excise taxes	33	33	85	86
PEF [Member]
Reconciliations of effective income tax rate to the statutory federal income tax rate
Effective income tax rate	35.90%	37.00%	36.90%	37.00%
Excise Taxes [Abstract]
Excise taxes	$ 62	$ 63	$ 156	$ 159

XML

Organization and Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2012

Disclosure Organization And Summary Of Significant Accounting Policies [Line Items]

Schedule of Unbilled Revenues [Text Block]

(in millions)	September 30, 2012		December 31, 2011
Progress Energy	$	190		$	157
PEC	$	99		$	102
PEF	$	91		$	55

PEC [Member]

Disclosure Organization And Summary Of Significant Accounting Policies [Line Items]

Schedule of Unbilled Revenues [Text Block]

(in millions)	September 30, 2012		December 31, 2011
Progress Energy	$	190		$	157
PEC	$	99		$	102
PEF	$	91		$	55

PEF [Member]

Disclosure Organization And Summary Of Significant Accounting Policies [Line Items]

Schedule of Unbilled Revenues [Text Block]

(in millions)	September 30, 2012		December 31, 2011
Progress Energy	$	190		$	157
PEC	$	99		$	102
PEF	$	91		$	55

XML

Investments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Schedule Of Available For Sale Securities [Abstract]
Fair Value	$ 1,904		$ 1,904		$ 1,650
Unrealized Losses	23		23		31
Unrealized Gains	573		573		444
Fair Value Of Available For Sale Debt Securities By Contractual Maturity [Abstract]
Due in one year or less	13		13
Due after one through five years	125		125
Due after five through 10 years	136		136
Due after 10 years	301		301
Total	575		575
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	121		121
Available-for-sale securities, continuous unrealized loss position, 12 months or longer, aggregate losses	14		14
Available-for-sale securities, continuous unrealized loss position, less than twelve months, aggregate losses	9		9
Sales Of Available For Sale Securities [Abstract]
Proceeds	274	1,062	794	4,254
Realized gains	8	9	23	24
Realized losses	6	11	12	20
PEC [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	1,229		1,229		1,107
Unrealized Losses	15		15		20
Unrealized Gains	368		368		287
Fair Value Of Available For Sale Debt Securities By Contractual Maturity [Abstract]
Due in one year or less	11		11
Due after one through five years	102		102
Due after five through 10 years	72		72
Due after 10 years	194		194
Total	379		379
Sales Of Available For Sale Securities [Abstract]
Proceeds	101	136	351	386
Realized gains	4	4	14	10
Realized losses	2	4	5	9
PEF [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	662		662		530
Unrealized Losses	8		8		11
Unrealized Gains	205		205		157
Fair Value Of Available For Sale Debt Securities By Contractual Maturity [Abstract]
Due in one year or less	2		2
Due after one through five years	18		18
Due after five through 10 years	55		55
Due after 10 years	82		82
Total	157		157
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	47		47
Available-for-sale securities, continuous unrealized loss position, 12 months or longer, aggregate losses	4		4
Available-for-sale securities, continuous unrealized loss position, less than twelve months, aggregate losses	4		4
Sales Of Available For Sale Securities [Abstract]
Proceeds	173	926	443	3,861
Realized gains	4	5	9	14
Realized losses	4	7	7	11
Ndtf [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	1,844		1,844		1,630
Unrealized Losses	23		23		31
Unrealized Gains	573		573		444
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	117		117		136
Available-for-sale securities, continuous unrealized loss position, 12 months or longer, aggregate losses	14		14		12
Available-for-sale securities, continuous unrealized loss position, less than twelve months, aggregate losses	9		9		19
Ndtf [Member] | PEC [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	1,223		1,223		1,101
Unrealized Losses	15		15		20
Unrealized Gains	368		368		287
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	74		74		98
Available-for-sale securities, continuous unrealized loss position, 12 months or longer, aggregate losses	10		10		10
Available-for-sale securities, continuous unrealized loss position, less than twelve months, aggregate losses	5		5		10
Ndtf [Member] | PEF [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	621		621		529
Unrealized Losses	8		8		11
Unrealized Gains	205		205		157
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	43		43		38
Available-for-sale securities, continuous unrealized loss position, 12 months or longer, aggregate losses	4		4		2
Available-for-sale securities, continuous unrealized loss position, less than twelve months, aggregate losses	4		4		9
Equity Securities [Member] | Ndtf [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	1,226		1,226		1,062
Unrealized Losses	21		21		29
Unrealized Gains	534		534		412
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	89		89		112
Available-for-sale securities, continuous unrealized loss position, 12 months or longer, aggregate losses	13		13		10
Available-for-sale securities, continuous unrealized loss position, less than twelve months, aggregate losses	8		8		19
Equity Securities [Member] | Ndtf [Member] | PEC [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	797		797		690
Unrealized Losses	15		15		20
Unrealized Gains	340		340		262
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	56		56		69
Available-for-sale securities, continuous unrealized loss position, 12 months or longer, aggregate losses	10		10		10
Available-for-sale securities, continuous unrealized loss position, less than twelve months, aggregate losses	5		5		10
Equity Securities [Member] | Ndtf [Member] | PEF [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	429		429		372
Unrealized Losses	6		6		9
Unrealized Gains	194		194		150
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	33		33		43
Available-for-sale securities, continuous unrealized loss position, 12 months or longer, aggregate losses	3		3
Available-for-sale securities, continuous unrealized loss position, less than twelve months, aggregate losses	3		3		9
Corporate Debt Securities [Member] | Ndtf [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	85		85		86
Unrealized Gains	9		9		6
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	3		3		20
Corporate Debt Securities [Member] | Ndtf [Member] | PEC [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	75		75		69
Unrealized Gains	8		8		5
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	2		2		10
Corporate Debt Securities [Member] | Ndtf [Member] | PEF [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	10		10		17
Unrealized Gains	1		1		1
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value					10
Municipal Bonds [Member] | Ndtf [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	134		134		127
Unrealized Losses	1		1		2
Unrealized Gains	10		10		7
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	14		14		21
Available-for-sale securities, continuous unrealized loss position, 12 months or longer, aggregate losses	1		1		2
Municipal Bonds [Member] | Ndtf [Member] | PEC [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	61		61		55
Unrealized Gains	4		4		3
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	5		5		8
Municipal Bonds [Member] | Ndtf [Member] | PEF [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	73		73		72
Unrealized Losses	1		1		2
Unrealized Gains	6		6		4
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	9		9		13
Available-for-sale securities, continuous unrealized loss position, 12 months or longer, aggregate losses	1		1		2
Municipal Bonds [Member] | Other Classification [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	39		39
Municipal Bonds [Member] | Other Classification [Member] | PEF [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	39		39
U.S. Government Bonds [Member] | Ndtf [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	295		295		268
Unrealized Gains	17		17		18
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	10		10		(23)
U.S. Government Bonds [Member] | Ndtf [Member] | PEC [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	230		230		225
Unrealized Gains	15		15		16
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	11		11		9
U.S. Government Bonds [Member] | Ndtf [Member] | PEF [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	65		65		43
Unrealized Gains	2		2		2
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value					(32)
Other [Member] | Ndtf [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	104		104		87
Unrealized Losses	1		1
Unrealized Gains	3		3		1
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	1		1		6
Available-for-sale securities, continuous unrealized loss position, less than twelve months, aggregate losses	1		1
Other [Member] | Ndtf [Member] | PEC [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	60		60		62
Unrealized Gains	1		1		1
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value					2
Other [Member] | Ndtf [Member] | PEF [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	44		44		25
Unrealized Losses	1		1
Unrealized Gains	2		2
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	1		1		4
Available-for-sale securities, continuous unrealized loss position, less than twelve months, aggregate losses	1		1
Other [Member] | Other Classification [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	21		21		20
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	4		4
Other [Member] | Other Classification [Member] | PEC [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	6		6		6
Other [Member] | Other Classification [Member] | PEF [Member]
Schedule Of Available For Sale Securities [Abstract]
Fair Value	2		2		1
Available-for-sale Securities, Continuous Unrealized Loss Position [Abstract]
Available-for-sale securities, continuous unrealized loss position, fair value	$ 4		$ 4

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Environmental Matters (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	$ 23		$ 35
Amount accrued for environmental loss contingencies	16		7
Expenditures for environmental loss contingencies	(7)		(17)
Ending Balance	32	[1]	25	[1]
Maximum [Member]
Accrual for Environmental Loss Contingencies [Roll Forward]
Cost of new control equipment estimate	320
Minimum [Member]
Accrual for Environmental Loss Contingencies [Roll Forward]
Cost of new control equipment estimate	150
PEC [Member]
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	11		12
Amount accrued for environmental loss contingencies	4		0
Expenditures for environmental loss contingencies	(2)		(1)
Ending Balance	13	[2]	11	[2]
PEC [Member] | MGP Site [Member]
Accrual for Environmental Loss Contingencies [Roll Forward]
Amount accrued for environmental loss contingencies	7
PEC [Member] | MGP Site [Member] | Maximum [Member]
Accrual for Environmental Loss Contingencies [Roll Forward]
Site contingency, loss exposure in excess of accrual, high estimate	25
PEF [Member]
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	12		23
Amount accrued for environmental loss contingencies	12		7
Expenditures for environmental loss contingencies	(5)		(16)
Ending Balance	19	[1]	14	[1]
Cost of new control equipment estimate	1,000
PEF [Member] | Orlando MGP OU1 [Member]
Accrual for Environmental Loss Contingencies [Roll Forward]
Amount accrued for environmental loss contingencies	9
Site contingency, loss exposure in excess of accrual, high estimate	$ 8

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

[2] Expected to be paid out over one to ten years.

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2012

Related party transactions [Line Items]

Schedule of related party transactions

		Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
PROGRESS ENERGY
Corporate governance and shared services provided by Duke Energy(a)		$	31	$	0	$	31	$	0
Corporate governance and shared services provided to Duke Energy(b)			30		0		30		0
JDA revenues(c)			37		0		37		0
JDA expenses(d)			8		0		8		0
Indemnification coverage expenses(e)			7		0		7		0
PEC
Corporate governance and shared service expenses(a)		$	72	$	48	$	183	$	155
JDA revenues(c)			37		0		37		0
JDA expenses(d)			8		0		8		0
Indemnification coverage expenses(e)			3		0		3		0
PEF
Corporate governance and shared service expenses(a)		$	52	$	41	$	136	$	122
Indemnification coverage expenses(e)			4		0		4		0
(a)	Progress Energy Registrants are charged their proportionate share of corporate governance and other costs by PESC (only applicable to PEC and PEF) and an unconsolidated affiliate that is a consolidated affiliate of Duke Energy. Corporate governance and other shared costs are primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These expenses are recorded in O&M in the Statements of Operations and Comprehensive Income.
(b)	PESC charges a proportionate share of corporate governance and other costs to unconsolidated affiliates that are consolidated affiliates of Duke Energy. Corporate governance and other shared costs are primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These charges are recorded as an offset to O&M in the Statements of Operations and Comprehensive Income.
(c)	Effective with the consummation of the merger, PEC and Duke Energy Carolinas began to participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customers' rates (See Note 4). The revenues from the sale of power to Duke Energy Carolinas are recorded in regulated electric revenues in the Consolidated Statements of Operations and Comprehensive Income.
(d)	Effective with the consummation of the merger, PEC and Duke Energy Carolinas began to participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customers' rates (See Note 4). The expenses from the purchase of power from Duke Energy Carolinas are recorded in fuel used in electric generation and purchased power in the Consolidated Statements of Operations and Comprehensive Income.
(e)	Effective with the consummation of the merger, Progress Energy Registrants incur expenses related to certain indemnification coverages through Bison, Duke Energy's wholly owned captive insurance subsidiary. These expenses are recorded in O&M in the Statements of Operations and Comprehensive Income.

PEC [Member]

Related party transactions [Line Items]

Schedule of related party transactions

		Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
PROGRESS ENERGY
Corporate governance and shared services provided by Duke Energy(a)		$	31	$	0	$	31	$	0
Corporate governance and shared services provided to Duke Energy(b)			30		0		30		0
JDA revenues(c)			37		0		37		0
JDA expenses(d)			8		0		8		0
Indemnification coverage expenses(e)			7		0		7		0
PEC
Corporate governance and shared service expenses(a)		$	72	$	48	$	183	$	155
JDA revenues(c)			37		0		37		0
JDA expenses(d)			8		0		8		0
Indemnification coverage expenses(e)			3		0		3		0
PEF
Corporate governance and shared service expenses(a)		$	52	$	41	$	136	$	122
Indemnification coverage expenses(e)			4		0		4		0
(a)	Progress Energy Registrants are charged their proportionate share of corporate governance and other costs by PESC (only applicable to PEC and PEF) and an unconsolidated affiliate that is a consolidated affiliate of Duke Energy. Corporate governance and other shared costs are primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These expenses are recorded in O&M in the Statements of Operations and Comprehensive Income.
(b)	PESC charges a proportionate share of corporate governance and other costs to unconsolidated affiliates that are consolidated affiliates of Duke Energy. Corporate governance and other shared costs are primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These charges are recorded as an offset to O&M in the Statements of Operations and Comprehensive Income.
(c)	Effective with the consummation of the merger, PEC and Duke Energy Carolinas began to participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customers' rates (See Note 4). The revenues from the sale of power to Duke Energy Carolinas are recorded in regulated electric revenues in the Consolidated Statements of Operations and Comprehensive Income.
(d)	Effective with the consummation of the merger, PEC and Duke Energy Carolinas began to participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customers' rates (See Note 4). The expenses from the purchase of power from Duke Energy Carolinas are recorded in fuel used in electric generation and purchased power in the Consolidated Statements of Operations and Comprehensive Income.
(e)	Effective with the consummation of the merger, Progress Energy Registrants incur expenses related to certain indemnification coverages through Bison, Duke Energy's wholly owned captive insurance subsidiary. These expenses are recorded in O&M in the Statements of Operations and Comprehensive Income.

PEF [Member]

Related party transactions [Line Items]

Schedule of related party transactions

		Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
PROGRESS ENERGY
Corporate governance and shared services provided by Duke Energy(a)		$	31	$	0	$	31	$	0
Corporate governance and shared services provided to Duke Energy(b)			30		0		30		0
JDA revenues(c)			37		0		37		0
JDA expenses(d)			8		0		8		0
Indemnification coverage expenses(e)			7		0		7		0
PEC
Corporate governance and shared service expenses(a)		$	72	$	48	$	183	$	155
JDA revenues(c)			37		0		37		0
JDA expenses(d)			8		0		8		0
Indemnification coverage expenses(e)			3		0		3		0
PEF
Corporate governance and shared service expenses(a)		$	52	$	41	$	136	$	122
Indemnification coverage expenses(e)			4		0		4		0
(a)	Progress Energy Registrants are charged their proportionate share of corporate governance and other costs by PESC (only applicable to PEC and PEF) and an unconsolidated affiliate that is a consolidated affiliate of Duke Energy. Corporate governance and other shared costs are primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These expenses are recorded in O&M in the Statements of Operations and Comprehensive Income.
(b)	PESC charges a proportionate share of corporate governance and other costs to unconsolidated affiliates that are consolidated affiliates of Duke Energy. Corporate governance and other shared costs are primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These charges are recorded as an offset to O&M in the Statements of Operations and Comprehensive Income.
(c)	Effective with the consummation of the merger, PEC and Duke Energy Carolinas began to participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customers' rates (See Note 4). The revenues from the sale of power to Duke Energy Carolinas are recorded in regulated electric revenues in the Consolidated Statements of Operations and Comprehensive Income.
(d)	Effective with the consummation of the merger, PEC and Duke Energy Carolinas began to participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customers' rates (See Note 4). The expenses from the purchase of power from Duke Energy Carolinas are recorded in fuel used in electric generation and purchased power in the Consolidated Statements of Operations and Comprehensive Income.
(e)	Effective with the consummation of the merger, Progress Energy Registrants incur expenses related to certain indemnification coverages through Bison, Duke Energy's wholly owned captive insurance subsidiary. These expenses are recorded in O&M in the Statements of Operations and Comprehensive Income.

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Benefit Plans - Costs of Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011
Pension Benefits [Member]
Defined benefit plan disclosure
Service cost	$ 16		$ 13		$ 47		$ 39
Interest cost on projected benefit obligation	32		33		95		98
Expected return on plan assets	(48)		(45)		(141)		(136)
Amortization of prior service cost (credit)	2	[1]	2	[1]	7	[1]	5	[1]
Amortization of net transition liability	0	[1]	0	[1]	0	[1]	0	[1]
Amortization of actuarial loss	24	[1]	15	[1]	69	[1]	47	[1]
Special termination costs	0		0		0		0
Other	1		0		1		0
Net periodic cost	27		18		78		53
Defined benefit plan, weighted average assumptions used in calculating net periodic benefit cost
Discount rate					4.60%
Rate of increase in future compensation
Bargaining					4.00%
Expected long-term rate of return on plan assets					8.00%
Pension Benefits [Member] | PEC [Member]
Defined benefit plan disclosure
Service cost	6		5		19		15
Interest cost on projected benefit obligation	15		15		43		46
Expected return on plan assets	(25)		(23)		(72)		(68)
Amortization of prior service cost (credit)	2		1		6		4
Amortization of net transition liability	0		0		0		0
Amortization of actuarial loss	9		7		28		19
Special termination costs	0		0		0		0
Other	1		0		1		0
Net periodic cost	8		5		25		16
Pension Benefits [Member] | PEF [Member]
Defined benefit plan disclosure
Service cost	8		6		22		18
Interest cost on projected benefit obligation	14		14		42		43
Expected return on plan assets	(21)		(19)		(61)		(59)
Amortization of net transition liability	0		0		0		0
Amortization of actuarial loss	13		8		36		25
Special termination costs	0		0		0		0
Net periodic cost	14		9		39		27
Nonqualified Pension Plans [Member]
Defined benefit plan disclosure
Service cost	0		0		1		1
Interest cost on projected benefit obligation	2		2		6		7
Expected return on plan assets	0		0		0		0
Amortization of prior service cost (credit)	0	[1]	0	[1]	0	[1]	0	[1]
Amortization of net transition liability	0	[1]	0	[1]	0	[1]	0	[1]
Amortization of actuarial loss	1	[1]	1	[1]	3	[1]	2	[1]
Special termination costs	0		0		0		0
Other	0		0		0		0
Net periodic cost	3		3		10		10
Defined benefit plan, weighted average assumptions used in calculating net periodic benefit cost
Discount rate					4.60%
Rate of increase in future compensation
Supplementary plans					5.25%
Nonqualified Pension Plans [Member] | PEC [Member]
Defined benefit plan disclosure
Service cost	0		0		1		1
Interest cost on projected benefit obligation	1		1		1		1
Expected return on plan assets	0		0		0		0
Amortization of prior service cost (credit)	0		0		0		0
Amortization of net transition liability	0		0		0		0
Amortization of actuarial loss	0		0		1		0
Special termination costs	0		0		0		0
Other	0		0		0		0
Net periodic cost	1		1		3		2
Nonqualified Pension Plans [Member] | PEF [Member]
Defined benefit plan disclosure
Service cost	0		0		0		0
Interest cost on projected benefit obligation	1		1		2		2
Expected return on plan assets	0		0		0		0
Amortization of net transition liability	0		0		0		0
Amortization of actuarial loss	0		0		0		0
Special termination costs	0		0		0		0
Net periodic cost	1		1		2		2
Other Postretirement Benefits [Member]
Defined benefit plan disclosure
Service cost	5		3		12		8
Interest cost on projected benefit obligation	11		10		32		30
Expected return on plan assets	0		0		(1)		(1)
Amortization of prior service cost (credit)	0	[1]	0	[1]	0	[1]	0	[1]
Amortization of net transition liability	1	[1]	1	[1]	3	[1]	4	[1]
Amortization of actuarial loss	10	[1]	3	[1]	25	[1]	9	[1]
Special termination costs	5		0		5		0
Other	0		0		0		0
Net periodic cost	32		17		76		50
Defined benefit plan, weighted average assumptions used in calculating net periodic benefit cost
Discount rate					4.60%
Other Postretirement Benefits [Member] | PEC [Member]
Defined benefit plan disclosure
Service cost	2		2		6		3
Interest cost on projected benefit obligation	6		5		17		15
Expected return on plan assets	0		0		0		0
Amortization of prior service cost (credit)	0		0		0		0
Amortization of net transition liability	0		0		0		1
Amortization of actuarial loss	6		1		14		4
Special termination costs	2		0		2		0
Other	0		0		0		0
Net periodic cost	16		8		39		23
Other Postretirement Benefits [Member] | PEF [Member]
Defined benefit plan disclosure
Service cost	2		1		5		3
Interest cost on projected benefit obligation	4		4		13		13
Expected return on plan assets	0		0		(1)		(1)
Amortization of net transition liability	1		1		2		3
Amortization of actuarial loss	3		2		9		6
Special termination costs	1		0		1		0
Net periodic cost	$ 11		$ 8		$ 29		$ 24

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

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Debt and Credit Facilities - Covenants and Default Provisions (Details)	Sep. 30, 2012
PEC [Member]
Collateralized obligations
Ratio of indebtedness to net capital	0.65
PEF [Member]
Collateralized obligations
Ratio of indebtedness to net capital	0.65

XML

Financial Information by Business Segment

9 Months Ended

Sep. 30, 2012

Financial Information By Business Segment Disclosure [Abstract]

Financial Information by Business Segment

3.FINANCIAL INFORMATION BY BUSINESS SEGMENT

PROGRESS ENERGY

Effective with the consummation of the merger with Duke Energy on July 2, 2012, our reportable segments changed based on the financial information the chief decision maker evaluates for the allocation of resources and assessing performance. Our sole reportable segment is now Franchised Electric, which is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. 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 segment, Other now presents the remainder of our operations, including the Parent and PESC and other miscellaneous nonregulated businesses,as well as costs to achieve the merger with Duke Energy.Also effective with the consummation of the merger, management began evaluating segment performance based on Segment Income. Segment Income is defined as income from continuing operations net of income attributable to noncontrolling interests.

Prior periods' segment information has been recast to conform to the current year presentation. None of these segment changes impact the Progress Energy Registrants' reported consolidated revenues or net income.

Products and services are sold between the affiliate companies of Duke Energy at cost.

BUSINESS SEGMENT DATA
(in millions)			Unaffiliated Revenues		Affiliated Revenues		Total Revenues		Segment Income/ Consolidated Net Income(a)
Three months ended September 30, 2012
Franchised Electric			$	2,747	$	39	$	2,786	$	333
	Total reportable segment			2,747		39		2,786		333
Other				3		0		3		(181)(b)
Eliminations				0		(1)		(1)		0
Add back of noncontrolling interest component				0		0		0		2
Income from discontinued operations, net of tax				0		0		0		3
	Total consolidated		$	2,750	$	38	$	2,788	$	157
Three months ended September 30, 2011
Franchised Electric			$	2,750	$	0	$	2,750	$	408
	Total reportable segment			2,750		0		2,750		408
Other				3		0		3		(117)(b)
Add back of noncontrolling interest component				0		0		0		2
	Total consolidated		$	2,753	$	0	$	2,753	$	293
(in millions)			Unaffiliated Revenues		Affiliated Revenues		Total Revenues		Segment Income/ Consolidated Net Income(a)
Nine months ended September 30, 2012
Franchised Electric			$	7,132	$	40	$	7,172	$	636
	Total reportable segment			7,132		40		7,172		636
Other				8		0		8		(278)(b)
Eliminations				0		(2)		(2)		0
Add back of noncontrolling interest component				0		0		0		5
Income from discontinued operations, net of tax				0		0		0		10
	Total consolidated		$	7,140	$	38	$	7,178	$	373
Nine months ended September 30, 2011
Franchised Electric			$	7,188	$	1	$	7,189	$	874
	Total reportable segment			7,188		1		7,189		874
Other				8		0		8		(219)(b)
Eliminations				0		(1)		(1)		0
Add back of noncontrolling interest component				0		0		0		5
Loss from discontinued operations, net of tax				0		0		0		(4)
	Total consolidated		$	7,196	$	0	$	7,196	$	656
(a)		Segment income excludes noncontrolling interests and results of entities classified as discontinued operations.
(b)		Segment income includes after-tax costs to achieve the merger with Duke Energy of $132 million and $149 million for the three and nine months ended September 30, 2012, respectively, and $9 million and $27 million for the three and nine months ended September 30, 2011, respectively.

SEGMENT ASSETS
Segment assets in the following table exclude all intercompany assets between the Progress Energy Registrants.
(in millions)			September 30, 2012		December 31, 2011
Franchised Electric			$	36,135	$	34,166
	Total reportable segment			36,135		34,166
Other				549		765
Reclassifications(a)				(33)		0
	Total consolidated assets		$	36,651	$	34,931
(a)		Primarily represents reclassification of federal tax balances in consolidation.

PEC and PEF

PEC and PEF each have one reportable operating segment, Franchised Electric, which generates, transmits, distributes and sells electricity in portions of North Carolina and South Carolina and in portions of Florida, respectively.

The remainder of PEC's and PEF's operations are classified as Other. While not considered reportable segments for either company, PEC's and PEF's Other consists ofeach respective company's costs to achieve the merger with Duke Energy. PEC's Other had a net loss of $109 million and $5 million for the three months ended September 30, 2012 and 2011, respectively, and $119 million and $14 million for the nine months ended September 30, 2012 and 2011, respectively. PEF's Other had a net loss of $23 million and $4 million for the three months ended September 30, 2012 and 2011, respectively, and $30 million and $13 million for the nine months ended September 30, 2012 and 2011, respectively.

The Franchised Electric operating segments own substantially all of PEC's and PEF's assets at September 30, 2012 and December 31, 2011.

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Purchase Obligations (Details) (PEC [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Purchase Obligations [Line Items]
2012	$ 20
Contractual obligations one to three years	103
Contractual obligations three to five years	103
Thereafter	804
Unrecorded unconditional purchase obligation, total	1,030
Conditional Agreement [Member]
Purchase Obligations [Line Items]
Unrecorded unconditional purchase obligation, total	1,510
Long term contract amount, classified as capital lease	$ 380

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Environmental Matters (Tables)

9 Months Ended

Sep. 30, 2012

Enviromental Matters Disclosure [Line Items]

Environmental remediation accruals [Tables]

PROGRESS ENERGY
(in millions)		Total
Balance, December 31, 2011		$	23
Amount accrued for environmental loss contingencies			16
Expenditures for environmental loss contingencies			(7)
Balance, September 30, 2012(a)		$	32
Balance, December 31, 2010		$	35
Amount accrued for environmental loss contingencies			7
Expenditures for environmental loss contingencies			(17)
Balance, September 30, 2011(a)		$	25
(a)	Expected to be paid out over one to 12 years.

PEC [Member]

Enviromental Matters Disclosure [Line Items]

Environmental remediation accruals [Tables]

PEC
(in millions)		Total
Balance, December 31, 2011		$	11
Amount accrued for environmental loss contingencies			4
Expenditures for environmental loss contingencies			(2)
Balance, September 30, 2012(a)		$	13
Balance, December 31, 2010		$	12
Amount accrued for environmental loss contingencies			-
Expenditures for environmental loss contingencies			(1)
Balance, September 30, 2011(a)		$	11
(a)	Expected to be paid out over one to ten years.

PEF [Member]

Enviromental Matters Disclosure [Line Items]

Environmental remediation accruals [Tables]

PEF
(in millions)		Total
Balance, December 31, 2011		$	12
Amount accrued for environmental loss contingencies			12
Expenditures for environmental loss contingencies			(5)
Balance, September 30, 2012(a)		$	19
Balance, December 31, 2010		$	23
Amount accrued for environmental loss contingencies			7
Expenditures for environmental loss contingencies			(16)
Balance, September 30, 2011(a)		$	14
(a)	Expected to be paid out over one to 12 years.

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Regulatory Matters (Tables)

36 Months Ended

Sep. 30, 2012

Regulatory Matters Disclosure [Line Items]

Schedule of extended outage repair and replacement power costs and recoveries

(in millions)			Replacement Power Costs		Repair Costs
Spent to date			$	573	$	324
NEIL proceeds received to date				(162)		(143)
	Balance for recovery(a)		$	411	$	181
(a)		See discussion below of PEF's ability to recover prudently incurred fuel and purchased power costs and CR3 repair costs.

PEF [Member]

Regulatory Matters Disclosure [Line Items]

Schedule of extended outage repair and replacement power costs and recoveries

(in millions)			Replacement Power Costs		Repair Costs
Spent to date			$	573	$	324
NEIL proceeds received to date				(162)		(143)
	Balance for recovery(a)		$	411	$	181
(a)		See discussion below of PEF's ability to recover prudently incurred fuel and purchased power costs and CR3 repair costs.

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Severance (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2012
Severance [Line Items]
Number of employees that accepted the termination benefits		650
Severance charges	$ 66	$ 66
Restructuring Liability, Beginning Balance		5
Provision/Adjustments		53
Cash Reductions		(15)
Restructuring Liability, Ending Balance	43	43
Duke Energy [Member]
Severance [Line Items]
Number of employees that accepted the termination benefits		1,100
Minimum [Member] | Duke Energy [Member]
Severance [Line Items]
Estimated future severance costs		80
Maximum [Member] | Duke Energy [Member]
Severance [Line Items]
Estimated future severance costs		110
PEC [Member]
Severance [Line Items]
Severance charges	42	42
Restructuring Liability, Beginning Balance		5
Provision/Adjustments		26
Cash Reductions		(7)
Restructuring Liability, Ending Balance	24	24
PEF [Member]
Severance [Line Items]
Severance charges	24	24
Restructuring Liability, Beginning Balance		0
Provision/Adjustments		10
Cash Reductions		(3)
Restructuring Liability, Ending Balance	$ 7	$ 7

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Guarantees (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011
Guarantor Obligations [Line Items]
Guarantee obligations maximum exposure	$ 219
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	28	63
Guarantee Obligations Related Party	300
PEF [Member]
Guarantor Obligations [Line Items]
Guarantee obligations maximum exposure	45
Guarantee obligations current carrying value	$ 20	$ 37

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Risk Management Activities and Derivative Transactions (Tables)

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2012

Sep. 30, 2012

Dec. 31, 2011

Risk Management Activities And Derivative Transactions Disclosure [Line Items]

Notional amounts of derivative instruments related to interest rate risk

Notional Amounts of Derivative Instruments Related to Interest Rate
		Progress Energy		PEC		PEF
(in millions)		September 30, 2012
Undesignated contracts	$	100	$	50	$	50

(in millions)		December 31, 2011
Cash flow hedges	$	500	$	250	$	50

Underlying notional amounts for commodity derivative instruments accounted for at fair value

Underlying Notional Amounts for Commodity Derivative Instruments Accounted for At Fair Value
		Progress Energy	PEC	PEF
		September 30, 2012
Commodity contracts
	Electricity-energy (Gigawatt-hours)(a)	1,850	1,850	0
	Electricity-capacity (Gigawatt-months)(a)	5	5	0
	Natural gas (millions of decatherms)	297	89	208
	Fuel oil (millions of gallons)	6	0	6

		December 31, 2011
Commodity contracts
	Natural gas (millions of decatherms)	347	103	244
	Fuel oil (millions of gallons)	10	0	10

Location and fair value amounts of derivatives reflected in the unaudited condensed balance sheets

Location and Fair Value of Derivatives Reflected in the Balance Sheets
				Progress Energy				PEC				PEF
Instrument / Balance Sheet location				September 30, 2012
(in millions)			Asset		Liability		Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity contracts
	Derivative liabilities, current				$	1			$	-			$	1
		Total derivatives designated as hedging instruments				1				0				1
Derivatives not designated as hedging instruments
Commodity contracts(a)
	Investments and other assets: other		$	1		0	$	0		0	$	1		0
	Derivative liabilities, current			8		220		3		74		5		146
	Deferred credits and other liabilities: other			14		209		2		74		12		135
Interest rate contracts(a)
	Derivative liabilities, current					23				11				12
CVOs(b)
	Deferred credits and other liabilities: other					4				0				0
		Total derivatives not designated as hedging instruments		23		456		5		159		18		293
		Total derivatives	$	23	$	457	$	5	$	159	$	18	$	294
(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 Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (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.

				Progress Energy				PEC				PEF
Instrument / Balance Sheet location			December 31, 2011
(in millions)			Asset		Liability		Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity contracts
	Derivative liabilities, current				$	2			$	-			$	2
	Deferred credits and other liabilities: other					1				-				1
Interest rate contracts
	Derivative liabilities, current					76				38				0
	Deferred credits and other liabilities: other					17				9				8
		Total derivatives designated as hedging instruments				96				47				11
Derivatives not designated as hedging instruments
Commodity contracts(a)
	Derivative liabilities, current		$	5		357	$	0		91	$	5		266
	Deferred credits and other liabilities: other			0		332		0		110		0		222
CVOs(b)
	Current liabilities: other					14				-				-
		Total derivatives not designated as hedging instruments		5		703		0		201		5		488
		Total derivatives	$	5	$	799	$	0	$	248	$	5	$	499
(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. In 2011, we repurchased and continue to hold 80.1 million CVOs in a negotiated settlement agreement and subsequent tender offer.

Cash flow hedges - location and amount of pretax gains and losses in comprehensive income or income

Cash Flow Hedges - Location and Amount of Pre-Tax Gains and (Losses) Recognized in Comprehensive Income
				Progress Energy				PEC				PEF
			Three months ended September 30
(in millions)			2012		2011		2012		2011		2012		2011
Pre-tax gains (losses) recognized in OCI(a)
	Commodity contracts		$	1	$	(1)	$	0	$	0	$	1	$	(1)
	Interest rate contracts(b)			0		(111)		0		(58)		0		(27)
Total pre-tax gains (losses) recognized in OCI			$	1	$	(112)	$	0	$	(58)	$	1	$	(28)
Location of pre-tax gains (losses) reclassified from OCI into income(a)
	Interest rate contracts(b)
		Interest expense	$	(2)	$	(3)	$	0	$	(2)	$	0	$	0
Total pre-tax gains (losses) reclassified from OCI into income			$	(2)	$	(3)	$	0	$	(2)	$	0	$	0
Location of pre-tax gains (losses) recognized in income on derivatives(c)
	Interest rate contracts(b)
		Interest expense	$	0	$	(1)	$	0	$	(1)	$	0	$	0
Total pre-tax gains (losses) recognized in income on derivatives			$	0	$	(1)	$	0	$	(1)	$	0	$	0
(a)	Effective portion.
(b)	Amounts in AOCI 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.
(c)	Related to ineffective portion and amount excluded from effectiveness testing.

				Progress Energy				PEC				PEF
			Nine months ended September 30
(in millions)			2012		2011		2012		2011		2012		2011
Pre-tax gains (losses) recognized in OCI(a)
	Commodity contracts		$	1	$	(1)	$	0	$	0	$	1	$	(1)
	Interest rate contracts(b)			(11)		(134)		(7)		(67)		(2)		(35)
Total pre-tax gains (losses) recognized in OCI			$	(10)	$	(135)	$	(7)	$	(67)	$	(1)	$	(36)
Location of pre-tax gains (losses) reclassified from OCI into income(a)
	Interest rate contracts(b)
		Interest expense	$	(12)	$	(9)	$	(5)	$	(5)	$	(2)	$	0
Total pre-tax gains (losses) reclassified from OCI into income			$	(12)	$	(9)	$	(5)	$	(5)	$	(2)	$	0
Location of pre-tax gains (losses) recognized in income on derivatives(c)
	Interest rate contracts(b)
		Interest expense	$	0	$	(3)	$	0	$	(1)	$	0	$	0
Total pre-tax gains (losses) recognized in income on derivatives			$	0	$	(3)	$	0	$	(1)	$	0	$	0
(a)	Effective portion.
(b)	Amounts in AOCI 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.
(c)	Related to ineffective portion and amount excluded from effectiveness testing.

Undesignated contracts - location and amount of pretax gains and losses recognized in income as regulatory assets or liabilities

Undesignated Contracts - Location and Amount of Pre-Tax Gains and (Losses) Recognized in Income or as Regulatory Assets or Liabilities
				Progress Energy				PEC				PEF
				Three months ended September 30
(in millions)				2012	2011			2012	2011			2012	2011
Location of pre-tax gains and (losses) recognized in earnings
	Commodity contracts
		Regulated electric revenue	$	(9)	$	0	$	(9)	$	0	$	0	$	0
		Fuel used in electric generation and purchased power(a)		(135)		(91)		(35)		(20)		(100)		(71)
	Interest rate contracts
		Interest expense(b)		(4)		0		(3)		0		(1)		0
Total pre-tax gains (losses) recognized in earnings			$	(148)	$	(91)	$	(47)	$	(20)	$	(101)	$	(71)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities
	Commodity contracts(c)
		Regulatory asset	$	60	$	(157)	$	15	$	(42)	$	45	$	(115)
	Interest rate contracts(b)
		Regulatory asset		2		0		2		0		0		0
Total pre-tax gains (losses) recognized as regulatory assets or liabilities			$	62	$	(157)	$	17	$	(42)	$	45	$	(115)
Location of pre-tax gains and (losses) recognized in income on derivatives
	Fair value loss transition adjustment
		Regulated electric revenue	$	0	$	1	$	0	$	1	$	0	$	0
	CVOs
		Other income and expenses, net		(1)		(63)		0		0		0		0
Total pre-tax gains (losses) recognized in income on derivatives			$	(1)	$	(62)	$	0	$	1	$	0	$	0
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts in regulatory assets and liabilities related to terminated hedges are reclassified to earnings as the interest expense is recorded. The hedges will be amortized to interest expense over the term of the related debt.
(c)	Amounts are recorded in regulatory assets and liabilities in the Balance Sheets until derivatives are settled.

				Progress Energy				PEC				PEF
				Nine months ended September 30
(in millions)				2012	2011			2012	2011			2012	2011
Location of pre-tax gains and (losses) recognized in earnings
	Commodity contracts
		Regulated electric revenue	$	(9)	$	0	$	(9)	$	0	$	0	$	0
		Fuel used in electric generation and purchased power(a)		(395)		(219)		(100)		(42)		(295)		(177)
	Interest rate contracts
		Interest expense(b)		(4)		0		(3)		0		(1)		0
Total pre-tax gains (losses) recognized in earnings			$	(408)	$	(219)	$	(112)	$	(42)	$	(296)	$	(177)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities
	Commodity contracts(c)
		Regulatory asset	$	(108)	$	(201)	$	(34)	$	(55)	$	(74)	$	(146)
	Interest rate contracts(b)
		Regulatory asset		2		0		2		0		0		0
Total pre-tax gains (losses) recognized as regulatory assets or liabilities			$	(106)	$	(201)	$	(32)	$	(55)	$	(74)	$	(146)
Location of pre-tax gains and (losses) recognized in income on derivatives
	Commodity contracts
		Regulated electric revenue	$	2	$	1	$	2	$	1	$	0	$	0
	Fair value loss transition adjustment
		Regulated electric revenue		1		1		1		1		0		0
	CVOs
		Other income and expenses, net		7		(59)		0		0		0		0
Total pre-tax gains (losses) recognized in income on derivatives			$	10	$	(57)	$	3	$	2	$	0	$	0
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts in regulatory assets and liabilities related to terminated hedges are reclassified to earnings as the interest expense is recorded. The hedges will be amortized to interest expense over the term of the related debt.
(c)	Amounts are recorded in regulatory assets and liabilities in the Balance Sheets until derivatives are settled.

Information regarding derivative instruments that contain credit risk related contingent features

Information Regarding Derivative Instruments that Contain Credit-Risk-Related Contingent Features
	Progress Energy		PEC		PEF
(in millions)		September 30, 2012
Aggregate fair value amounts of derivative instruments in a net liability position	$	325	$	118	$	207
Collateral already posted		74		13		61
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered at the end of the reporting period		251		105		146

(in millions)		December 31, 2011
Aggregate fair value amounts of derivative instruments in a net liability position	$	489	$	152	$	337
Collateral already posted		147		24		123
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered at the end of the reporting period		342		128		214

Information regarding cash collateral under master netting arrangements

Information Regarding Cash Collateral under Master Netting Arrangements
		Progress Energy				PEC				PEF
	September 30, 2012
(in millions)	Receivables		Payables		Receivables		Payables		Receivables		Payables
Amounts offset against net derivative positions	$	73	$	0	$	13	$	0	$	60	$	0
Amounts not offset against net derivative positions		1		0		0		0		1		0

(in millions)	Receivables		Payables		Receivables		Payables		Receivables		Payables
Amounts offset against net derivative positions	$	140	$	0	$	23	$	0	$	117	$	0
Amounts not offset against net derivative positions		3		0		0		0		3		0

PEC [Member]

Risk Management Activities And Derivative Transactions Disclosure [Line Items]

Notional amounts of derivative instruments related to interest rate risk

Notional Amounts of Derivative Instruments Related to Interest Rate
		Progress Energy		PEC		PEF
(in millions)		September 30, 2012
Undesignated contracts	$	100	$	50	$	50

(in millions)		December 31, 2011
Cash flow hedges	$	500	$	250	$	50

Underlying notional amounts for commodity derivative instruments accounted for at fair value

Underlying Notional Amounts for Commodity Derivative Instruments Accounted for At Fair Value
		Progress Energy	PEC	PEF
		September 30, 2012
Commodity contracts
	Electricity-energy (Gigawatt-hours)(a)	1,850	1,850	0
	Electricity-capacity (Gigawatt-months)(a)	5	5	0
	Natural gas (millions of decatherms)	297	89	208
	Fuel oil (millions of gallons)	6	0	6

		December 31, 2011
Commodity contracts
	Natural gas (millions of decatherms)	347	103	244
	Fuel oil (millions of gallons)	10	0	10

Location and fair value amounts of derivatives reflected in the unaudited condensed balance sheets

Location and Fair Value of Derivatives Reflected in the Balance Sheets
				Progress Energy				PEC				PEF
Instrument / Balance Sheet location				September 30, 2012
(in millions)			Asset		Liability		Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity contracts
	Derivative liabilities, current				$	1			$	-			$	1
		Total derivatives designated as hedging instruments				1				0				1
Derivatives not designated as hedging instruments
Commodity contracts(a)
	Investments and other assets: other		$	1		0	$	0		0	$	1		0
	Derivative liabilities, current			8		220		3		74		5		146
	Deferred credits and other liabilities: other			14		209		2		74		12		135
Interest rate contracts(a)
	Derivative liabilities, current					23				11				12
CVOs(b)
	Deferred credits and other liabilities: other					4				0				0
		Total derivatives not designated as hedging instruments		23		456		5		159		18		293
		Total derivatives	$	23	$	457	$	5	$	159	$	18	$	294
(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 Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (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.

				Progress Energy				PEC				PEF
Instrument / Balance Sheet location			December 31, 2011
(in millions)			Asset		Liability		Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity contracts
	Derivative liabilities, current				$	2			$	-			$	2
	Deferred credits and other liabilities: other					1				-				1
Interest rate contracts
	Derivative liabilities, current					76				38				0
	Deferred credits and other liabilities: other					17				9				8
		Total derivatives designated as hedging instruments				96				47				11
Derivatives not designated as hedging instruments
Commodity contracts(a)
	Derivative liabilities, current		$	5		357	$	0		91	$	5		266
	Deferred credits and other liabilities: other			0		332		0		110		0		222
CVOs(b)
	Current liabilities: other					14				-				-
		Total derivatives not designated as hedging instruments		5		703		0		201		5		488
		Total derivatives	$	5	$	799	$	0	$	248	$	5	$	499
(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. In 2011, we repurchased and continue to hold 80.1 million CVOs in a negotiated settlement agreement and subsequent tender offer.

Cash flow hedges - location and amount of pretax gains and losses in comprehensive income or income

Cash Flow Hedges - Location and Amount of Pre-Tax Gains and (Losses) Recognized in Comprehensive Income
				Progress Energy				PEC				PEF
			Three months ended September 30
(in millions)			2012		2011		2012		2011		2012		2011
Pre-tax gains (losses) recognized in OCI(a)
	Commodity contracts		$	1	$	(1)	$	0	$	0	$	1	$	(1)
	Interest rate contracts(b)			0		(111)		0		(58)		0		(27)
Total pre-tax gains (losses) recognized in OCI			$	1	$	(112)	$	0	$	(58)	$	1	$	(28)
Location of pre-tax gains (losses) reclassified from OCI into income(a)
	Interest rate contracts(b)
		Interest expense	$	(2)	$	(3)	$	0	$	(2)	$	0	$	0
Total pre-tax gains (losses) reclassified from OCI into income			$	(2)	$	(3)	$	0	$	(2)	$	0	$	0
Location of pre-tax gains (losses) recognized in income on derivatives(c)
	Interest rate contracts(b)
		Interest expense	$	0	$	(1)	$	0	$	(1)	$	0	$	0
Total pre-tax gains (losses) recognized in income on derivatives			$	0	$	(1)	$	0	$	(1)	$	0	$	0
(a)	Effective portion.
(b)	Amounts in AOCI 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.
(c)	Related to ineffective portion and amount excluded from effectiveness testing.

				Progress Energy				PEC				PEF
			Nine months ended September 30
(in millions)			2012		2011		2012		2011		2012		2011
Pre-tax gains (losses) recognized in OCI(a)
	Commodity contracts		$	1	$	(1)	$	0	$	0	$	1	$	(1)
	Interest rate contracts(b)			(11)		(134)		(7)		(67)		(2)		(35)
Total pre-tax gains (losses) recognized in OCI			$	(10)	$	(135)	$	(7)	$	(67)	$	(1)	$	(36)
Location of pre-tax gains (losses) reclassified from OCI into income(a)
	Interest rate contracts(b)
		Interest expense	$	(12)	$	(9)	$	(5)	$	(5)	$	(2)	$	0
Total pre-tax gains (losses) reclassified from OCI into income			$	(12)	$	(9)	$	(5)	$	(5)	$	(2)	$	0
Location of pre-tax gains (losses) recognized in income on derivatives(c)
	Interest rate contracts(b)
		Interest expense	$	0	$	(3)	$	0	$	(1)	$	0	$	0
Total pre-tax gains (losses) recognized in income on derivatives			$	0	$	(3)	$	0	$	(1)	$	0	$	0
(a)	Effective portion.
(b)	Amounts in AOCI 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.
(c)	Related to ineffective portion and amount excluded from effectiveness testing.

Undesignated contracts - location and amount of pretax gains and losses recognized in income as regulatory assets or liabilities

Undesignated Contracts - Location and Amount of Pre-Tax Gains and (Losses) Recognized in Income or as Regulatory Assets or Liabilities
				Progress Energy				PEC				PEF
				Three months ended September 30
(in millions)				2012	2011			2012	2011			2012	2011
Location of pre-tax gains and (losses) recognized in earnings
	Commodity contracts
		Regulated electric revenue	$	(9)	$	0	$	(9)	$	0	$	0	$	0
		Fuel used in electric generation and purchased power(a)		(135)		(91)		(35)		(20)		(100)		(71)
	Interest rate contracts
		Interest expense(b)		(4)		0		(3)		0		(1)		0
Total pre-tax gains (losses) recognized in earnings			$	(148)	$	(91)	$	(47)	$	(20)	$	(101)	$	(71)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities
	Commodity contracts(c)
		Regulatory asset	$	60	$	(157)	$	15	$	(42)	$	45	$	(115)
	Interest rate contracts(b)
		Regulatory asset		2		0		2		0		0		0
Total pre-tax gains (losses) recognized as regulatory assets or liabilities			$	62	$	(157)	$	17	$	(42)	$	45	$	(115)
Location of pre-tax gains and (losses) recognized in income on derivatives
	Fair value loss transition adjustment
		Regulated electric revenue	$	0	$	1	$	0	$	1	$	0	$	0
	CVOs
		Other income and expenses, net		(1)		(63)		0		0		0		0
Total pre-tax gains (losses) recognized in income on derivatives			$	(1)	$	(62)	$	0	$	1	$	0	$	0
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts in regulatory assets and liabilities related to terminated hedges are reclassified to earnings as the interest expense is recorded. The hedges will be amortized to interest expense over the term of the related debt.
(c)	Amounts are recorded in regulatory assets and liabilities in the Balance Sheets until derivatives are settled.

				Progress Energy				PEC				PEF
				Nine months ended September 30
(in millions)				2012	2011			2012	2011			2012	2011
Location of pre-tax gains and (losses) recognized in earnings
	Commodity contracts
		Regulated electric revenue	$	(9)	$	0	$	(9)	$	0	$	0	$	0
		Fuel used in electric generation and purchased power(a)		(395)		(219)		(100)		(42)		(295)		(177)
	Interest rate contracts
		Interest expense(b)		(4)		0		(3)		0		(1)		0
Total pre-tax gains (losses) recognized in earnings			$	(408)	$	(219)	$	(112)	$	(42)	$	(296)	$	(177)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities
	Commodity contracts(c)
		Regulatory asset	$	(108)	$	(201)	$	(34)	$	(55)	$	(74)	$	(146)
	Interest rate contracts(b)
		Regulatory asset		2		0		2		0		0		0
Total pre-tax gains (losses) recognized as regulatory assets or liabilities			$	(106)	$	(201)	$	(32)	$	(55)	$	(74)	$	(146)
Location of pre-tax gains and (losses) recognized in income on derivatives
	Commodity contracts
		Regulated electric revenue	$	2	$	1	$	2	$	1	$	0	$	0
	Fair value loss transition adjustment
		Regulated electric revenue		1		1		1		1		0		0
	CVOs
		Other income and expenses, net		7		(59)		0		0		0		0
Total pre-tax gains (losses) recognized in income on derivatives			$	10	$	(57)	$	3	$	2	$	0	$	0
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts in regulatory assets and liabilities related to terminated hedges are reclassified to earnings as the interest expense is recorded. The hedges will be amortized to interest expense over the term of the related debt.
(c)	Amounts are recorded in regulatory assets and liabilities in the Balance Sheets until derivatives are settled.

Information regarding derivative instruments that contain credit risk related contingent features

Information Regarding Derivative Instruments that Contain Credit-Risk-Related Contingent Features
	Progress Energy		PEC		PEF
(in millions)		September 30, 2012
Aggregate fair value amounts of derivative instruments in a net liability position	$	325	$	118	$	207
Collateral already posted		74		13		61
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered at the end of the reporting period		251		105		146

(in millions)		December 31, 2011
Aggregate fair value amounts of derivative instruments in a net liability position	$	489	$	152	$	337
Collateral already posted		147		24		123
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered at the end of the reporting period		342		128		214

Information regarding cash collateral under master netting arrangements

Information Regarding Cash Collateral under Master Netting Arrangements
		Progress Energy				PEC				PEF
	September 30, 2012
(in millions)	Receivables		Payables		Receivables		Payables		Receivables		Payables
Amounts offset against net derivative positions	$	73	$	0	$	13	$	0	$	60	$	0
Amounts not offset against net derivative positions		1		0		0		0		1		0

(in millions)	Receivables		Payables		Receivables		Payables		Receivables		Payables
Amounts offset against net derivative positions	$	140	$	0	$	23	$	0	$	117	$	0
Amounts not offset against net derivative positions		3		0		0		0		3		0

PEF [Member]

Risk Management Activities And Derivative Transactions Disclosure [Line Items]

Notional amounts of derivative instruments related to interest rate risk

Notional Amounts of Derivative Instruments Related to Interest Rate
		Progress Energy		PEC		PEF
(in millions)		September 30, 2012
Undesignated contracts	$	100	$	50	$	50

(in millions)		December 31, 2011
Cash flow hedges	$	500	$	250	$	50

Underlying notional amounts for commodity derivative instruments accounted for at fair value

Underlying Notional Amounts for Commodity Derivative Instruments Accounted for At Fair Value
		Progress Energy	PEC	PEF
		September 30, 2012
Commodity contracts
	Electricity-energy (Gigawatt-hours)(a)	1,850	1,850	0
	Electricity-capacity (Gigawatt-months)(a)	5	5	0
	Natural gas (millions of decatherms)	297	89	208
	Fuel oil (millions of gallons)	6	0	6

		December 31, 2011
Commodity contracts
	Natural gas (millions of decatherms)	347	103	244
	Fuel oil (millions of gallons)	10	0	10

Location and fair value amounts of derivatives reflected in the unaudited condensed balance sheets

Location and Fair Value of Derivatives Reflected in the Balance Sheets
				Progress Energy				PEC				PEF
Instrument / Balance Sheet location				September 30, 2012
(in millions)			Asset		Liability		Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity contracts
	Derivative liabilities, current				$	1			$	-			$	1
		Total derivatives designated as hedging instruments				1				0				1
Derivatives not designated as hedging instruments
Commodity contracts(a)
	Investments and other assets: other		$	1		0	$	0		0	$	1		0
	Derivative liabilities, current			8		220		3		74		5		146
	Deferred credits and other liabilities: other			14		209		2		74		12		135
Interest rate contracts(a)
	Derivative liabilities, current					23				11				12
CVOs(b)
	Deferred credits and other liabilities: other					4				0				0
		Total derivatives not designated as hedging instruments		23		456		5		159		18		293
		Total derivatives	$	23	$	457	$	5	$	159	$	18	$	294
(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 Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (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.

				Progress Energy				PEC				PEF
Instrument / Balance Sheet location			December 31, 2011
(in millions)			Asset		Liability		Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity contracts
	Derivative liabilities, current				$	2			$	-			$	2
	Deferred credits and other liabilities: other					1				-				1
Interest rate contracts
	Derivative liabilities, current					76				38				0
	Deferred credits and other liabilities: other					17				9				8
		Total derivatives designated as hedging instruments				96				47				11
Derivatives not designated as hedging instruments
Commodity contracts(a)
	Derivative liabilities, current		$	5		357	$	0		91	$	5		266
	Deferred credits and other liabilities: other			0		332		0		110		0		222
CVOs(b)
	Current liabilities: other					14				-				-
		Total derivatives not designated as hedging instruments		5		703		0		201		5		488
		Total derivatives	$	5	$	799	$	0	$	248	$	5	$	499
(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. In 2011, we repurchased and continue to hold 80.1 million CVOs in a negotiated settlement agreement and subsequent tender offer.

Cash flow hedges - location and amount of pretax gains and losses in comprehensive income or income

Cash Flow Hedges - Location and Amount of Pre-Tax Gains and (Losses) Recognized in Comprehensive Income
				Progress Energy				PEC				PEF
			Three months ended September 30
(in millions)			2012		2011		2012		2011		2012		2011
Pre-tax gains (losses) recognized in OCI(a)
	Commodity contracts		$	1	$	(1)	$	0	$	0	$	1	$	(1)
	Interest rate contracts(b)			0		(111)		0		(58)		0		(27)
Total pre-tax gains (losses) recognized in OCI			$	1	$	(112)	$	0	$	(58)	$	1	$	(28)
Location of pre-tax gains (losses) reclassified from OCI into income(a)
	Interest rate contracts(b)
		Interest expense	$	(2)	$	(3)	$	0	$	(2)	$	0	$	0
Total pre-tax gains (losses) reclassified from OCI into income			$	(2)	$	(3)	$	0	$	(2)	$	0	$	0
Location of pre-tax gains (losses) recognized in income on derivatives(c)
	Interest rate contracts(b)
		Interest expense	$	0	$	(1)	$	0	$	(1)	$	0	$	0
Total pre-tax gains (losses) recognized in income on derivatives			$	0	$	(1)	$	0	$	(1)	$	0	$	0
(a)	Effective portion.
(b)	Amounts in AOCI 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.
(c)	Related to ineffective portion and amount excluded from effectiveness testing.

				Progress Energy				PEC				PEF
			Nine months ended September 30
(in millions)			2012		2011		2012		2011		2012		2011
Pre-tax gains (losses) recognized in OCI(a)
	Commodity contracts		$	1	$	(1)	$	0	$	0	$	1	$	(1)
	Interest rate contracts(b)			(11)		(134)		(7)		(67)		(2)		(35)
Total pre-tax gains (losses) recognized in OCI			$	(10)	$	(135)	$	(7)	$	(67)	$	(1)	$	(36)
Location of pre-tax gains (losses) reclassified from OCI into income(a)
	Interest rate contracts(b)
		Interest expense	$	(12)	$	(9)	$	(5)	$	(5)	$	(2)	$	0
Total pre-tax gains (losses) reclassified from OCI into income			$	(12)	$	(9)	$	(5)	$	(5)	$	(2)	$	0
Location of pre-tax gains (losses) recognized in income on derivatives(c)
	Interest rate contracts(b)
		Interest expense	$	0	$	(3)	$	0	$	(1)	$	0	$	0
Total pre-tax gains (losses) recognized in income on derivatives			$	0	$	(3)	$	0	$	(1)	$	0	$	0
(a)	Effective portion.
(b)	Amounts in AOCI 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.
(c)	Related to ineffective portion and amount excluded from effectiveness testing.

Undesignated contracts - location and amount of pretax gains and losses recognized in income as regulatory assets or liabilities

Undesignated Contracts - Location and Amount of Pre-Tax Gains and (Losses) Recognized in Income or as Regulatory Assets or Liabilities
				Progress Energy				PEC				PEF
				Three months ended September 30
(in millions)				2012	2011			2012	2011			2012	2011
Location of pre-tax gains and (losses) recognized in earnings
	Commodity contracts
		Regulated electric revenue	$	(9)	$	0	$	(9)	$	0	$	0	$	0
		Fuel used in electric generation and purchased power(a)		(135)		(91)		(35)		(20)		(100)		(71)
	Interest rate contracts
		Interest expense(b)		(4)		0		(3)		0		(1)		0
Total pre-tax gains (losses) recognized in earnings			$	(148)	$	(91)	$	(47)	$	(20)	$	(101)	$	(71)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities
	Commodity contracts(c)
		Regulatory asset	$	60	$	(157)	$	15	$	(42)	$	45	$	(115)
	Interest rate contracts(b)
		Regulatory asset		2		0		2		0		0		0
Total pre-tax gains (losses) recognized as regulatory assets or liabilities			$	62	$	(157)	$	17	$	(42)	$	45	$	(115)
Location of pre-tax gains and (losses) recognized in income on derivatives
	Fair value loss transition adjustment
		Regulated electric revenue	$	0	$	1	$	0	$	1	$	0	$	0
	CVOs
		Other income and expenses, net		(1)		(63)		0		0		0		0
Total pre-tax gains (losses) recognized in income on derivatives			$	(1)	$	(62)	$	0	$	1	$	0	$	0
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts in regulatory assets and liabilities related to terminated hedges are reclassified to earnings as the interest expense is recorded. The hedges will be amortized to interest expense over the term of the related debt.
(c)	Amounts are recorded in regulatory assets and liabilities in the Balance Sheets until derivatives are settled.

				Progress Energy				PEC				PEF
				Nine months ended September 30
(in millions)				2012	2011			2012	2011			2012	2011
Location of pre-tax gains and (losses) recognized in earnings
	Commodity contracts
		Regulated electric revenue	$	(9)	$	0	$	(9)	$	0	$	0	$	0
		Fuel used in electric generation and purchased power(a)		(395)		(219)		(100)		(42)		(295)		(177)
	Interest rate contracts
		Interest expense(b)		(4)		0		(3)		0		(1)		0
Total pre-tax gains (losses) recognized in earnings			$	(408)	$	(219)	$	(112)	$	(42)	$	(296)	$	(177)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities
	Commodity contracts(c)
		Regulatory asset	$	(108)	$	(201)	$	(34)	$	(55)	$	(74)	$	(146)
	Interest rate contracts(b)
		Regulatory asset		2		0		2		0		0		0
Total pre-tax gains (losses) recognized as regulatory assets or liabilities			$	(106)	$	(201)	$	(32)	$	(55)	$	(74)	$	(146)
Location of pre-tax gains and (losses) recognized in income on derivatives
	Commodity contracts
		Regulated electric revenue	$	2	$	1	$	2	$	1	$	0	$	0
	Fair value loss transition adjustment
		Regulated electric revenue		1		1		1		1		0		0
	CVOs
		Other income and expenses, net		7		(59)		0		0		0		0
Total pre-tax gains (losses) recognized in income on derivatives			$	10	$	(57)	$	3	$	2	$	0	$	0
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts in regulatory assets and liabilities related to terminated hedges are reclassified to earnings as the interest expense is recorded. The hedges will be amortized to interest expense over the term of the related debt.
(c)	Amounts are recorded in regulatory assets and liabilities in the Balance Sheets until derivatives are settled.

Information regarding derivative instruments that contain credit risk related contingent features

Information Regarding Derivative Instruments that Contain Credit-Risk-Related Contingent Features
	Progress Energy		PEC		PEF
(in millions)		September 30, 2012
Aggregate fair value amounts of derivative instruments in a net liability position	$	325	$	118	$	207
Collateral already posted		74		13		61
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered at the end of the reporting period		251		105		146

(in millions)		December 31, 2011
Aggregate fair value amounts of derivative instruments in a net liability position	$	489	$	152	$	337
Collateral already posted		147		24		123
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered at the end of the reporting period		342		128		214

Information regarding cash collateral under master netting arrangements

Information Regarding Cash Collateral under Master Netting Arrangements
		Progress Energy				PEC				PEF
	September 30, 2012
(in millions)	Receivables		Payables		Receivables		Payables		Receivables		Payables
Amounts offset against net derivative positions	$	73	$	0	$	13	$	0	$	60	$	0
Amounts not offset against net derivative positions		1		0		0		0		1		0

(in millions)	Receivables		Payables		Receivables		Payables		Receivables		Payables
Amounts offset against net derivative positions	$	140	$	0	$	23	$	0	$	117	$	0
Amounts not offset against net derivative positions		3		0		0		0		3		0

XML

Fair Value Disclosures (Tables)

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Line Items]

Fair value measurements- assets and liabilities

PROGRESS ENERGY
(in millions)			Total		Level 1		Level 2		Level 3
September 30, 2012
Nuclear decommissioning trust fund equity securities		$	1,226	$	1,220	$	6	$	-
Nuclear decommissioning trust fund debt securities and other			618		131		487		-
Other long-term available-for-sale debt securities and other(a)			60		21		39		-
Derivative assets(b)			1		-		1		-
	Total assets		1,905		1,372		533		-
Derivative liabilities(c)			(435)		-		(399)		(36)
	Net assets	$	1,470	$	1,372	$	134	$	(36)
(in millions)			Total		Level 1		Level 2		Level 3
December 31, 2011
Nuclear decommissioning trust fund equity securities		$	1,062	$	1,061	$	1	$	-
Nuclear decommissioning trust fund debt securities and other			585		87		498		-
Other long-term available-for-sale debt securities and other(a)			20		20		-		-
Derivative assets(b)			5		-		5		-
	Total assets		1,672		1,168		504		-
Derivative liabilities(c)			(799)		-		(775)		(24)
	Net assets	$	873	$	1,168	$	(271)	$	(24)
(a)	Included in Other within Investments and Other Assets in the Consolidated Balance Sheets.
(b)	Included in Prepayments and Other Current Assets within Current Assets and Other within Investments and Other Assets in the Consolidated Balance Sheets.
(c)	Included in Derivative Liabilities within Current Liabilities and Other within Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.

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

PROGRESS ENERGY
	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
Derivatives, net at beginning of period	$	30	$	37	$	24	$	36
Total pre-tax realized or unrealized gains included in earnings − regulated electric		(2)		-		(2)		-
Total (gains) losses, included in the consolidated Balance Sheet as regulatory asset or liability		(4)		6		2		7
Issuances		16		-		16		-
Settlements		(4)		-		(4)		-
Transfers into Level 3 − CVOs		-		74		-		74
Derivatives, net at end of period	$	36	$	117	$	36	$	117

Fair value inputs liabilities quantitative information

PROGRESS ENERGY
(in millions)	Fair Value		Valuation Technique	Unobservable Input		Range
September 30, 2012
Commodity natural gas hedges	$	27	Discounted cash flow	Forward natural gas curves - price per MMBtu	$	4.178	-	4.588
FERC mitigation power sale agreements		9	Discounted cash flow	Forward electricity curves - price per MWh		24.88	-	49.78

Fair value, by balance sheet grouping [Table Text Block]

		September 30, 2012				December 31, 2011
(in millions)		Book Value		Fair Value		Book Value		Fair Value
Progress Energy	$	13,776	$	16,160	$	13,152	$	15,518
PEC		4,838		5,352		4,206		4,735
PEF		4,672		5,646		4,681		5,633

PEC [Member]

Fair Value Disclosures [Line Items]

Fair value measurements- assets and liabilities

PEC
(in millions)			Total		Level 1		Level 2		Level 3
September 30, 2012
Nuclear decommissioning trust fund equity securities		$	797	$	797	$	-	$	-
Nuclear decommissioning trust fund debt securities and other			426		105		321		-
Other long-term available-for-sale debt securities and other(a)			6		6		-		-
	Total assets		1,229		908		321		-
Derivative liabilities(c)			(155)		-		(119)		(36)
	Net assets	$	1,074	$	908	$	202	$	(36)
(in millions)			Total		Level 1		Level 2		Level 3
December 31, 2011
Nuclear decommissioning trust fund equity securities		$	690	$	690	$	-	$	-
Nuclear decommissioning trust fund debt securities and other			398		81		317		-
Other long-term available-for-sale debt securities and other(a)			6		6		-		-
	Total assets		1,094		777		317		-
Derivative liabilities(c)			(248)		-		(224)		(24)
	Net assets	$	846	$	777	$	93	$	(24)
(a)	Included in Other within Investments and Other Assets in the Consolidated Balance Sheets.
(b)	Included in Prepayments and Other Current Assets within Current Assets and Other within Investments and Other Assets in the Consolidated Balance Sheets.
(c)	Included in Derivative Liabilities within Current Liabilities and Other within Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.

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

PEC
	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
Derivatives, net at beginning of period	$	28	$	37	$	24	$	36
Total pre-tax realized or unrealized gains included in earnings − regulated electric		(2)		-		(2)		-
Total (gains) losses, included in the consolidated Balance Sheet as regulatory asset or liability		(2)		5		2		6
Issuances		16		-		16		-
Settlements		(4)		-		(4)		-
Derivatives, net at end of period	$	36	$	42	$	36	$	42

Fair value inputs liabilities quantitative information

PEC
(in millions)	Fair Value		Valuation Technique	Unobservable Input		Range
September 30, 2012
Commodity natural gas hedges	$	27	Discounted cash flow	Forward natural gas curves - price per MMBtu	$	4.178	-	4.588
FERC mitigation power sale agreements		9	Discounted cash flow	Forward electricity curves - price per MWh		24.88	-	49.78

Fair value, by balance sheet grouping [Table Text Block]

		September 30, 2012				December 31, 2011
(in millions)		Book Value		Fair Value		Book Value		Fair Value
Progress Energy	$	13,776	$	16,160	$	13,152	$	15,518
PEC		4,838		5,352		4,206		4,735
PEF		4,672		5,646		4,681		5,633

PEF [Member]

Fair Value Disclosures [Line Items]

Fair value measurements- assets and liabilities

PEF
(in millions)			Total		Level 1		Level 2		Level 3
September 30, 2012
Nuclear decommissioning trust fund equity securities		$	429	$	423	$	6	$	-
Nuclear decommissioning trust fund debt securities and other			192		26		166		-
Other long-term available-for-sale debt securities and other(a)			41		2		39		-
Derivative assets(b)			1		-		1		-
	Total assets		663		451		212		-
Derivative liabilities(c)			(276)		-		(276)		-
	Net assets	$	387	$	451	$	(64)	$	-
(in millions)			Total		Level 1		Level 2		Level 3
December 31, 2011
Nuclear decommissioning trust fund equity securities		$	372	$	371	$	1	$	-
Nuclear decommissioning trust fund debt securities and other			187		6		181		-
Other long-term available-for-sale debt securities and other(a)			1		1		-		-
Derivative assets(b)			5		-		5		-
	Total assets		565		378		187		-
Derivative liabilities(c)			(499)		-		(499)		-
	Net assets	$	66	$	378	$	(312)	$	-
(a)	Included in Other within Investments and Other Assets in the Balance Sheets.
(b)	Included in Prepayments and Other Current Assets within Current Assets and Other within Investments and Other Assets in the Balance Sheets.
(c)	Included in Derivative Liabilities within Current Liabilities and Other within Deferred Credits and Other Liabilities in the Balance Sheets.

Fair value, by balance sheet grouping [Table Text Block]

		September 30, 2012				December 31, 2011
(in millions)		Book Value		Fair Value		Book Value		Fair Value
Progress Energy	$	13,776	$	16,160	$	13,152	$	15,518
PEC		4,838		5,352		4,206		4,735
PEF		4,672		5,646		4,681		5,633

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Merger and Sales of Other Assets

9 Months Ended

Sep. 30, 2012

Merger Agreement [Line Items]

Merger And Sales Of Other Assets [Text Block]

2.       MERGER AND SALES OF OTHER ASSETS

A.MERGER WITH DUKE ENERGY

On July 2, 2012, Progress Energy consummated the merger with Duke Energy, and became, and will continue as, a direct wholly owned subsidiary of Duke Energy. Under the terms of the merger agreement, each share of Progress Energy common stock was converted into 0.87083 shares of Duke Energy common stock as adjusted for the one-for-three reverse stock split of Duke Energy stock, effected in conjunction with, and immediately prior to, the merger. Each outstanding option to acquire, and each outstanding equity award relating to, one share of Progress Energy common stock was converted into an option to acquire, or an equity award relating to, 0.87083 shares of Duke Energy common stock. The terms and vesting periods of outstanding options and equity awards were not changed as a result of the merger.

As a result of the merger, the prior Progress Energy shares outstanding were cancelled. Progress Energy now has 100 authorized, issued and outstanding shares of common stock.

MERGER-RELATED REGULATORY MATTERS

Federal Energy Regulatory Commission

On June 8, 2012, the FERC conditionally approved the merger including Duke Energy and Progress Energy's revised market power mitigation plan, the Joint Dispatch Agreement (JDA) and the joint Open Access Transmission Tariff (OATT). The revised market power mitigation plan provides for the acceleration of one transmission project and the construction of seven other transmission projects (Long-term FERC Mitigation) and interim firm power sale agreements during the construction of the transmission projects (Interim FERC Mitigation). The Long-term FERC Mitigation will increase power imported into the service areas of Duke Energy Carolinas LLC (Duke Energy Carolinas), a wholly owned subsidiary of Duke Energy, and PEC and enhance competitive power supply options in the service areas. The construction of these projects will occur over the next two to three years. In conjunction with the Interim FERC Mitigation, Duke Energy Carolinas and PEC entered into power sale agreements with various counterparties that were effective with the consummation of the merger. These agreements, or similar power sale agreements, will be in place until the Long-term FERC Mitigation is operational. Under the agreements PEC will deliver around-the-clock power during the winter and summer in quantities that vary by season and by peak period.

The FERC order requires an independent partyto monitor whether the power sale agreements remain in effect during construction of the transmission projects and provide quarterly reports to the FERC regarding the status of construction of the transmission projects.

• On June 25, 2012, Duke Energy and Progress Energy accepted the conditions imposed by the FERC.
• On July 9, 2012, certain intervenors requested a rehearing seeking to overturn the June 8, 2012 order by the FERC. On August 8, 2012, the FERC granted rehearing for further consideration.

North Carolina Utilities Commission and Public Service Commission of South Carolina

In September 2011, Duke Energy and Progress Energy reached settlements with the Public Staff of the North Carolina Utilities Commission (NC Public Staff) and the South Carolina Office of Regulatory Staff (ORS) and certain other interested parties in connection with the regulatory proceedings related to the merger, the JDA and the OATT that were pending before the NCUC and PSCSC. These settlements were updated in May 2012 to reflect the results of ongoing merger-related applications pending before the FERC. As part of these settlements and the application for approval of the merger by the NCUC and PSCSC, Duke Energy Carolinas and PEC agreed to the conditions and obligations listed below.

• Guarantee of $650 million in system fuel and fuel-related savings over 60 to 78 months for North Carolina and South Carolina retail customers. The savings are expected to be achieved through coal blending, coal commodity and transportation savings, gas transportation savings and the joint dispatch of Duke Energy Carolinas and PEC generation fleets.
• Duke Energy Carolinas and PEC will not seek recovery from retail customers for the cost of the Long-term FERC Mitigation for five years following merger consummation. After five years, Duke Energy Carolinas and PEC may seek to recover the costs of the Long-term FERC Mitigation, but must show that the projects are needed to provide adequate and reliable retail service regardless of the merger.
• A $65 million rate reduction over the term of the Interim FERC Mitigation to reflect the cost of capacity not available to Duke Energy Carolinas and PECwholesale and retail customers during the Interim FERC Mitigation. The rate reduction will be achieved through retail decrement riders apportioned between Duke Energy Carolinas and PEC retail customers.
• Duke Energy Carolinas and PEC will not seek recovery from retail customers for any revenue shortfalls or fuel-related costs associated with the Interim FERC Mitigation.
• Duke Energy Carolinas and PEC will not seek recovery from retail customers for any of their allocable share of merger-related severance costs.
• Duke Energy Carolinas and PEC will provide community support and charitable contributions for four years, workforce development, low income energy assistance and funding for green energy at a total cost of approximately $99 million, which cannot be recovered from retail customers.
• Duke Energy Carolinas and PEC will abide by revised North Carolina Regulatory Conditions and Code of Conduct governing their operations.

On June 29, 2012, the NCUC approved the merger application and the JDA application with conditions that were reflective of the settlement agreements described above. On July 2, 2012, the PSCSC approved the JDA application subject to Duke Energy Carolinas and PEC providing their South Carolina retail customers pro rata benefits equivalent to those approved by the NCUC in its merger approval order.

On July 6, 2012, the NCUC issued an order initiating investigation and scheduling hearings on the Duke Energy board of directors' decision on July 2, 2012, to replace William D. Johnson with James E. Rogers as President and CEO of Duke Energy subsequent to the merger close, as well as other related matters. See Note 4C for further information.

ACCOUNTING CHARGES RELATED TO THE MERGER CONSUMMATION

The following pre-tax consummation charges were recognized upon closing of the merger and are included in our Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2012.

(in millions)		PEC		PEF		Progress Energy
FERC Mitigation		$	71	$	-	$	71
Severance costs			42		24		66
Community support, charitable contributions and other			54		9		63
	Total	$	167	$	33	$	200

The FERC Mitigation charges reflect the portion of transmission project costs thatare probable of disallowance, the impairment of the carrying value of the generation assets serving theInterim FERC Mitigation, and the mark-to-market loss recognized on the power sale agreements upon closing of the merger.Subsequent changes in the fair value of the interim power sale agreements are reflected in regulated electric operating revenues over the life of the contracts. The charges related to the transmission projects and the impairment of the carrying value of generation assets were recorded within impairment charges in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2012. The mark-to-market loss on the power sale agreements was recorded in regulated electric operating revenues in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2012. Realized gains or losses on the interim contract sales are also recorded within regulated electric operating revenues. The ability to successfully defend future recovery of a portion of the transmission projects in rates and any future changes to estimated transmission project costs could impact the amount that is not expected to be recovered.

In conjunction with the merger, in November 2011, Duke Energy and Progress Energy each offered a voluntary severance plan (VSP) to certain eligible employees. VSP and other severance costs incurred during the three and nine months ended September 30, 2012, were recorded primarily within operations, maintenance and other (O&M) expense in the Consolidated Statements of Operations and Comprehensive Income. See Note 13 for further information related to employee severance expenses.

Community support, charitable contributions and other reflect (i) the unconditional obligation to provide funding at a level comparable to historic practices over the next four years and (ii) financial and legal advisory costs that were incurredupon the closing of the merger, retention and relocation costs paid to certain employees. These charges were recorded within O&M expense in the Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2012.

COSTS TO ACHIEVE THE MERGER

The following table summarizespre-tax merger consummation costs, integration and other related costs (collectively referred to as costs to achieve),including those discussed above, substantially all of which are included in operating expenses in our Statements of Operations and Comprehensive Income:

	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
Progress Energy	$	218	$	14	$	241	$	32
PEC		180		7		194		17
PEF		38		7		47		15

Duke Energy expects to incur significant system integration and other merger-related transition costs primarily through 2016 that are necessary in order to achieve certain cost savings, efficiencies and other benefits anticipated to result from the merger.

EXIT COSTS

In 2011, 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 $17million for us, of which $9 million of expense will be attributable to PEC, $4 million to PEF and $4 million to other Duke Energy subsidiaries. The exit cost liability is being recognized proportionately as we vacate the premises, which began in the fourth quarter of 2011. The costs of the exit plan are included in O&M expense in the Consolidated Statements of Operations and Comprehensive Income.

The following table presents a reconciliation of the beginning and ending exit cost liability balance:

(in millions)
Balance, December 31, 2011		$	5
Additional exit cost recognized			5
Balance, June 30, 2012			10
Additional exit cost recognized(a)			2
Balance, September 30, 2012(b)		$	12
(a)	PEC, PEF and other Duke Energy subsidiaries recognized exit costs of $1 million, $- million and $1 million, respectively, for the three months ended September 30, 2012, and $4 million, $2 million and $1 million, respectively, for the nine months ended September 30, 2012.
(b)	Expense related to the recognition of the cumulative exit cost liability at September 30, 2012, was attributed to PEC, PEF and other Duke Energy subsidiaries totaling $8 million, $3 million and $1 million, respectively.

B.       SALES OF OTHER ASSETS

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 5C 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 September 30, 2012 and 2011, earnings(loss) from discontinued operations, net of tax was $3 million and $- million, respectively.During the nine months ended September 30, 2012 and 2011, earnings (loss) from discontinued operations, net of tax was $10 million and $(4) million, respectively. Earnings for the nine months endedSeptember 30, 2012, relates primarily to an $18 million pre-tax gain from the reversal of certain environmental indemnification liabilities for which the indemnification period expired in the first quarter of 2012.

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Investments (Tables)

9 Months Ended

Sep. 30, 2012

Investments Disclosure [Line Items]

Investments

PROGRESS ENERGY
(in millions)		Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2012
Nuclear decommissioning trust funds
	Equity securities	$	1,226	$	21	$	534
	Corporate debt securities		85		-		9
	Municipal bonds		134		1		10
	U.S. government bonds		295		-		17
	Other		104		1		3
Total nuclear decommissioning trust funds			1,844		23		573
Other investments
	Municipal bonds		39		-		-
	Other		21		-		-
	Total	$	1,904	$	23	$	573
December 31, 2011
Nuclear decommissioning trust funds
	Equity securities	$	1,062	$	29	$	412
	Corporate debt securities		86		-		6
	Municipal bonds		127		2		7
	U.S. government bonds		268		-		18
	Other		87		-		1
Total nuclear decommissioning trust funds			1,630		31		444
Other investments
	Other		20		-		-
	Total	$	1,650	$	31	$	444

Available For Sale Securities Debt Maturities Fair Value [Text Block]

(in millions)	< 1 Year		1-5 Years		6-10 Years		Thereafter		Total
Progress Energy	$	13	$	125	$	136	$	301	$	575
PEC		11		102		72		194		379
PEF		2		18		55		82		157

Schedule of realized gain (loss)

PROGRESS ENERGY
	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
Proceeds	$	274	$	1,062	$	794	$	4,254
Realized gains		8		9		23		24
Realized losses		6		11		12		20

Schedule of unrealized loss on investments

PROGRESS ENERGY
(in millions)		Fair Value		Unrealized Loss Positions > 12 months		Unrealized Loss Positions < 12 months
September 30, 2012
Nuclear decommissioning trust funds
	Equity securities	$	89	$	13	$	8
	Corporate debt securities		3		-		-
	Municipal bonds		14		1		-
	U.S. government bonds		10		-		-
	Other		1		-		1
Total nuclear decommissioning trust funds			117		14		9
Other investments
	Other		4		-		-
	Total	$	121	$	14	$	9
December 31, 2011
Nuclear decommissioning trust funds
	Equity securities	$	112	$	10	$	19
	Corporate debt securities		20		-		-
	Municipal bonds		21		2		-
	U.S. government bonds		(23)		-		-
	Other		6		-		-
	Total	$	136	$	12	$	19

PEC [Member]

Investments Disclosure [Line Items]

Investments

PEC
(in millions)		Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2012
Nuclear decommissioning trust funds
	Equity securities	$	797	$	15	$	340
	Corporate debt securities		75		-		8
	Municipal bonds		61		-		4
	U.S. government bonds		230		-		15
	Other		60		-		1
Total nuclear decommissioning trust funds			1,223		15		368
Other investments
	Other		6		-		-
	Total	$	1,229	$	15	$	368
December 31, 2011
Nuclear decommissioning trust funds
	Equity securities	$	690	$	20	$	262
	Corporate debt securities		69		-		5
	Municipal bonds		55		-		3
	U.S. government bonds		225		-		16
	Other		62		-		1
Total nuclear decommissioning trust funds			1,101		20		287
Other investments
	Other		6		-		-
	Total	$	1,107	$	20	$	287

Available For Sale Securities Debt Maturities Fair Value [Text Block]

(in millions)	< 1 Year		1-5 Years		6-10 Years		Thereafter		Total
Progress Energy	$	13	$	125	$	136	$	301	$	575
PEC		11		102		72		194		379
PEF		2		18		55		82		157

Schedule of realized gain (loss)

PEC
	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
Proceeds	$	101	$	136	$	351	$	386
Realized gains		4		4		14		10
Realized losses		2		4		5		9

Schedule of unrealized loss on investments

PEC
(in millions)		Fair Value		Unrealized Loss Positions > 12 months		Unrealized Loss Positions < 12 months
September 30, 2012
Nuclear decommissioning trust funds
	Equity securities	$	56	$	10	$	5
	Corporate debt securities		2		-		-
	Municipal bonds		5		-		-
	U.S. government bonds		11		-		-
	Total	$	74	$	10	$	5
December 31, 2011
Nuclear decommissioning trust funds
	Equity securities	$	69	$	10	$	10
	Corporate debt securities		10		-		-
	Municipal bonds		8		-		-
	U.S. government bonds		9		-		-
	Other		2		-		-
	Total	$	98	$	10	$	10

PEF [Member]

Investments Disclosure [Line Items]

Investments

PEF
(in millions)		Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2012
Nuclear decommissioning trust funds
	Equity securities	$	429	$	6	$	194
	Corporate debt securities		10		-		1
	Municipal bonds		73		1		6
	U.S. government bonds		65		-		2
	Other		44		1		2
Total nuclear decommissioning trust funds			621		8		205
Other investments
	Municipal bonds		39		-		-
	Other		2		-		-
	Total	$	662	$	8	$	205
December 31, 2011
Nuclear decommissioning trust funds
	Equity securities	$	372	$	9	$	150
	Corporate debt securities		17		-		1
	Municipal bonds		72		2		4
	U.S. government bonds		43		-		2
	Other		25		-		-
Total nuclear decommissioning trust funds			529		11		157
Other investments
	Other		1		-		-
	Total	$	530	$	11	$	157

Available For Sale Securities Debt Maturities Fair Value [Text Block]

(in millions)	< 1 Year		1-5 Years		6-10 Years		Thereafter		Total
Progress Energy	$	13	$	125	$	136	$	301	$	575
PEC		11		102		72		194		379
PEF		2		18		55		82		157

Schedule of realized gain (loss)

PEF
	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
Proceeds	$	173	$	926	$	443	$	3,861
Realized gains		4		5		9		14
Realized losses		4		7		7		11

Schedule of unrealized loss on investments

PEF
(in millions)		Fair Value		Unrealized Loss Positions > 12 months		Unrealized Loss Positions < 12 months
September 30, 2012
Nuclear decommissioning trust funds
	Equity securities	$	33	$	3	$	3
	Municipal bonds		9		1		-
	Other		1		-		1
Total nuclear decommissioning trust funds			43		4		4
Other investments
	Other		4		-		-
	Total	$	47	$	4	$	4
December 31, 2011
Nuclear decommissioning trust funds
	Equity securities	$	43	$	-	$	9
	Corporate debt securities		10		-		-
	Municipal bonds		13		2		-
	U.S. government bonds		(32)		-		-
	Other		4		-		-
	Total	$	38	$	2	$	9

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Financial Information by Business Segment (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011		Dec. 31, 2011
Segment Reporting Information [Line Items]
Unaffiliated	$ 2,750		$ 2,753		$ 7,140		$ 7,196
Affiliated	38				38
Total operating revenues	2,788		2,753		7,178		7,196
Depreciation and amortization	174		175		571		508
Net income	157		293		373		656
Add back of noncontrolling interest component	2		2		5		5
Income (loss) from discontinued operations, net of tax	3		0		10		(4)
Total assets	36,651				36,651				34,931
After-tax costs to achieve	132		9		149		27
Franchised Electric [Member]
Segment Reporting Information [Line Items]
Unaffiliated	2,747		2,750		7,132		7,188
Affiliated	39				40		1
Segment reporting information, revenue for reportable segment, total	2,786		2,750		7,172		7,189
Segment income	333	[1]	408	[1]	636	[1]	874	[1]
Total assets	36,135				36,135				34,166
Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Unaffiliated	2,747		2,750		7,132		7,188
Affiliated	39				40		1
Segment reporting information, revenue for reportable segment, total	2,786		2,750		7,172		7,189
Segment income	333	[1]	408	[1]	636	[1]	874	[1]
Total assets	36,135				36,135				34,166
Other [Member]
Segment Reporting Information [Line Items]
Unaffiliated	3		3		8		8
Segment reporting information, revenue for reportable segment, total	3		3		8		8
Segment income	(181)	[1],[2]	(117)	[1],[2]	(278)	[1],[2]	(219)	[1],[2]
Total assets	549				549				765
Eliminations [Member]
Segment Reporting Information [Line Items]
Affiliated	(1)				(2)		(1)
Segment reporting information, revenue for reportable segment, total	(1)				(2)		(1)
Reclassifications [Member]
Segment Reporting Information [Line Items]
Total assets	(33)	[3]			(33)	[3]
PEC's Other [Member]
Segment Reporting Information [Line Items]
Segment income	(109)		(5)		(119)		(14)
PEF's Other [Member]
Segment Reporting Information [Line Items]
Segment income	$ (23)		$ (4)		$ (30)		$ (13)

[1] Segment income excludes noncontrolling interests and results of entities classified as discontinued operations.

[2] Segment income includes after-tax costs to achieve the merger with Duke Energy of $132 million and $149 million for the three and nine months ended September 30, 2012, respectively, and $9 million and $27 million for the three and nine months ended September 30, 2011, respectively.

[3] Primarily represents reclassification of federal tax balances in consolidation.

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Benefit Plans - Benefit Obligations and Accrued Costs (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Changes in benefit obligations and the funded status
Change in pension benefit obligation due to defined benefit plans remeasurement	$ 122
Increase in regulatory assets due to defined benefit plans remeasurement	128
Weighted-average actuarial assumptions used in the calculation of year-end obligations
Defined benefit plan, health care cost trend rate assumed for currrent year	8.75%
Ultimate medical cost trend rate	5.00%
Year ultimate medical cost trend rate is achieved	2020
PEC [Member]
Changes in benefit obligations and the funded status
Change in pension benefit obligation due to defined benefit plans remeasurement	40
Increase in regulatory assets due to defined benefit plans remeasurement	44
PEF [Member]
Changes in benefit obligations and the funded status
Change in pension benefit obligation due to defined benefit plans remeasurement	75
Increase in regulatory assets due to defined benefit plans remeasurement	$ 75

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Unaudited Condensed Consolidated Statements of Operations and Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Operating Revenues
Regulated electric	$ 2,775	$ 2,743	$ 7,135	$ 7,161
Non-regulated electric and other	13	10	43	35
Total operating revenues	2,788	2,753	7,178	7,196
Operating expenses
Fuel used in electric generation and purchased power	1,396	1,234	3,299	3,186
Operation, maintenance and other	626	494	1,798	1,500
Depreciation and amortization	174	175	571	508
Property and other taxes	160	164	440	437
Impairment charges	55	0	55	0
Total operating expenses	2,411	2,067	6,163	5,631
Gains on sales of other assets and other, net	2	1	4	2
Operating income	379	687	1,019	1,567
Other income and expenses, net	32	(44)	97	21
Interest expense, net	182	172	560	542
Income from continuing operations before income taxes	229	471	556	1,046
Income tax expense from continuing operations	75	178	193	386
Income from continuing operations	154	293	363	660
Income (loss) from discontinued operations, net of tax	3	0	10	(4)
Net income	157	293	373	656
Less: net income attributable to noncontrolling interests	2	2	5	5
Net income attributable to Duke Energy Corporation	155	291	368	651
Net income amounts attributable to Duke Energy Corporation
Income from continuing operations, net of tax	152	291	358	655
Discontinued operations, net of tax	3	0	10	(4)
Net income attributable to Duke Energy Corporation	155	291	368	651
Comprehensive income, net of tax
Comprehensive income	255	228	472	574
Comprehensive income attributable to noncontrolling interests, net of tax	(2)	(2)	(5)	(5)
Comprehensive income attributable to Duke Energy Corporation	253	226	467	569
PEC [Member]
Operating Revenues
Regulated electric	1,394	1,330	3,561	3,524
Non-regulated electric and other	4	1	17	10
Total operating revenues	1,398	1,331	3,578	3,534
Operating expenses
Fuel used in electric generation and purchased power	597	544	1,450	1,382
Operation, maintenance and other	384	273	1,146	863
Depreciation and amortization	131	132	399	383
Property and other taxes	60	58	168	164
Impairment charges	55	0	55	0
Total operating expenses	1,227	1,007	3,218	2,792
Gains on sales of other assets and other, net	1	0	2	1
Operating income	172	324	362	743
Other income and expenses, net	21	16	57	55
Interest expense, net	52	41	156	134
Income from continuing operations before income taxes	141	299	263	664
Income tax expense from continuing operations	45	100	83	227
Net income	96	199	180	437
Less: preferred stock dividend requirement	1	1	2	2
Net income available to parent	95	198	178	435
Comprehensive income, net of tax
Comprehensive income attributable to Duke Energy Corporation	168	165	251	400
PEF [Member]
Operating Revenues
Regulated electric	1,382	1,414	3,576	3,639
Non-regulated electric and other	6	5	18	16
Total operating revenues	1,388	1,419	3,594	3,655
Operating expenses
Fuel used in electric generation and purchased power	799	690	1,849	1,804
Operation, maintenance and other	245	222	660	652
Depreciation and amortization	39	39	158	112
Property and other taxes	99	106	271	274
Total operating expenses	1,182	1,057	2,938	2,842
Gains on sales of other assets and other, net	1	1	2	2
Operating income	207	363	658	815
Other income and expenses, net	11	5	29	24
Interest expense, net	62	46	194	176
Income from continuing operations before income taxes	156	322	493	663
Income tax expense from continuing operations	56	119	182	245
Net income	100	203	311	418
Less: preferred stock dividend requirement	0	0	1	1
Net income available to parent	100	203	310	417
Comprehensive income, net of tax
Comprehensive income attributable to Duke Energy Corporation	$ 126	$ 186	$ 337	$ 396

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Other Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2009 Synthetic Fuels Matters [Member]	Sep. 30, 2012 Spent Nuclear Fuel Matters [Member]	Sep. 30, 2012 Spent Nuclear Fuel Matters [Member] PEC [Member]	Sep. 30, 2012 Spent Nuclear Fuel Matters [Member] PEF [Member]
Gain Contingencies [Line Items]
Gain contingency, asserted damage		$ 113	$ 113	$ 113
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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Consolidated Statements of Changes in Total Equity (USD $) In Millions, unless otherwise specified	Total		PEC [Member]	PEF [Member]	Common Stock Equity [Member]	Common Stock Equity [Member] PEC [Member]	Common Stock Equity [Member] PEF [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Retained Earnings [Member] PEC [Member]	Retained Earnings [Member] PEF [Member]	Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]	Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] PEC [Member]	Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] PEF [Member]	Accumulated Defined Benefit Plans Adjustment [Member]	Common Stockholders' Equity [Member]	Noncontrolling Interests [Member]
Beginning balance at Dec. 31, 2010	$ 10,027		$ 5,180	$ 4,890	$ 7,332	$ 2,130	$ 1,750	$ 11	$ 2,805	$ 3,083	$ 3,144	$ (63)	$ (33)	$ (4)	$ (62)	$ 10,023	$ 4
Net income	653	[1]	437	418					651	437	418					651	2
Other comprehensive (loss) income	(82)		(37)	(22)								(77)	(37)	(22)	(5)	(82)
Issuance of shares	42				42											42
Stock-based compensation expense	28		14	5	24	14	5	4								28
Dividends paid to parent			(450)	(475)						(450)	(475)
Dividends declared	(550)								(550)							(550)
Preferred stock dividends at stated rates			(2)	(1)						(2)	(1)
Distributions to noncontrolling interests	(3)																(3)
Tax dividend				(2)							(2)
Notes To Reconciliation Of Total Equity [Details]
Net income	656		437	418
Net income attributable to preferred shareholders of subsidiaries excluded from reconciliation of total equity	3
Ending balance at Sep. 30, 2011	10,115		5,142	4,813	7,398	2,144	1,755	15	2,906	3,068	3,084	(140)	(70)	(26)	(67)	10,112	3
Beginning balance at Jun. 30, 2011
Notes To Reconciliation Of Total Equity [Details]
Net income	293		199	203
Ending balance at Sep. 30, 2011	10,115		5,142	4,813
Beginning balance at Dec. 31, 2011	10,025		5,088	4,675	7,418	2,148	1,757	16	2,752	3,011	2,945	(143)	(71)	(27)	(22)	10,021	4
Net income	370	[1]	180	311					368	180	311					368	2
Other comprehensive (loss) income	99		71	26								99	71	26		99
Issuance of shares	6				6											6
Stock-based compensation expense	25		11	5	12	11	5	13								25
Dividends paid to parent			(310)	(170)						(310)	(170)
Dividends declared	(369)								(369)							(369)
Preferred stock dividends at stated rates			(2)	(1)						(2)	(1)
Distributions to noncontrolling interests	(2)																(2)
Tax dividend				(1)							(1)
Issuance of 100 shares of $.01 par value common shares to Duke Energy					(7,436)			7,436
Other	(1)																(1)
Notes To Reconciliation Of Total Equity [Details]
Net income	373		180	311
Net income attributable to preferred shareholders of subsidiaries excluded from reconciliation of total equity	3
Ending balance at Sep. 30, 2012	10,153		5,038	4,845	0	2,159	1,762	7,465	2,751	2,879	3,084	(44)	0	(1)	(22)	10,150	3
Beginning balance at Jun. 30, 2012
Notes To Reconciliation Of Total Equity [Details]
Net income	157		96	100
Ending balance at Sep. 30, 2012	$ 10,153		$ 5,038	$ 4,845											$ (22)

[1] For the nine months ended September 30, 2012, consolidated net income of $373 million includes $3 million attributable to preferred shareholders of subsidiaries. For the nine months ended September 30, 2011, consolidated net income of $656 million includes $3 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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Condensed Consolidating Statements (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Dec. 31, 2010
Operating revenues
Regulated electric	$ 2,775	$ 2,743	$ 7,135	$ 7,161
Non-regulated electric and other	13	10	43	35
Total operating revenues	2,788	2,753	7,178	7,196
Operating expenses
Fuel used in electric generation and purchased power	1,396	1,234	3,299	3,186
Operation, maintenance and other	626	494	1,798	1,500
Depreciation and amortization	174	175	571	508
Property and other taxes	160	164	440	437
Impairment charges	55	0	55	0
Total operating expenses	2,411	2,067	6,163	5,631
Gains on sales of other assets and other, net	2	1	4	2
Operating (loss) income	379	687	1,019	1,567
Other income and expenses, net	32	(44)	97	21
Interest expense, net	182	172	560	542
Income (Loss) from Continuing Operations before Income Taxes	229	471	556	1,046
Income tax expense from continuing operations	75	178	193	386
Income from continuing operations	154	293	363	660
Income (loss) from discontinued operations, net of tax	3	0	10	(4)
Net income (loss)	157	293	373	656
Less: net income attributable to noncontrolling interests	2	2	5	5
Net income attributable to Duke Energy Corporation	155	291	368	651
Comprehensive income, net of tax
Comprehensive income	255	228	472	574
Comprehensive income attributable to noncontrolling interests, net of tax	(2)	(2)	(5)	(5)
Comprehensive income attributable to Duke Energy Corporation	253	226	467	569
Current assets
Cash and cash equivalents	57	103	57	103
Receivables	930		930		883
Notes receivable from affiliated companies	0		0		0
Inventory	1,366		1,366		1,429
Prepayments and other current assets	673		673		778
Total current assets	3,026		3,026		3,320
Investments and other assets
Nuclear decommissioning trust funds	1,844		1,844		1,647
Investment in consolidated subsidiaries	0		0		0
Goodwill	3,655		3,655		3,655
Other	532		532		504
Total investments and other assets	6,031		6,031		5,806
Net property, plant and equipment	24,167		24,167		22,292
Regulatory assets and deferred debits
Regulatory assets	3,331		3,331		3,424
Other	96		96		89
Total regulatory assets and deferred debits	3,427		3,427		3,513
Total assets	36,651		36,651		34,931
Current liabilities
Notes payable and commercial paper	0		0		671
Current maturities of long-term debt	838		838		961
Notes payable to affiliated companies	635		635		0
Other	2,263		2,263		2,387
Total current liabilities	3,736		3,736		4,019
Long-term debt	12,664		12,664		11,918
Long-term debt, affiliate	274		274		273
Deferred credits and other liabilities
Deferred income taxes	2,509		2,509		2,193
Asset retirement obligations	2,137		2,137		1,265
Regulatory liabilities	2,704		2,704		2,727
Deferred credits and other liabilities	2,381		2,381		2,418
Total deferred credits and other liabilities	9,731		9,731		8,603
Preferred stock of subsidiaries	93		93		93
Equity
Common shareholders' equity	10,150		10,150		10,021
Noncontrolling interests	3		3		4
Total equity	10,153	10,115	10,153	10,115	10,025	10,027
Total liabilities and equity	36,651		36,651		34,931
Condensed Consolidating Statement of Cash Flows
Net cash provided (used) by operating activities			1,450	1,258
Cash flows from investing activities
Capital expenditures			(1,695)	(1,647)
Purchases of available-for-sale securities			(947)	(4,537)
Proceeds from sales and maturities of available-for-sale securities			921	4,509
Other			112	100
Net cash provided (used) by investing activities			(1,609)	(1,575)
Cash flows from financing activities
Issuance of long-term debt			1,432	1,286
Issuance of common stock related to employee benefit plans			6	42
Payments for the redemption of long-term debt			(961)	(1,010)
Notes payable and commercial paper			(671)	45
Distributions to noncontrolling interests			(6)	(6)
Dividends paid			(445)	(550)
Notes payable to affiliate			635	0
Other			(4)	2
Net cash provided (used) by financing activities			(14)	(191)
Net increase (decrease) in cash and cash equivalents			(173)	(508)
Cash and cash equivalents at beginning of period			230	611
Cash and cash equivalents at end of period	57	103	57	103
Parent [Member]
Operating revenues
Regulated electric	0	0	0	0
Non-regulated electric and other	0	0	0	0
Total operating revenues	0	0	0	0
Operating expenses
Fuel used in electric generation and purchased power	0	0	0	0
Operation, maintenance and other	0	2	4	6
Depreciation and amortization	0	0	0	0
Property and other taxes	0	0	0	0
Impairment charges	0	0	0	0
Total operating expenses	0	2	4	6
Gains on sales of other assets and other, net	0	0	0	0
Operating (loss) income	0	(2)	(4)	(6)
Equity in earnings of consolidated subsidiaries	203	391	489	832
Other income and expenses, net	(1)	(63)	8	(59)
Interest expense, net	63	80	193	216
Income (Loss) from Continuing Operations before Income Taxes	139	246	300	551
Income tax expense from continuing operations	(16)	(45)	(68)	(100)
Income from continuing operations	155	291	368	651
Income (loss) from discontinued operations, net of tax	0	0	0	0
Net income (loss)	155	291	368	651
Less: net income attributable to noncontrolling interests	0	0	0	0
Net income attributable to Duke Energy Corporation	155	291	368	651
Comprehensive income, net of tax
Comprehensive income	253	226	467	569
Comprehensive income attributable to noncontrolling interests, net of tax	0	0	0	0
Comprehensive income attributable to Duke Energy Corporation	253	226	467	569
Current assets
Cash and cash equivalents	0	0	0	0
Receivables	0		0		0
Notes receivable from affiliated companies	676		676		53
Inventory	0		0		0
Prepayments and other current assets	59		59		127
Total current assets	735		735		297
Investments and other assets
Nuclear decommissioning trust funds	0		0		0
Investment in consolidated subsidiaries	14,171		14,171		14,043
Goodwill	0		0		0
Other	151		151		118
Total investments and other assets	14,322		14,322		14,161
Net property, plant and equipment	0		0		0
Regulatory assets and deferred debits
Regulatory assets	0		0		0
Other	23		23		22
Total regulatory assets and deferred debits	23		23		22
Total assets	15,080		15,080		14,480
Current liabilities
Notes payable and commercial paper	0		0		250
Current maturities of long-term debt	0		0		450
Notes payable to affiliated companies	843		843		0
Other	75		75		199
Total current liabilities	918		918		899
Long-term debt	3,992		3,992		3,543
Long-term debt, affiliate	0		0		0
Deferred credits and other liabilities
Deferred income taxes	0		0		0
Asset retirement obligations	0		0		0
Regulatory liabilities	0		0		0
Deferred credits and other liabilities	20		20		17
Total deferred credits and other liabilities	20		20		17
Preferred stock of subsidiaries	0		0		0
Equity
Common shareholders' equity	10,150		10,150		10,021
Noncontrolling interests	0		0		0
Total equity	10,150		10,150		10,021
Total liabilities and equity	15,080		15,080		14,480
Condensed Consolidating Statement of Cash Flows
Net cash provided (used) by operating activities			335	659
Cash flows from investing activities
Capital expenditures			0	0
Purchases of available-for-sale securities			0	0
Proceeds from sales and maturities of available-for-sale securities			0	0
Notes due from affiliate			(624)	(83)
Return of investment in consolidated subsidiaries			0	0
Contributions to consolidated subsidiaries			0	(11)
Other			24	(6)
Net cash provided (used) by investing activities			(600)	(100)
Cash flows from financing activities
Issuance of long-term debt			444	494
Issuance of common stock related to employee benefit plans			6	42
Payments for the redemption of long-term debt			(450)	(700)
Notes payable and commercial paper			(250)	45
Distributions to noncontrolling interests			0	0
Dividends paid			(445)	(550)
Dividends to parent			0	0
Dividends paid to parent in excess of retained earnings			0	0
Notes payable to affiliate			843	0
Contributions from parent			0	0
Other			0	0
Net cash provided (used) by financing activities			148	(669)
Net increase (decrease) in cash and cash equivalents			(117)	(110)
Cash and cash equivalents at beginning of period			117	110
Cash and cash equivalents at end of period	0	0	0	0
Subsidiary Guarantor [Member]
Operating revenues
Regulated electric	1,382	1,414	3,576	3,639
Non-regulated electric and other	10	9	26	24
Total operating revenues	1,392	1,423	3,602	3,663
Operating expenses
Fuel used in electric generation and purchased power	799	690	1,849	1,804
Operation, maintenance and other	247	225	668	659
Depreciation and amortization	39	39	158	112
Property and other taxes	100	106	272	274
Impairment charges	0	0	0	0
Total operating expenses	1,185	1,060	2,947	2,849
Gains on sales of other assets and other, net	1	1	2	2
Operating (loss) income	208	364	657	816
Equity in earnings of consolidated subsidiaries	0	0	0	0
Other income and expenses, net	12	2	32	25
Interest expense, net	67	52	210	193
Income (Loss) from Continuing Operations before Income Taxes	153	314	479	648
Income tax expense from continuing operations	55	116	177	240
Income from continuing operations	98	198	302	408
Income (loss) from discontinued operations, net of tax	2	1	10	(2)
Net income (loss)	100	199	312	406
Less: net income attributable to noncontrolling interests	1	1	3	3
Net income attributable to Duke Energy Corporation	99	198	309	403
Comprehensive income, net of tax
Comprehensive income	118	182	331	384
Comprehensive income attributable to noncontrolling interests, net of tax	(1)	(1)	(3)	(3)
Comprehensive income attributable to Duke Energy Corporation	117	181	328	381
Current assets
Cash and cash equivalents	38	34	38	34
Receivables	435		435		367
Notes receivable from affiliated companies	0		0		0
Inventory	618		618		659
Prepayments and other current assets	417		417		418
Total current assets	1,508		1,508		1,536
Investments and other assets
Nuclear decommissioning trust funds	621		621		559
Investment in consolidated subsidiaries	0		0		0
Goodwill	0		0		0
Other	232		232		189
Total investments and other assets	853		853		748
Net property, plant and equipment	10,885		10,885		10,455
Regulatory assets and deferred debits
Regulatory assets	1,446		1,446		1,629
Other	49		49		51
Total regulatory assets and deferred debits	1,495		1,495		1,680
Total assets	14,741		14,741		14,419
Current liabilities
Notes payable and commercial paper	0		0		233
Current maturities of long-term debt	435		435		10
Notes payable to affiliated companies	431		431		238
Other	1,120		1,120		1,030
Total current liabilities	1,986		1,986		1,511
Long-term debt	4,237		4,237		4,671
Long-term debt, affiliate	309		309		309
Deferred credits and other liabilities
Deferred income taxes	960		960		757
Asset retirement obligations	514		514		369
Regulatory liabilities	880		880		1,024
Deferred credits and other liabilities	923		923		1,012
Total deferred credits and other liabilities	3,277		3,277		3,162
Preferred stock of subsidiaries	34		34		34
Equity
Common shareholders' equity	4,895		4,895		4,728
Noncontrolling interests	3		3		4
Total equity	4,898		4,898		4,732
Total liabilities and equity	14,741		14,741		14,419
Condensed Consolidating Statement of Cash Flows
Net cash provided (used) by operating activities			733	664
Cash flows from investing activities
Capital expenditures			(573)	(626)
Purchases of available-for-sale securities			(562)	(4,099)
Proceeds from sales and maturities of available-for-sale securities			561	4,101
Notes due from affiliate			0	22
Return of investment in consolidated subsidiaries			0	0
Contributions to consolidated subsidiaries			0	0
Other			13	102
Net cash provided (used) by investing activities			(561)	(500)
Cash flows from financing activities
Issuance of long-term debt			0	296
Issuance of common stock related to employee benefit plans			0	0
Payments for the redemption of long-term debt			(9)	(309)
Notes payable and commercial paper			(233)	0
Distributions to noncontrolling interests			(3)	(4)
Dividends paid			0	0
Dividends to parent			(173)	(478)
Dividends paid to parent in excess of retained earnings			0	0
Notes payable to affiliate			193	84
Contributions from parent			0	10
Other			(1)	1
Net cash provided (used) by financing activities			(226)	(400)
Net increase (decrease) in cash and cash equivalents			(54)	(236)
Cash and cash equivalents at beginning of period			92	270
Cash and cash equivalents at end of period	38	34	38	34
Non-Guarantor Subsidiaries [Member]
Operating revenues
Regulated electric	1,394	1,330	3,561	3,524
Non-regulated electric and other	4	2	17	11
Total operating revenues	1,398	1,332	3,578	3,535
Operating expenses
Fuel used in electric generation and purchased power	597	544	1,450	1,382
Operation, maintenance and other	378	265	1,120	829
Depreciation and amortization	135	136	413	396
Property and other taxes	63	58	175	168
Impairment charges	55	0	55	0
Total operating expenses	1,228	1,003	3,213	2,775
Gains on sales of other assets and other, net	1	0	2	0
Operating (loss) income	171	329	367	760
Equity in earnings of consolidated subsidiaries	0	0	0	0
Other income and expenses, net	23	14	58	54
Interest expense, net	53	41	157	134
Income (Loss) from Continuing Operations before Income Taxes	141	302	268	680
Income tax expense from continuing operations	43	103	88	243
Income from continuing operations	98	199	180	437
Income (loss) from discontinued operations, net of tax	1	(1)	0	(2)
Net income (loss)	99	198	180	435
Less: net income attributable to noncontrolling interests	0	0	0	0
Net income attributable to Duke Energy Corporation	99	198	180	435
Comprehensive income, net of tax
Comprehensive income	170	165	250	393
Comprehensive income attributable to noncontrolling interests, net of tax	0	0	0	0
Comprehensive income attributable to Duke Energy Corporation	170	165	250	393
Current assets
Cash and cash equivalents	19	69	19	69
Receivables	495		495		516
Notes receivable from affiliated companies	209		209		219
Inventory	749		749		770
Prepayments and other current assets	293		293		297
Total current assets	1,765		1,765		1,823
Investments and other assets
Nuclear decommissioning trust funds	1,223		1,223		1,088
Investment in consolidated subsidiaries	0		0		0
Goodwill	0		0		0
Other	695		695		675
Total investments and other assets	1,918		1,918		1,763
Net property, plant and equipment	13,126		13,126		11,677
Regulatory assets and deferred debits
Regulatory assets	1,885		1,885		1,795
Other	30		30		22
Total regulatory assets and deferred debits	1,915		1,915		1,817
Total assets	18,724		18,724		17,080
Current liabilities
Notes payable and commercial paper	0		0		188
Current maturities of long-term debt	403		403		502
Notes payable to affiliated companies	246		246		34
Other	1,164		1,164		1,221
Total current liabilities	1,813		1,813		1,945
Long-term debt	4,435		4,435		3,704
Long-term debt, affiliate	0		0		0
Deferred credits and other liabilities
Deferred income taxes	2,091		2,091		1,903
Asset retirement obligations	1,623		1,623		896
Regulatory liabilities	1,667		1,667		1,543
Deferred credits and other liabilities	1,432		1,432		1,384
Total deferred credits and other liabilities	6,813		6,813		5,726
Preferred stock of subsidiaries	59		59		59
Equity
Common shareholders' equity	5,604		5,604		5,646
Noncontrolling interests	0		0		0
Total equity	5,604		5,604		5,646
Total liabilities and equity	18,724		18,724		17,080
Condensed Consolidating Statement of Cash Flows
Net cash provided (used) by operating activities			865	863
Cash flows from investing activities
Capital expenditures			(1,122)	(1,021)
Purchases of available-for-sale securities			(385)	(438)
Proceeds from sales and maturities of available-for-sale securities			359	408
Notes due from affiliate			10	(23)
Return of investment in consolidated subsidiaries			0	0
Contributions to consolidated subsidiaries			0	0
Other			75	5
Net cash provided (used) by investing activities			(1,063)	(1,069)
Cash flows from financing activities
Issuance of long-term debt			988	496
Issuance of common stock related to employee benefit plans			0	0
Payments for the redemption of long-term debt			(502)	(1)
Notes payable and commercial paper			(188)	0
Distributions to noncontrolling interests			0	0
Dividends paid			0	0
Dividends to parent			(310)	(450)
Dividends paid to parent in excess of retained earnings			0	0
Notes payable to affiliate			212	0
Contributions from parent			0	1
Other			(4)	(2)
Net cash provided (used) by financing activities			196	44
Net increase (decrease) in cash and cash equivalents			(2)	(162)
Cash and cash equivalents at beginning of period			21	231
Cash and cash equivalents at end of period	19	69	19	69
Other [Member]
Operating revenues
Regulated electric	(1)	(1)	(2)	(2)
Non-regulated electric and other	(1)	(1)	0	0
Total operating revenues	(2)	(2)	(2)	(2)
Operating expenses
Fuel used in electric generation and purchased power	0	0	0	0
Operation, maintenance and other	1	2	6	6
Depreciation and amortization	0	0	0	0
Property and other taxes	(3)	0	(7)	(5)
Impairment charges	0	0	0	0
Total operating expenses	(2)	2	(1)	1
Gains on sales of other assets and other, net	0	0	0	0
Operating (loss) income	0	(4)	(1)	(3)
Equity in earnings of consolidated subsidiaries	(203)	(391)	(489)	(832)
Other income and expenses, net	(2)	3	(1)	1
Interest expense, net	(1)	(1)	0	(1)
Income (Loss) from Continuing Operations before Income Taxes	(204)	(391)	(491)	(833)
Income tax expense from continuing operations	(7)	4	(4)	3
Income from continuing operations	(197)	(395)	(487)	(836)
Income (loss) from discontinued operations, net of tax	0	0	0	0
Net income (loss)	(197)	(395)	(487)	(836)
Less: net income attributable to noncontrolling interests	1	1	2	2
Net income attributable to Duke Energy Corporation	(198)	(396)	(489)	(838)
Comprehensive income, net of tax
Comprehensive income	(286)	(345)	(576)	(772)
Comprehensive income attributable to noncontrolling interests, net of tax	(1)	(1)	(2)	(2)
Comprehensive income attributable to Duke Energy Corporation	(287)	(346)	(578)	(774)
Current assets
Cash and cash equivalents	0	0	0	0
Receivables	0		0		0
Notes receivable from affiliated companies	(885)		(885)		(272)
Inventory	(1)		(1)		0
Prepayments and other current assets	(96)		(96)		(64)
Total current assets	(982)		(982)		(336)
Investments and other assets
Nuclear decommissioning trust funds	0		0		0
Investment in consolidated subsidiaries	(14,171)		(14,171)		(14,043)
Goodwill	3,655		3,655		3,655
Other	(546)		(546)		(478)
Total investments and other assets	(11,062)		(11,062)		(10,866)
Net property, plant and equipment	156		156		160
Regulatory assets and deferred debits
Regulatory assets	0		0		0
Other	(6)		(6)		(6)
Total regulatory assets and deferred debits	(6)		(6)		(6)
Total assets	(11,894)		(11,894)		(11,048)
Current liabilities
Notes payable and commercial paper	0		0		0
Current maturities of long-term debt	0		0		(1)
Notes payable to affiliated companies	(885)		(885)		(272)
Other	(96)		(96)		(63)
Total current liabilities	(981)		(981)		(336)
Long-term debt	0		0		0
Long-term debt, affiliate	(35)		(35)		(36)
Deferred credits and other liabilities
Deferred income taxes	(542)		(542)		(467)
Asset retirement obligations	0		0		0
Regulatory liabilities	157		157		160
Deferred credits and other liabilities	6		6		5
Total deferred credits and other liabilities	(379)		(379)		(302)
Preferred stock of subsidiaries	0		0		0
Equity
Common shareholders' equity	(10,499)		(10,499)		(10,374)
Noncontrolling interests	0		0		0
Total equity	(10,499)		(10,499)		(10,374)
Total liabilities and equity	(11,894)		(11,894)		(11,048)
Condensed Consolidating Statement of Cash Flows
Net cash provided (used) by operating activities			(483)	(928)
Cash flows from investing activities
Capital expenditures			0	0
Purchases of available-for-sale securities			0	0
Proceeds from sales and maturities of available-for-sale securities			1	0
Notes due from affiliate			614	84
Return of investment in consolidated subsidiaries			0	0
Contributions to consolidated subsidiaries			0	11
Other			0	(1)
Net cash provided (used) by investing activities			615	94
Cash flows from financing activities
Issuance of long-term debt			0	0
Issuance of common stock related to employee benefit plans			0	0
Payments for the redemption of long-term debt			0	0
Notes payable and commercial paper			0	0
Distributions to noncontrolling interests			(3)	(2)
Dividends paid			0	0
Dividends to parent			483	928
Dividends paid to parent in excess of retained earnings			0	0
Notes payable to affiliate			(613)	(84)
Contributions from parent			0	(11)
Other			1	3
Net cash provided (used) by financing activities			(132)	834
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	$ 0	$ 0

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Severance (Tables)

9 Months Ended

Sep. 30, 2012

Severance Cost Disclosure [Line Items]

Schedule Of Severance Costs Incurred [Text Block]

(in millions)	Three months ended September 30, 2012			Nine months ended September 30, 2012
Progress Energy		$	66		$	66
PEC			42			42
PEF			24			24

Schedule of Severance Liability

(in millions)	Balance at December 31, 2011		Provisions / Adjustments		Cash Reductions		Balance at September 30, 2012
Progress Energy	$	5	$	53	$	(15)	$	43
PEC		5		26		(7)		24
PEF		-		10		(3)		7

PEC [Member]

Severance Cost Disclosure [Line Items]

Schedule Of Severance Costs Incurred [Text Block]

(in millions)	Three months ended September 30, 2012			Nine months ended September 30, 2012
Progress Energy		$	66		$	66
PEC			42			42
PEF			24			24

Schedule of Severance Liability

(in millions)	Balance at December 31, 2011		Provisions / Adjustments		Cash Reductions		Balance at September 30, 2012
Progress Energy	$	5	$	53	$	(15)	$	43
PEC		5		26		(7)		24
PEF		-		10		(3)		7

PEF [Member]

Severance Cost Disclosure [Line Items]

Schedule Of Severance Costs Incurred [Text Block]

(in millions)	Three months ended September 30, 2012			Nine months ended September 30, 2012
Progress Energy		$	66		$	66
PEC			42			42
PEF			24			24

Schedule of Severance Liability

(in millions)	Balance at December 31, 2011		Provisions / Adjustments		Cash Reductions		Balance at September 30, 2012
Progress Energy	$	5	$	53	$	(15)	$	43
PEC		5		26		(7)		24
PEF		-		10		(3)		7

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New Accounting Standards

9 Months Ended

Sep. 30, 2012

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

Description Of New Accounting Pronouncements [Text Block]

16.       NEW ACCOUNTING STANDARDS

The following new accounting standards were adopted by the Progress Energy Registrants subsequent to September 30, 2011 and the impact of such adoption, if applicable, has been presented in the respective Consolidated Financial Statements of the Progress Energy Registrants:

ASC 220 — Comprehensive Income. In June 2011, the FASB amended the existing requirements for presenting comprehensive income in financial statements primarily to increase the prominence of items reported in other comprehensive income (OCI) and to facilitate the convergence of U.S. GAAP and International Financial Reporting Standards (IFRS). Specifically, the revised guidance eliminates the option previously provided to present components of OCI as part of the statement of changes in stockholders' equity. Accordingly, all non-owner changes in stockholders' equity are required to be presented either in a single continuous statement of comprehensive income or in two separate but consecutivefinancial statements. For the Progress Energy Registrants, this revised guidance was effective on a retrospective basis for interim and annual periods beginning January 1, 2012. The adoption of this standard changed the presentation of the Progress Energy Registrants' financial statements but did not affect the calculation of net income, comprehensive income or earnings per share.

ASC 820 — Fair Value Measurements and Disclosures. In May 2011, the FASB amended existing requirements for measuring fair value and for disclosing information about fair value measurements. This revised guidance results in a consistent definition of fair value, as well as common requirements for measurement and disclosure of fair value information between U.S. GAAP and IFRS. In addition, the amendments set forth enhanced disclosure requirements with respect to recurring Level 3 measurements, nonfinancial assets measured or disclosed at fair value, transfers between levels in the fair value hierarchy, and assets and liabilities disclosed but not recorded at fair value. For the Progress Energy Registrants, the revised fair value measurement guidance was effective on a prospective basis for interim and annual periods beginning January 1, 2012. The adoption of this new guidance did not have a significant impact on the Progress Energy Registrants' disclosures or their consolidated results of operations, cash flows, or financial position.

ASC 350 — Intangibles–Goodwill and Other. In September 2011, the FASB amended existing goodwill impairment testing accounting guidance to provide an entity testing goodwill for impairment with the option of performing a qualitative assessment prior to calculating the fair value of a reporting unit in step one of a goodwill impairment test. Under this revised guidance, a qualitative assessment would require an evaluation of economic, industry, and company-specific considerations. If an entity determines, on a basis of such qualitative factors, that the fair value of a reporting unit is more likely than not less than the carrying value of a reporting unit, then step one and if necessary, step two of the impairment test must be performed. Otherwise, no further impairment testing would berequired. The revised goodwill impairment testing accounting guidance was effective for the Progress Energy Registrants' annual and interim goodwill impairment tests performed for fiscal years beginning January 1, 2012. The adoption of this new guidance did not have a significant impact on the Progress Energy Registrants' disclosures or their consolidated results of operations, cash flows, or financial position.

The following new Accounting Standards Update (ASU) has been issued, but has not yet been adopted by the Progress Energy Registrants, as of September 30, 2012.

ASC 210—Balance Sheet. In December 2011, the FASB issued revised accounting guidance to amend the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve comparability of balance sheets prepared under U.S. GAAP and IFRS. The revised disclosure guidance affects all companies that have financial instruments and derivative instruments that are either offset in the balance sheet (i.e., presented on a net basis) or subject to an enforceable master netting arrangement and/or similar agreement. The revised guidance requires that certain enhanced quantitative and qualitative disclosures be made with respect to a company's netting arrangements and/or rights of setoff associated with its financial instrumentsand/or derivative instruments including associated collateral. For the Progress Energy Registrants, the revised disclosure guidance is effective on a retrospective basis for interim and annual periods beginning January 1, 2013. Other than additional disclosures, this revised guidance does not impact the consolidated results of operations, cash flows or financial position of Progress Energy.

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2012

Income Taxes Disclosure [Line Items]

Schedule of effective income tax rate reconciliation

	Three months ended September 30				Nine months ended September 30
	2012		2011		2012		2011
Progress Energy	32.8	%	37.8	%	34.7	%	36.9	%
PEC	31.9	%	33.4	%	31.6	%	34.2	%
PEF	35.9	%	37.0	%	36.9	%	37.0	%

Schedule of excise taxes [Tables]

	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
PEC	$	33	$	33	$	85	$	86
PEF		62		63		156		159
Progress Energy	$	95	$	96	$	241	$	245

PEC [Member]

Income Taxes Disclosure [Line Items]

Schedule of effective income tax rate reconciliation

	Three months ended September 30				Nine months ended September 30
	2012		2011		2012		2011
Progress Energy	32.8	%	37.8	%	34.7	%	36.9	%
PEC	31.9	%	33.4	%	31.6	%	34.2	%
PEF	35.9	%	37.0	%	36.9	%	37.0	%

Schedule of excise taxes [Tables]

	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
PEC	$	33	$	33	$	85	$	86
PEF		62		63		156		159
Progress Energy	$	95	$	96	$	241	$	245

PEF [Member]

Income Taxes Disclosure [Line Items]

Schedule of effective income tax rate reconciliation

	Three months ended September 30				Nine months ended September 30
	2012		2011		2012		2011
Progress Energy	32.8	%	37.8	%	34.7	%	36.9	%
PEC	31.9	%	33.4	%	31.6	%	34.2	%
PEF	35.9	%	37.0	%	36.9	%	37.0	%

Schedule of excise taxes [Tables]

	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
PEC	$	33	$	33	$	85	$	86
PEF		62		63		156		159
Progress Energy	$	95	$	96	$	241	$	245

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Significant Accounting Policies (Significant Accounting Policies)

9 Months Ended

Sep. 30, 2012

Policy Text Block [Line Items]

Basis of presentation

B.       BASIS OF PRESENTATION

These Unaudited Condensed Interim Financial Statements have been prepared in accordance with generally accepted accounting principles (GAAP) in the U.S. for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, these Unaudited Condensed Interim Financial Statements do not include all of the information and notes required by GAAP in the U.S. 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 Unaudited Condensed Interim Financial Statementsand Notes do not include all of the information and notes required by GAAP in the U.S. for annual financial statements, the Unaudited Condensed Interim Financial Statementsand other information included in this quarterly report should be read in conjunction with the respective Financial Statementsand Notes in the Progress Energy Registrants' combined Form 10-K for the year ended December 31, 2011 (2011 Form 10-K).

These Unaudited Condensed Interim Financial Statementsreflect all normal recurring adjustments that are, in the opinion of the respective companies' management, necessary to fairly present the financial position and results of operations of each Progress Energy Registrant. Amounts reported in the Progress Energy Registrants' Statements of Operations and Comprehensive Income are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, regulatory rulings, the timing of maintenance on electric generating units, changes in mark-to-market valuations, changing commodity prices and other factors.

The Unaudited Condensed Interim Financial Statements and Notes have been reclassified to conform with the Duke Energy format.

Consolidation of variable interest entities

VARIABLE INTEREST ENTITIES

A variable interest entity (VIE) is an entity that is evaluated for consolidation using more than a simple analysis of voting control. The analysis to determine whether an entity is a VIE considers contracts with an entity, credit support for an entity, the adequacy of the equity investment of an entity and the relationship of voting power to the amount of equity invested in an entity. This analysis is performed either upon the creation of a legal entity or upon the occurrence of an event requiring reevaluation, such as a significant change in the entity's assets or activities. If an entity is determined to be a VIE, a qualitative analysis of control determines the party that consolidates a VIE based on what party has the power to direct the most significant activities of the VIE that impact its economic performance as well as what party has rights to receive benefits or is obligated to absorb losses that are significant to the VIE. The analysis of the party that consolidates a VIE is a continual reassessment.

Use of estimates and assumptions

C.       USE OF ESTIMATES

To conform to GAAP in the U.S., management makes estimates and assumptions that affect the amounts reported in the Unaudited Condensed Interim Financial Statementsand Notes. Although these estimates are based on management's best available information at the time, actual results could differ.

Revenue recognition

D.       UNBILLED REVENUE

Revenues on sales of electricity are recognized when the service is provided to customers. Unbilled retail revenues are estimated by applying a weighted average revenue per kilowatt-hour for all customer classes to the number of estimated kilowatt-hours delivered but not billed. The amount of unbilled revenues can vary significantly from period to period as a result of numerous factors, including seasonality, weather, customer usage patterns and customer mix.

Excise taxes

EXCISE TAXES

Certain excise taxes levied by state or local governments are collected by the Utilities from their customers. Taxesthat are required to be paid regardless of the ability to collect from the customer are accounted for on a gross basis. When the Utilities act as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis.

PEC [Member]

Policy Text Block [Line Items]

Basis of presentation

B.       BASIS OF PRESENTATION

These Unaudited Condensed Interim Financial Statements have been prepared in accordance with generally accepted accounting principles (GAAP) in the U.S. for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, these Unaudited Condensed Interim Financial Statements do not include all of the information and notes required by GAAP in the U.S. 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 Unaudited Condensed Interim Financial Statementsand Notes do not include all of the information and notes required by GAAP in the U.S. for annual financial statements, the Unaudited Condensed Interim Financial Statementsand other information included in this quarterly report should be read in conjunction with the respective Financial Statementsand Notes in the Progress Energy Registrants' combined Form 10-K for the year ended December 31, 2011 (2011 Form 10-K).

These Unaudited Condensed Interim Financial Statementsreflect all normal recurring adjustments that are, in the opinion of the respective companies' management, necessary to fairly present the financial position and results of operations of each Progress Energy Registrant. Amounts reported in the Progress Energy Registrants' Statements of Operations and Comprehensive Income are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, regulatory rulings, the timing of maintenance on electric generating units, changes in mark-to-market valuations, changing commodity prices and other factors.

The Unaudited Condensed Interim Financial Statements and Notes have been reclassified to conform with the Duke Energy format.

Consolidation of variable interest entities

VARIABLE INTEREST ENTITIES

A variable interest entity (VIE) is an entity that is evaluated for consolidation using more than a simple analysis of voting control. The analysis to determine whether an entity is a VIE considers contracts with an entity, credit support for an entity, the adequacy of the equity investment of an entity and the relationship of voting power to the amount of equity invested in an entity. This analysis is performed either upon the creation of a legal entity or upon the occurrence of an event requiring reevaluation, such as a significant change in the entity's assets or activities. If an entity is determined to be a VIE, a qualitative analysis of control determines the party that consolidates a VIE based on what party has the power to direct the most significant activities of the VIE that impact its economic performance as well as what party has rights to receive benefits or is obligated to absorb losses that are significant to the VIE. The analysis of the party that consolidates a VIE is a continual reassessment.

Use of estimates and assumptions

C.       USE OF ESTIMATES

To conform to GAAP in the U.S., management makes estimates and assumptions that affect the amounts reported in the Unaudited Condensed Interim Financial Statementsand Notes. Although these estimates are based on management's best available information at the time, actual results could differ.

Revenue recognition

D.       UNBILLED REVENUE

Revenues on sales of electricity are recognized when the service is provided to customers. Unbilled retail revenues are estimated by applying a weighted average revenue per kilowatt-hour for all customer classes to the number of estimated kilowatt-hours delivered but not billed. The amount of unbilled revenues can vary significantly from period to period as a result of numerous factors, including seasonality, weather, customer usage patterns and customer mix.

Excise taxes

EXCISE TAXES

Certain excise taxes levied by state or local governments are collected by the Utilities from their customers. Taxesthat are required to be paid regardless of the ability to collect from the customer are accounted for on a gross basis. When the Utilities act as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis.

PEF [Member]

Policy Text Block [Line Items]

Basis of presentation

B.       BASIS OF PRESENTATION

These Unaudited Condensed Interim Financial Statements have been prepared in accordance with generally accepted accounting principles (GAAP) in the U.S. for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, these Unaudited Condensed Interim Financial Statements do not include all of the information and notes required by GAAP in the U.S. 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 Unaudited Condensed Interim Financial Statementsand Notes do not include all of the information and notes required by GAAP in the U.S. for annual financial statements, the Unaudited Condensed Interim Financial Statementsand other information included in this quarterly report should be read in conjunction with the respective Financial Statementsand Notes in the Progress Energy Registrants' combined Form 10-K for the year ended December 31, 2011 (2011 Form 10-K).

These Unaudited Condensed Interim Financial Statementsreflect all normal recurring adjustments that are, in the opinion of the respective companies' management, necessary to fairly present the financial position and results of operations of each Progress Energy Registrant. Amounts reported in the Progress Energy Registrants' Statements of Operations and Comprehensive Income are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, regulatory rulings, the timing of maintenance on electric generating units, changes in mark-to-market valuations, changing commodity prices and other factors.

The Unaudited Condensed Interim Financial Statements and Notes have been reclassified to conform with the Duke Energy format.

Consolidation of variable interest entities

VARIABLE INTEREST ENTITIES

A variable interest entity (VIE) is an entity that is evaluated for consolidation using more than a simple analysis of voting control. The analysis to determine whether an entity is a VIE considers contracts with an entity, credit support for an entity, the adequacy of the equity investment of an entity and the relationship of voting power to the amount of equity invested in an entity. This analysis is performed either upon the creation of a legal entity or upon the occurrence of an event requiring reevaluation, such as a significant change in the entity's assets or activities. If an entity is determined to be a VIE, a qualitative analysis of control determines the party that consolidates a VIE based on what party has the power to direct the most significant activities of the VIE that impact its economic performance as well as what party has rights to receive benefits or is obligated to absorb losses that are significant to the VIE. The analysis of the party that consolidates a VIE is a continual reassessment.

Use of estimates and assumptions

C.       USE OF ESTIMATES

To conform to GAAP in the U.S., management makes estimates and assumptions that affect the amounts reported in the Unaudited Condensed Interim Financial Statementsand Notes. Although these estimates are based on management's best available information at the time, actual results could differ.

Revenue recognition

D.       UNBILLED REVENUE

Revenues on sales of electricity are recognized when the service is provided to customers. Unbilled retail revenues are estimated by applying a weighted average revenue per kilowatt-hour for all customer classes to the number of estimated kilowatt-hours delivered but not billed. The amount of unbilled revenues can vary significantly from period to period as a result of numerous factors, including seasonality, weather, customer usage patterns and customer mix.

Excise taxes

EXCISE TAXES

Certain excise taxes levied by state or local governments are collected by the Utilities from their customers. Taxesthat are required to be paid regardless of the ability to collect from the customer are accounted for on a gross basis. When the Utilities act as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis.

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Organization and Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2012

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

Organization and Summary of Significant Accounting Policies

1.       ORGANIZATION ANDBASIS OF PRESENTATION

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 Energy Registrants” refers collectively to the three separate registrants: Progress Energy, PEC and PEF. The information in these combined notes relates to each of the Progress Energy Registrants as noted in the Index to Applicable Combined Notes to Unaudited Condensed Interim Financial Statements by Registrant. 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).On July 2, 2012, Progress Energy, Inc. consummated the merger with Duke Energy Corporation (Duke Energy), and became, and will continue as, a direct wholly owned subsidiary of Duke Energy.The total consideration transferred in the merger, based on the closing price of Duke Energy common shares on July 2, 2012, was $18 billion. The merger was recorded using the acquisition method of accounting, whereby the acquiree normally reflects the impact of the adjustments of assets and liabilities to fair value and the resultant goodwill on their financial statements. However, in accordance with SEC guidance, the Progress Energy Registrants did not reflect these adjustments based on the significance of the Progress Energy Registrants' outstanding public debt securities. See Note 2 for additional information regarding the merger.

Subsequent to the merger, our sole reportable segment is Franchised Electric, which is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. The remainder of our operations, including the Parent and Progress Energy Service Company (PESC) and other miscellaneous nonregulated businesses are presented as Other. See Note 3 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), the Public Service Commission of South Carolina (PSCSC), the United States Nuclear Regulatory Commission (NRC) and the FERC. As discussed further in Note 3, PEC's operations include one reportable segment, Franchised Electric.

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. As discussed further in Note 3, PEF's operations include one reportable segment, Franchised Electric.

B.       BASIS OF PRESENTATION

These Unaudited Condensed Interim Financial Statements have been prepared in accordance with generally accepted accounting principles (GAAP) in the U.S. for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, these Unaudited Condensed Interim Financial Statements do not include all of the information and notes required by GAAP in the U.S. 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 Unaudited Condensed Interim Financial Statementsand Notes do not include all of the information and notes required by GAAP in the U.S. for annual financial statements, the Unaudited Condensed Interim Financial Statementsand other information included in this quarterly report should be read in conjunction with the respective Financial Statementsand Notes in the Progress Energy Registrants' combined Form 10-K for the year ended December 31, 2011 (2011 Form 10-K).

These Unaudited Condensed Interim Financial Statementsreflect all normal recurring adjustments that are, in the opinion of the respective companies' management, necessary to fairly present the financial position and results of operations of each Progress Energy Registrant. Amounts reported in the Progress Energy Registrants' Statements of Operations and Comprehensive Income are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, regulatory rulings, the timing of maintenance on electric generating units, changes in mark-to-market valuations, changing commodity prices and other factors.

The Unaudited Condensed Interim Financial Statements and Notes have been reclassified to conform with the Duke Energy format.

C.       USE OF ESTIMATES

To conform to GAAP in the U.S., management makes estimates and assumptions that affect the amounts reported in the Unaudited Condensed Interim Financial Statementsand Notes. Although these estimates are based on management's best available information at the time, actual results could differ.

D.       UNBILLED REVENUE

Revenues on sales of electricity are recognized when the service is provided to customers. Unbilled retail revenues are estimated by applying a weighted average revenue per kilowatt-hour for all customer classes to the number of estimated kilowatt-hours delivered but not billed. The amount of unbilled revenues can vary significantly from period to period as a result of numerous factors, including seasonality, weather, customer usage patterns and customer mix.

Progress Energy, PEC and PEF had unbilled revenues within Receivables in their respective Balance Sheets as follows:

(in millions)	September 30, 2012		December 31, 2011
Progress Energy	$	190		$	157
PEC	$	99		$	102
PEF	$	91		$	55

XML

Unaudited Condensed Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Current assets
Cash and cash equivalents	$ 57	$ 230
Receivables	930	883
Receivables from affiliated companies	24	0
Notes receivable from affiliated companies	0	0
Inventory	1,366	1,429
Regulatory assets	226	275
Deferred tax assets	326	371
Prepayments and other current assets	97	132
Total current assets	3,026	3,320
Investments and other assets
Nuclear decommissioning trust funds	1,844	1,647
Goodwill	3,655	3,655
Intangibles	30	36
Other	502	468
Total investments and other assets	6,031	5,806
Property, plant and equipment
Cost	36,844	34,797
Cost, variable interest entities	16	16
Accumulated depreciation and amortization	(12,857)	(12,684)
Generation facilities to be retired, net	164	163
Net property, plant and equipment	24,167	22,292
Regulatory assets and deferred debits
Regulatory assets	3,331	3,424
Other	96	89
Total regulatory assets and deferred debits	3,427	3,513
Total assets	36,651	34,931
Current liabilities
Accounts payable	835	968
Payables to affiliated companies	29	0
Notes payable and commercial paper	0	671
Notes payable to affiliated companies	635	0
Taxes accrued	233	56
Interest accrued	187	200
Customer deposits	341	340
Derivative liabilities	209	382
Current maturities of long-term debt	838	961
Other	429	441
Total current liabilities	3,736	4,019
Long-term debt	12,664	11,918
Long-term debt, affiliate	274	273
Deferred credits and other liabilities
Deferred income taxes	2,509	2,193
Investment tax credits	97	103
Accrued pension and other post-retirement benefit costs	1,724	1,625
Asset retirement obligations	2,137	1,265
Regulatory liabilities	2,704	2,727
Other	560	690
Total deferred credits and other liabilities	9,731	8,603
Commitments and contingencies	0	0
Preferred stock of subsidiaries	93	93
Equity
Common stock	0	7,418
Additional paid-in capital	7,465	16
Retained earnings	2,751	2,752
Accumulated other comprehensive loss	(66)	(165)
Total common shareholders' equity	10,150	10,021
Noncontrolling interests	3	4
Total equity	10,153	10,025
Total liabilities and equity	36,651	34,931
PEC [Member]
Current assets
Cash and cash equivalents	19	20
Receivables	486	492
Receivables from affiliated companies	11	1
Inventory	749	770
Deferred tax assets	123	142
Prepayments and other current assets	70	84
Total current assets	1,458	1,509
Investments and other assets
Nuclear decommissioning trust funds	1,223	1,088
Other	216	210
Total investments and other assets	1,439	1,298
Property, plant and equipment
Cost	20,841	19,367
Cost, variable interest entities	16	16
Accumulated depreciation and amortization	(8,025)	(7,991)
Generation facilities to be retired, net	164	163
Net property, plant and equipment	12,996	11,555
Regulatory assets and deferred debits
Regulatory assets	1,762	1,682
Other	30	22
Total regulatory assets and deferred debits	1,792	1,704
Total assets	17,685	16,066
Current liabilities
Accounts payable	369	518
Payables to affiliated companies	52	29
Notes payable and commercial paper	0	188
Notes payable to affiliated companies	243	31
Taxes accrued	85	23
Interest accrued	71	77
Customer deposits	119	116
Derivative liabilities	79	123
Current maturities of long-term debt	403	502
Other	247	178
Total current liabilities	1,668	1,785
Long-term debt	4,435	3,704
Deferred credits and other liabilities
Deferred income taxes	2,091	1,903
Investment tax credits	94	98
Accrued pension and other post-retirement benefit costs	726	687
Asset retirement obligations	1,623	896
Regulatory liabilities	1,667	1,543
Other	284	303
Total deferred credits and other liabilities	6,485	5,430
Commitments and contingencies	0	0
Preferred stock	59	59
Equity
Common stock	2,159	2,148
Retained earnings	2,879	3,011
Accumulated other comprehensive loss	0	(71)
Total equity	5,038	5,088
Total liabilities and equity	17,685	16,066
PEF [Member]
Current assets
Cash and cash equivalents	20	16
Receivables	434	367
Receivables from affiliated companies	19	7
Inventory	618	659
Regulatory assets	214	244
Deferred tax assets	133	138
Prepayments and other current assets	44	37
Total current assets	1,482	1,468
Investments and other assets
Nuclear decommissioning trust funds	621	559
Other	187	142
Total investments and other assets	808	701
Property, plant and equipment
Cost	15,476	14,926
Accumulated depreciation and amortization	(4,594)	(4,474)
Net property, plant and equipment	10,882	10,452
Regulatory assets and deferred debits
Regulatory assets	1,446	1,629
Other	42	44
Total regulatory assets and deferred debits	1,488	1,673
Total assets	14,660	14,294
Current liabilities
Accounts payable	399	340
Payables to affiliated companies	25	14
Notes payable and commercial paper	0	233
Notes payable to affiliated companies	221	8
Taxes accrued	142	31
Interest accrued	59	54
Customer deposits	222	224
Derivative liabilities	130	220
Current maturities of long-term debt	435	10
Other	128	132
Total current liabilities	1,761	1,266
Long-term debt	4,237	4,671
Deferred credits and other liabilities
Deferred income taxes	1,541	1,325
Accrued pension and other post-retirement benefit costs	631	598
Asset retirement obligations	514	369
Regulatory liabilities	880	1,024
Other	217	332
Total deferred credits and other liabilities	3,783	3,648
Commitments and contingencies	0	0
Preferred stock	34	34
Equity
Common stock	1,762	1,757
Retained earnings	3,084	2,945
Accumulated other comprehensive loss	(1)	(27)
Total equity	4,845	4,675
Total liabilities and equity	$ 14,660	$ 14,294

XML

Variable Interest Entities

9 Months Ended

Sep. 30, 2012

Consolidation Of Variable Interest Entities [Abstract]

Variable Interest Entities Disclosure [Text Block]

11.VARIABLE INTEREST ENTITIES

A variable interest entity (VIE) is an entity that is evaluated for consolidation using more than a simple analysis of voting control. The analysis to determine whether an entity is a VIE considers contracts with an entity, credit support for an entity, the adequacy of the equity investment of an entity and the relationship of voting power to the amount of equity invested in an entity. This analysis is performed either upon the creation of a legal entity or upon the occurrence of an event requiring reevaluation, such as a significant change in the entity's assets or activities. If an entity is determined to be a VIE, a qualitative analysis of control determines the party that consolidates a VIE based on what party has the power to direct the most significant activities of the VIE that impact its economic performance as well as what party has rights to receive benefits or is obligated to absorb losses that are significant to the VIE. The analysis of the party that consolidates a VIE is a continual reassessment.

• CONSOLIDATED VIEs

The following table shows the VIE that Progress Energy, through its subsidiary PEC consolidates and how the entity impacts Progress Energy's and PEC's respective Consolidated Balance Sheets. No financial support was provided to the consolidated VIE during the nine months ended September 30, 2012 and the year ended 2011, or is expected to be provided in the future, that was not previously contractually required.

(in millions)		September 30, 2012		December 31, 2011
Net property, plant and equipment(a)		$	12	$	12
Prepayments and other current assets(a)			2		1
Net assets of consolidated VIEs		$	14	$	13
(a)	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. 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.

B.       NON-CONSOLIDATED VIEs

Progress Energy has variable interests in the FPC Capital I Trust (the Trust), which is a VIE of which we are not the primary beneficiary (See Note 17). Amounts reflected in the Consolidated Balance Sheets of Progress Energy related to the Trust are a $9 million equity investment (included in investments and other assets, other) at September 30, 2012 and December 31, 2011, and long-term debt, affiliate of $274 million and $273 million at September 30, 2012 and December 31, 2011, respectively. Our maximum exposure to loss that could potentially be recorded through earnings in future periods is the $9 million equity investment in the Trust.

PEC

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

PEF

PEF has no significant variable interests in VIEs.

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2012	Nov. 05, 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	Sep. 30, 2012
Amendment flag	false
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		100
Document fiscal year focus	2012
Document fiscal period focus	Q3
PEC [Member]
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 [Member]
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

XML

Benefit Plans

9 Months Ended

Sep. 30, 2012

Benefit Plans Disclosure [Line Items]

Benefit Plans

12.BENEFIT PLANS

COSTS OF BENEFIT PLANS

Net periodic benefit costs disclosed in the following tables for the qualified pension, non-qualified pension and other post-retirement benefit plans represent the cost of the respective benefit plan to the Progress Energy Registrants for the periods presented. However, portions of the net periodic benefit costs disclosed in the tables below have been capitalized as a component of property, plant and equipment.

Each of the Utilities participate in the qualified pension plans, non-qualified pension plans and other post-retirement benefit plans sponsored by Progress Energy. The net periodic benefit costs shown in the tables below represent their allocated cost of the respective benefit plan for the periods presented. Additionally, the Utilities are allocated their proportionate share of pension and other post-retirement benefit costs for PESC employees that provide support to the Utilities. These allocated amounts are included in the governance and shared services costs for the Utilities discussed in Note 15.

In conjunction with the merger,we offered a voluntary severance plan to certain employeesin November 2011. The voluntary severance plan included additional coverage of healthcare costs to certain eligible employees. The cost of the healthcare benefits are reflected in the tables below as special termination costs. See further discussion at Note13.

The components of the net periodic benefit cost for the respective Progress Energy Registrants for the three months ended September 30 were:

PROGRESS ENERGY
		Qualified					Non-Qualified			Other Post-Retirement
		Pension Plans				Pension Plans				Benefit Plans
(in millions)			2012		2011		2012		2011		2012		2011
Service cost		$	16	$	13	$	0	$	0	$	5	$	3
Interest cost on projected benefit obligation			32		33		2		2		11		10
Expected return on plan assets			(48)		(45)		0		0		0		0
Amortization of prior service cost (a)			2		2		0		0		0		0
Amortization net transition liability(a)			0		0		0		0		1		1
Amortization of actuarial loss(a)			24		15		1		1		10		3
Special termination costs			0		0		0		0		5		0
Other			1		0		0		0		0		0
	Net periodic cost	$	27	$	18	$	3	$	3	$	32	$	17
(a)	Adjusted to reflect PEF’s rate treatment. See Note 17B in the 2011 Form 10-K.
PEC
		Qualified					Non-Qualified			Other Post-Retirement
		Pension Plans				Pension Plans				Benefit Plans
(in millions)			2012		2011		2012		2011		2012		2011
Service cost		$	6	$	5	$	0	$	0	$	2	$	2
Interest cost on projected benefit obligation			15		15		1		1		6		5
Expected return on plan assets			(25)		(23)		0		0		0		0
Amortization of prior service cost			2		1		0		0		0		0
Amortization net transition liability			0		0		0		0		0		0
Amortization of actuarial loss			9		7		0		0		6		1
Special termination costs			0		0		0		0		2		0
Other			1		0		0		0		0		0
	Net periodic cost	$	8	$	5	$	1	$	1	$	16	$	8
PEF
		Qualified					Non-Qualified			Other Post-Retirement
		Pension Plans				Pension Plans				Benefit Plans
(in millions)			2012		2011		2012		2011		2012		2011
Service cost		$	8	$	6	$	0	$	0	$	2	$	1
Interest cost on projected benefit obligation			14		14		1		1		4		4
Expected return on plan assets			(21)		(19)		0		0		0		0
Amortization net transition liability			0		0		0		0		1		1
Amortization of actuarial loss			13		8		0		0		3		2
Special termination costs			0		0		0		0		1		0
	Net periodic cost	$	14	$	9	$	1	$	1	$	11	$	8

The components of the net periodic benefit cost for the respective Progress Energy Registrants for the nine months ended September 30 were:

PROGRESS ENERGY
			Qualified				Non-Qualified			Other Post-Retirement
			Pension Plans				Pension Plans					Benefit Plans
(in millions)			2012		2011		2012		2011			2012		2011
Service cost		$	47	$	39	$	1	$	1		$	12	$	8
Interest cost on projected benefit obligation			95		98		6		7			32		30
Expected return on plan assets			(141)		(136)		0		0			(1)		(1)
Amortization of prior service cost (a)			7		5		0		0			0		0
Amortization of net transition liability(a)			0		0		0		0			3		4
Amortization of actuarial loss(a)			69		47		3		2			25		9
Special termination cost			0		0		0		0			5		0
Other			1		0		0		0			0		0
	Net periodic cost	$	78	$	53	$	10	$	10		$	76	$	50
(a)	Adjusted to reflect PEF’s rate treatment. See Note 17B in the 2011 Form 10-K.
PEC
			Qualified				Non-Qualified				Other Post-Retirement
			Pension Plans				Pension Plans					Benefit Plans
(in millions)			2012		2011		2012		2011			2012		2011
Service cost		$	19	$	15	$	1	$	1		$	6	$	3
Interest cost on projected benefit obligation			43		46		1		1			17		15
Expected return on plan assets			(72)		(68)		0		0			0		0
Amortization of prior service cost			6		4		0		0			0		0
Amortization of net transition liability			0		0		0		0			0		1
Amortization of actuarial loss			28		19		1		0			14		4
Special termination cost			0		0		0		0			2		0
Other			1		0		0		0			0		0
	Net periodic cost	$	25	$	16	$	3	$	2		$	39	$	23
PEF
			Qualified				Non-Qualified				Other Post-Retirement
			Pension Plans				Pension Plans					Benefit Plans
(in millions)			2012		2011		2012		2011			2012		2011
Service cost		$	22	$	18	$	0	$	0		$	5	$	3
Interest cost on projected benefit obligation			42		43		2		2			13		13
Expected return on plan assets			(61)		(59)		0		0			(1)		(1)
Amortization of net transition liability			0		0		0		0			2		3
Amortization of actuarial loss			36		25		0		0			9		6
Special termination cost			0		0		0		0			1		0
	Net periodic cost	$	39	$	27	$	2	$	2		$	29	$	24

BENEFIT OBLIGATIONS

Upon consummation of the merger with Duke Energy, all defined benefit plan obligations were remeasured. Progress Energy, PEC and PEF updated the assumptions used to determine their accrued benefit obligations and prospective net periodic benefit costs. The weighted-average assumptions used to determine benefit obligations are as follows:

		Qualified Pension Benefits	Non-Qualified Pension Benefits	Other Post-Retirement Benefits
Discount rate		4.60%	4.60%	4.60%
Rate of increase in future compensation
	Bargaining	4.00%	N/A	N/A
	Supplementary plans	N/A	5.25%	N/A
Expected long-term rate of return on plan assets		8.00%	N/A	N/A

The salary increase for qualified pension benefits relates to bargaining employees only. Our primary defined benefit plan for non-bargaining employees is a “cash balance” plan that uses the traditional unit credit method for purposes of measuring the benefit obligation. Under the traditional unit credit method, no assumptions are included about future changes in compensation, and the accumulated benefit obligation and projected benefit obligation are the same.

The assumed health care cost trend ratesfor our otherpost-retirement benefit plans are as follows:

Health care cost trend rate assumed for 2012	8.75%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.00%
Year that the rate reaches the ultimate trend rate	2020

As a result of the remeasurement, we recorded net increases in our benefit obligations of $122 million, including $40 million for PEC and $75 million for PEF. These net increases were primarily offset by a $128 million increase in our regulatory assets, including $44 million for PEC and $75 million for PEF. In addition, $39 million of investments previously reported as plan assets of PEF's benefit plans were reclassified to investments and other assets, other in the Balance Sheets at September 30, 2012.

CONTRIBUTIONS

To date in 2012, we have made contributions directly to pension plan assets of approximately $146 million for us, including $71 million for PEC and $74 million for PEF. Our contributionsduring the nine months ended September 30, 2012 totaled $122 million, including $60 million for PEC and $61 million for PEF.Future amounts we contribute may be impacted by recently enacted legislation as well as other factors.

Additionally, we sponsor employee savings plans that cover substantially all employees. We made pre-tax employer contributions of $12 million and $12 million for the three months ended September 30, 2012 and 2011, respectively. We made pre-tax employer contributions of $35 million and $34 million for the nine months ended September 30, 2012 and 2011, respectively. The Utilities participate in our employee savings plans. The following table shows the respective expense related to their proportionate share of pre-tax employer contributions.

	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
PEC	$	7	$	6	$	18	$	18
PEF		4		4		11		11

XML

Unaudited Condensed Consolidated Balance Sheets (Parentheticals) (USD $) In Millions, except Share data, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Balance Sheets Parentheticals [Line Items]
Receivables, allowance for doubtful accounts	$ 13	$ 27
Par value	$ 0.01
Common shares, authorized	100	500,000,000
Common shares, issued	100	295,000,000
Common shares, outstanding	100	295,000,000
PEC [Member]
Balance Sheets Parentheticals [Line Items]
Receivables, allowance for doubtful accounts	8	9
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 [Member]
Balance Sheets Parentheticals [Line Items]
Receivables, allowance for doubtful accounts	$ 5	$ 18
Common shares, authorized	60,000,000	60,000,000
Common shares, issued	100	100
Common shares, outstanding	100	100

XML

Debt and Credit Facilities

9 Months Ended

Sep. 30, 2012

Debt And Credit Facilities Disclosure [Line Items]

Debt and Credit Facilities

6.DEBT AND CREDIT FACILITIES

Significant changes to the Progress Energy Registrants' debt and credit facilities since December 31, 2011, are as follows:

FIRST MORTGAGE BONDS

On May 18, 2012, PEC issued $500 million of 2.80% First Mortgage Bonds due May 15, 2022 and $500 million of 4.10% First Mortgage Bonds due May 15, 2042. The net proceeds were used to retire at maturity the $500 million outstanding aggregate principal balance of PEC's 6.50% Notes due July 15, 2012, and a portion of PEC's outstanding commercial paper and notes payable to affiliated companies.

OTHER DEBT

On March 8, 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.

AVAILABLE CREDIT FACILITIES

On July 2, 2012, the Parent terminated its $478 million RCA, and PEC and PEF terminated their respective $750 million RCAs and became borrowers under the Duke Energy Master Credit Facility (MCF). In November 2011, Duke Energy entered into a new $6.0 billion, five-year MCF,expiring in November 2016, with $4.0 billion available at closing and the remaining $2.0 billion available following consummation of the merger. In October 2012, Duke Energy reached an agreement with banks representing $5.63 billion of commitments under the MCF to extend the expiration date by one year to November 2017. Through November 2016, the available credit under this facility remains $6 billion. PEC and PEF each have borrowing capacity under the MCF up to $750 million. However, Duke Energy has the unilateral ability at any time to increase or decrease the borrowing sublimit of each borrower, subject to a maximum sublimit of $1.0 billion for PEC and PEF.Available capacity under the MCF for PEC and PEF has been reduced for certain amounts outstanding under the money pool arrangement described below. Available capacity for PEC and PEF as of September 30, 2012, was approximately $600 million for each utility. The Duke Energy MCF contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65% for each borrower, including PEC and PEF. Indebtedness as defined by the Duke Energy MCF includes certain letters of credit, surety bonds and guarantees not recorded in the Consolidated Balance Sheets. Following the merger, the cash needs of the Parent will be funded with dividends from the Utilities generated from their earnings and cash flows, and to a lesser extent, dividends from other subsidiaries; borrowings under an intercompany note with Duke Energy; and/or equity contributions from Duke Energy.

MONEY POOL

PEC, PEF and PESC receive support for their short-term borrowing needs through participation with Duke Energy and certain of its subsidiaries in a money pool arrangement. Under this arrangement, those companies with short-term funds may provide short-term loans to affiliates participating under this arrangement. The money pool is structured such that the participants separately manage their cash needs and working capital requirements. Accordingly, there is no net settlement of receivables and payables between the money pool participants. Per the terms of the money pool arrangement, the parent companies, including Duke Energy Corporation and Progress Energy, Inc., may loan funds to their participating subsidiaries, but may not borrow funds through the money pool.

Increases or decreases in money pool receivables are reflected within investing activities in the Progress Energy Registrants' Statements of Cash Flows, while increases or decreases in money pool borrowings are reflected within financing activities in the Progress Energy Registrants' Statements of Cash Flows.

CURRENT MATURITIES OF LONG-TERM DEBT

At September 30, 2012, PEC had $400 million of 5.125% First Mortgage Bonds due September 15, 2013 classified as current maturities of long-term debt in the Consolidated Balance Sheets. PEC expects to fund this obligation with proceeds from additional borrowings.

At September 30, 2012, PEF had $425 million of 4.80% First Mortgage Bonds due March 1, 2013 classified as current maturities of long-term debt in the Balance Sheets. PEF expects to fund this obligation with proceeds from additional borrowings.

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2012

Commitments And Contingencies Disclosure [Line Items]

Commitments and Contingencies

5.COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Notes 21 and 22 in the 2011 Form 10-K are described below.

A.ENVIRONMENTAL MATTERS

The Progress Energy Registrants are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.These regulations can be changed from time to time, imposing new obligations on the Progress Energy Registrants.

The following environmental matters impact all of the Progress Energy Registrants.

REMEDIATION ACTIVITIES

The Progress Energy Registrants are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing operations and sites formerly owned or used by Progress Energy entities. In some cases, Progress Energy no longer owns the property. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remediation requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Progress Energy Registrants could potentially be held responsible for contamination caused by other parties. In some instances, the Progress Energy Registrants may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. Reserves associated with remediation activities at certain sites have been recorded and it is anticipated that additional costs associated with remediation activities at certain sites will be incurred in the future. All of these sites generally are managed in the normal course of business or affiliate operations. The Progress Energy Registrants have accrued costs associated with remediation activities at some of their current and former sites, as well as other relevant environmental contingent liabilities. Management, in the normal course of business, continually assesses the nature and extent of known or potential environmentally related contingencies and records liabilities when losses become probable and are reasonably estimable. Costs associated with remediation activities within the Progress Energy Registrants' operations are typically expensed unless regulatory recovery of the costs is deemed probable.

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 deferred credits and other liabilitiesin the Balance Sheets. Amounts accrued and expenditures for environmental loss contingencies presented below are for the nine months endedSeptember 30, 2012 and 2011. Such amounts for the three months ended September 30, 2012 and 2011 were not material.

PROGRESS ENERGY
(in millions)		Total
Balance, December 31, 2011		$	23
Amount accrued for environmental loss contingencies			16
Expenditures for environmental loss contingencies			(7)
Balance, September 30, 2012(a)		$	32
Balance, December 31, 2010		$	35
Amount accrued for environmental loss contingencies			7
Expenditures for environmental loss contingencies			(17)
Balance, September 30, 2011(a)		$	25
(a)	Expected to be paid out over one to 12 years.
PEC
(in millions)		Total
Balance, December 31, 2011		$	11
Amount accrued for environmental loss contingencies			4
Expenditures for environmental loss contingencies			(2)
Balance, September 30, 2012(a)		$	13
Balance, December 31, 2010		$	12
Amount accrued for environmental loss contingencies			-
Expenditures for environmental loss contingencies			(1)
Balance, September 30, 2011(a)		$	11
(a)	Expected to be paid out over one to ten years.
PEF
(in millions)		Total
Balance, December 31, 2011		$	12
Amount accrued for environmental loss contingencies			12
Expenditures for environmental loss contingencies			(5)
Balance, September 30, 2012(a)		$	19
Balance, December 31, 2010		$	23
Amount accrued for environmental loss contingencies			7
Expenditures for environmental loss contingencies			(16)
Balance, September 30, 2011(a)		$	14
(a)	Expected to be paid out over one to 12 years.

PEC

PEC's accruals relate to one former manufactured gas plant (MGP) site and other sites associated with PEC that have required, or are anticipated to require, investigation and/or remediation. Remediation of PEC's other MGP sites has been substantially completed. During the nine months ended September 30, 2012,PEC completed a preliminary remedial action plan for its remaining MGP site, which indicates a range of viable remedial approaches with estimated costs up to $25 million. PEC has accrued approximately $7 million to reflect the estimated cost for the remedial approach considered to have more merit. 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.

PEF

PEF's accruals 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 September 30, 2012,PEF's accrual primarily relates to an MGP site located in Orlando, Fla. The potentially responsible parties (PRPs) for the Orlando MGP site have agreed to an interim allocation for the Orlando MGP site and are 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. During the nine months ended September 30, 2012,the PRPs received refined estimates for the range of viable remedial approaches. Additionally, the PRPs believe one approach has more merit than the other approaches; however, the recommendation has not been submitted to or approved by the United StatesEnvironmental Protection Agency (EPA) at this time. The PRPs for the Orlando MGP site intend 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 remedial approachconsidered to have more merit and its current allocation share, PEF accrued additional obligations of approximately $9 million during the nine months ended September 30, 2012, for remediation of soil and groundwater down to 50 feet. 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 $8 million for remediation of soil and groundwater down to 50 feet. Results of an investigative study revealed the presence of MGP byproduct material at least 200 feet below 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.

CLEAN WATER ACT 316(b)

The EPA published its proposed cooling water intake structures rule on April 20, 2011. The proposed rule advances one main approach and three alternatives. The main approach establishes aquatic protection requirements for existing facilities and new on-site facility additions that withdraw 2 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Based on the main approach proposed, most, if not all of the coal, natural gas and nuclear-fueled steam electric-generating facilities in which the Progress Energy Registrants are either a whole or partial owner are likely affected sources unless retired prior to implementation of the 316(b) rule requirements. Additional sources, including some combined-cycle combustion turbine facilities may also be impacted, at least for intake modifications.

The EPA recently modified a previous settlement agreement that now calls for the EPA to finalize the 316(b) rule by June 2013. Compliance with portions of the rule could begin as early as 2016. Because of the wide range of potential outcomes, including the other three alternative proposals, the Progress Energy Registrants are unable to estimate their costs to comply at this time.

COAL COMBUSTIONRESIDUALS (CCR) MANAGEMENT

On June 21, 2010, the EPA issued a proposal to regulate, under the Resource Conservation and Recovery Act, CCRs, a term the EPA uses to describe the coal combustion products associated with the generation of electricity. The EPA proposal contains two regulatory options whereby CCRs not employed in approved beneficial use applications would either be regulated as hazardous waste or would continue to be regulated as non-hazardous waste. We cannot predict the outcome of this rulemaking. However, based on the proposal, the cost of complying with the final regulation will be material. The timing of a final rule is uncertain. In response to a motion filed in federal court by environmental groups asking the court to compel the EPA to issue a final rule, the EPA filed a declaration on October 11, 2012, suggesting that it could take more than a year to complete the regulation.

CROSS-STATE AIR POLLUTION RULE (CSAPR)

On August 8, 2011, the final CSAPR was published in the Federal Register. The CSAPR established state-level annual SO2 and NOx budgets that were to take effect on January 1, 2012, and state-level ozone-season NOx budgets that were to take effect on May 1, 2012, allocating emission allowances to affected sources in each state equal to the state budget less an allowance set-aside for new sources. The budget levels were set to decline in 2014 for many states, including North Carolina. In South Carolina and Florida, the budgets were to remain constant. The rule allowed both intrastate and limited interstate allowance trading.

Numerous petitions for review of the CSAPR were filed with the United States Court of Appeals for the District of Columbia(D.C. Court of Appeals). On August 21, 2012, by a 2-1 decision, the D.C. Court of Appealsvacated the CSAPR. The court also directed the EPA to continue administering the Clean Air Interstate Rule (CAIR) that the Progress Energy Registrants have been complying with since 2009 pending completion of a remand rulemaking to replace CSAPR with a valid rule. CAIR requires additional Phase II reductions in SO2 and NOx emissions beginning in 2015. The court's decision to vacate the CSAPR leaves the future of the rule uncertain.The EPA has filed a petition with the D.C. Court of Appeals for en banc rehearing of the CSAPR decision. If the court's August 21, 2012 decision is upheld, the CAIR will remain in force for an unknown period of time until EPA develops a replacement rule. If the decision is overturned on rehearing, it is not known when EPA would move to implement the CSAPR.

The Progress Energy Registrants cannot predict the outcome of the rehearing process or how it couldaffect future emission reduction requirements that might apply to the Progress Energy Registrants as a result of a potential CSAPR replacement rulemaking. The continued implementation of the CAIR pending the outcome of the rehearing process and a potential CSAPR replacement rulemaking, including the potential implementation of CAIR Phase II in 2015, will not result in the Progress Energy Registrants adding new emission controls.

MERCURYAND AIR TOXICS STANDARDS (MATS)

The final Mercury and Air Toxics Standards rule (previously referred to as the Utility maximum achievable control technology (MACT) Rule) was published in the Federal Register on February 16, 2012. The final rule establishes emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The rule requires sources to comply with the emission limits by April 16, 2015. Under the Clean Air Act, permitting authorities have the discretion to grant up to a 1-year compliance extension, on a case-by-case basis, to sources that are unable to complete the installation of emission controls before the compliance deadline. The Progress Energy Registrants continue to evaluate the requirements of the rule and develop strategies for complying with the rule's requirements. Strategies to achieve compliance with the final MATS rule are likely to include installing new or upgrading existing air emission control equipment, developing monitoring processes and accelerating retirement of some coal-fired electric generating units. Due to significant investments in nitrogen oxides (NOx) and sulfur dioxide (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. For additional information, refer to Note 4.

Numerous petitions for review of the final MATS rule have been filed with the D.C. Court of Appeals. The court established a schedule for the litigation that has final briefs being filed on April 8, 2013. The Progress Energy Registrants cannot predict the outcome of the litigation or how it might affect the MATS requirements as they apply to the Progress Energy Registrants.

As finalized, the cost to the Progress Energy Registrants to comply with the regulation will be material.

CLEAN AIR VISIBILITY RULE (CAVR)

The EPA's Clean Air Visibility Rule (CAVR) is an implementing regulation in its Regional Haze program that requires states to identify facilities, including power plants, built between August 1962 and August 1977 with the potential to produce emissions that affect visibility in certain specially protected areas, including national parks and wilderness areas, designated as Class I areas. To help restore visibility in those areas, states must require the identified facilities to install best available retrofit technology (BART) to control their emissions. PEF's BART-eligible units are Anclote and CR1 and CR2. Under an agreement with the Florida Department of Environmental Protection (FDEP) that is reflected in a BART permit issued in final form on October 10, 2012, PEF will either retire its Crystal River Units No. 1 and No. 2 coal-fired steam turbines (CR1 and CR2) as coal-fired units by December 31, 2020 or install pollution control equipment by January 1, 2018. In addition, PEF will convert Anclote to 100 percent natural gas.

The FDEP is working with the EPA to complete development of an approvable regional haze state implementation plan by July 5, 2013, which is consistent with the BART permit issued by the FDEP on October 10, 2012. The outcome of these matters cannot be predicted.

EPA GREENHOUSE GAS NEW SOURCE PERFORMANCE STANDARDS (NSPS)

On April 13, 2012, the EPA published in the Federal Register its proposed rule to establish carbon dioxide (CO2) emissions standards for pulverized coal, integrated gasification combined cycle, and natural gas combined cycle electric-generating units that are permitted and constructed in the future. The proposal would not apply to any of the Progress Energy Registrants' coal and natural gas electric generation plants that are currently under construction or in operation. Any future pulverized coal and integrated gasification combined cycle units will have to employ carbon capture and storage technology to meet the CO2 emission standard the EPA has proposed. The proposed standard will not require new natural gas combined cycle facilities to install carbon capture and storage technology.

Management does not expect any material impact on the Progress Energy Registrants' future results of operations or cash flows based on the EPA's proposal. The final rule, however, could be significantly different from the proposal. It is not known when the EPA might finalize the rule.

ESTIMATED COST AND IMPACTS OF EPA RULEMAKINGS

While the ultimate compliance requirements for the Progress Energy Registrants for MATS, Clean Water Act 316(b) and CCRs will not be known until all the rules have been finalized, for planning purposes, we currently estimate that if the decision is made to retire PEF's CR1 and CR2, MATS compliance costs at the Utilities could range from $150 million to $320 million. If the units are not retired, PEF's MATS compliance costs could exceed $1 billion. The Progress Energy Registrants also expect to incur increased fuel, purchased power, operation and maintenance, and other expenses in conjunction with these EPA regulations, and also expect to incur costs for replacement generation for potential coal-fired power plant retirements. Until the final regulatory requirements of the group of EPA regulations are known and can be fully evaluated, the potential compliance costs associated with these EPA regulatory actions are subject to considerable uncertainty. Therefore, the actual compliance costs incurred may be materially different from these estimates based on the timing and requirements of the final EPA regulations.

The Progress Energy Registrants intend to seek regulatory recovery of amounts incurred associated with regulated operations in complying with these regulations. Refer to Note 4 for further information regarding potential plant retirements and related regulatory filings.

B.        LITIGATION

MERGER

On August 3, 2012, Duke Energy was served with a shareholder Derivative Complaint, which has been transferred to the North Carolina Business Court (Krieger v. Johnson, et al). The lawsuit names as defendants, William D. Johnson, James E. Rogers and the Legacy Duke Energy Directors. Duke Energy is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duty in granting excessive compensation to Mr. Johnson. We cannot predict the outcome of this matter.

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 assertingdamages incurred through 2005. In 2011, 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 in 2011 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 $113 million of damages with the U.S. Court of Federal Claims and the DOE.The total amount of damages could change during discovery, which is set to end on May 31, 2013. The Utilities may file subsequent damage claims as they incur additional costs.The next status conference to discuss trial dates is scheduled for May 10, 2013. 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 29tax 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 represented payment of the total judgment and a required premium equivalent to two years of interest at the then statutory rate, to the Broward County Clerk of Court bond account. The appellate briefing process has been completed. Oral argument on the appeal was held on September 27, 2011.On October 3, 2012, the Florida appellate court reversed the trial court ruling and directed a verdict on damages. The case was remanded to the trial court to determine whether specific performance is an appropriate remedy. On October 18, 2012, Global filed a Motion for Clarification and Rehearing of Panel Decision, which has yet to be ruled upon. On November 1, 2012, we filed a response in opposition to U.S. Global's motion. 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 April 17, 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 outcome of 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.

C.       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 September 30, 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 September 30, 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 September 30, 2012, our estimated maximum exposure for guarantees and indemnifications for which a maximum exposure is determinable was $219 million, including $45 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 September 30, 2012 and December 31, 2011, we had recorded liabilities related to guarantees and indemnifications to third parties of $28million and $63 million, respectively. These amounts included $20 million and $37 million for PEF at September 30, 2012 and December 31, 2011, respectively. Our liabilities decreased primarilydue to the reversal of certain environmental indemnification liabilities for which the indemnification period has expired (See Note 2) and the adjustment to the indemnification for the estimated future years' joint owner replacement power costs related to the CR3outage (See Note 8C of the 2011 Form 10-K). PEF's liabilities decreased primarily due to the previously mentioned indemnification adjustment related to CR3. During the three and ninemonths ended September 30, 2012, our and the Utilities' accruals and expenditures related to guarantees and indemnifications were not material. As current estimates change, 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 17).

D.        OTHER COMMITMENTS AND CONTINGENCIES

As part of its normal business, the Progress Energy Registrants enter into various fixed-price, non-cancelable commitments to purchase or sell power (tolling agreements or power purchase contracts), take-or-pay arrangements, transportation or throughput agreements and other contracts that may or may not be recognized in the respective Balance Sheets. Some of these arrangements may be recognized at fair value in the respective Balance Sheets if such contracts meet the definition of a derivative and the normal purchase normal sale (NPNS) exception does not apply.

During the three and nine months ended September 30, 2012, there were no material changes in the Progress Energy Registrants' other commitments and contingencies other than as follows:

PEC

As described in Note 22A in the 2011 Form 10-K, PEC entered into conditional agreements for firm pipeline transportation capacity to support PEC's gas supply needs. As the transactions are subject to several conditions precedent, the estimated costs associated with these agreements were not included in PEC's fuel commitments at December 31, 2011. The estimated total cost to PEC associated with these agreements at December 31, 2011, was approximately $1.510billion, approximately $380 million of which relates to a capital lease. The agreements pertain to the period from July 2012 through May 2033. During the nine months ended September 30, 2012, the conditions precedent for two of the agreements, including the capital lease agreement, were satisfied. The agreementsare through 2032 and have an estimated total cost of approximately $1.030 billion, including $20 million, $103 million, $103 million and $804 million, respectively, for less than one year, one to three years, three to five years and more than five years from December 31, 2011.

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Condensed Consolidating Statements

9 Months Ended

Sep. 30, 2012

Condensed Consolidating Statements Disclosure [Abstract]

Condensed consolidating financials

17.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 ITrust 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 these entities 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.

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

Presented below are the condensed consolidating Statements of Operations and Comprehensive Income, Balance Sheets and Statements of 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 Operations and Comprehensive Income
Three months ended September 30, 2012
(in millions)			Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
Operating revenues
	Regulated electric		$	0	$	1,382	$	1,394	$	(1)	$	2,775
	Non-regulated electric and other			0		10		4		(1)		13
		Total operating revenues		0		1,392		1,398		(2)		2,788
Operating expenses
	Fuel used in electric generation and purchased power			0		799		597		0		1,396
	Operation, maintenance and other			0		247		378		1		626
	Depreciation and amortization			0		39		135		0		174
	Property and other taxes			0		100		63		(3)		160
	Impairment charges			0		0		55		0		55
		Total operating expenses		0		1,185		1,228		(2)		2,411
Gains on sales of other assets and other, net				0		1		1		0		2
Operating income				0		208		171		0		379
Equity in earnings of consolidated subsidiaries				203		0		0		(203)		0
Other income and expenses, net				(1)		12		23		(2)		32
Interest expense, net				63		67		53		(1)		182
Income from continuing operations before income taxes				139		153		141		(204)		229
Income tax (benefit) expense from continuing operations				(16)		55		43		(7)		75
Income from continuing operations				155		98		98		(197)		154
Income from discontinued operations, net of tax				0		2		1		0		3
Net income				155		100		99		(197)		157
Less: Net income attributable to noncontrolling interests				0		1		0		1		2
Net income attributable to Duke Energy Corporation			$	155	$	99	$	99	$	(198)	$	155
Comprehensive income, net of tax
	Comprehensive income		$	253	$	118	$	170	$	(286)	$	255
	Comprehensive income attributable to noncontrolling interests, net of tax			0		(1)		0		(1)		(2)
		Comprehensive income attributable to Duke Energy Corporation	$	253	$	117	$	170	$	(287)	$	253

Condensed Consolidating Statement of Operations and Comprehensive Income
Three months ended September 30, 2011
(in millions)			Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
Operating revenues
	Regulated electric		$	0	$	1,414	$	1,330	$	(1)	$	2,743
	Non-regulated electric and other			0		9		2		(1)		10
		Total operating revenues		0		1,423		1,332		(2)		2,753
Operating expenses
	Fuel used in electric generation and purchased power			0		690		544		0		1,234
	Operation, maintenance and other			2		225		265		2		494
	Depreciation and amortization			0		39		136		0		175
	Property and other taxes			0		106		58		0		164
		Total operating expenses		2		1,060		1,003		2		2,067
Gains on sales of other assets and other, net				0		1		0		0		1
Operating (loss) income				(2)		364		329		(4)		687
Equity in earnings of consolidated subsidiaries				391		0		0		(391)		0
Other income and expenses, net				(63)		2		14		3		(44)
Interest expense, net				80		52		41		(1)		172
Income from continuing operations before income taxes				246		314		302		(391)		471
Income tax (benefit) expense from continuing operations				(45)		116		103		4		178
Income from continuing operations				291		198		199		(395)		293
Income (loss) from discontinued operations, net of tax				0		1		(1)		0		0
Net income				291		199		198		(395)		293
Less: Net income attributable to noncontrolling interests				0		1		0		1		2
Net income attributable to Duke Energy Corporation			$	291	$	198	$	198	$	(396)	$	291
Comprehensive income, net of tax
	Comprehensive income		$	226	$	182	$	165	$	(345)	$	228
	Comprehensive income attributable to noncontrolling interests, net of tax			0		(1)		0		(1)		(2)
		Comprehensive income attributable to Duke Energy Corporation	$	226	$	181	$	165	$	(346)	$	226

Condensed Consolidating Statement of Operations and Comprehensive Income
Nine months ended September 30, 2012
(in millions)			Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
Operating revenues
	Regulated electric		$	0	$	3,576	$	3,561	$	(2)	$	7,135
	Non-regulated electric and other			0		26		17		0		43
		Total operating revenues		0		3,602		3,578		(2)		7,178
Operating expenses
	Fuel used in electric generation and purchased power			0		1,849		1,450		0		3,299
	Operation, maintenance and other			4		668		1,120		6		1,798
	Depreciation and amortization			0		158		413		0		571
	Property and other taxes			0		272		175		(7)		440
	Impairment charges			0		0		55		0		55
		Total operating expenses		4		2,947		3,213		(1)		6,163
Gains on sales of other assets and other, net				0		2		2		0		4
Operating (loss) income				(4)		657		367		(1)		1,019
Equity in earnings of consolidated subsidiaries				489		0		0		(489)		0
Other income and expenses, net				8		32		58		(1)		97
Interest expense, net				193		210		157		0		560
Income from continuing operations before income taxes				300		479		268		(491)		556
Income tax (benefit) expense from continuing operations				(68)		177		88		(4)		193
Income from continuing operations				368		302		180		(487)		363
Income from discontinued operations, net of tax				0		10		0		0		10
Net income				368		312		180		(487)		373
Less: Net income attributable to noncontrolling interests				0		3		0		2		5
Net income attributable to Duke Energy Corporation			$	368	$	309	$	180	$	(489)	$	368
Comprehensive income, net of tax
	Comprehensive income		$	467	$	331	$	250	$	(576)	$	472
	Comprehensive income attributable to noncontrolling interests, net of tax			0		(3)		0		(2)		(5)
		Comprehensive income attributable to Duke Energy Corporation	$	467	$	328	$	250	$	(578)	$	467

Condensed Consolidating Statement of Operations and Comprehensive Income
Nine months ended September 30, 2011
(in millions)			Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
Operating revenues
	Regulated electric		$	0	$	3,639	$	3,524	$	(2)	$	7,161
	Non-regulated electric and other			0		24		11		0		35
		Total operating revenues		0		3,663		3,535		(2)		7,196
Operating expenses
	Fuel used in electric generation and purchased power			0		1,804		1,382		0		3,186
	Operation, maintenance and other			6		659		829		6		1,500
	Depreciation and amortization			0		112		396		0		508
	Property and other taxes			0		274		168		(5)		437
		Total operating expenses		6		2,849		2,775		1		5,631
Gains on sales of other assets and other, net				0		2		0		0		2
Operating (loss) income				(6)		816		760		(3)		1,567
Equity in earnings of consolidated subsidiaries				832		0		0		(832)		0
Other income and expenses, net				(59)		25		54		1		21
Interest expense, net				216		193		134		(1)		542
Income from continuing operations before income taxes				551		648		680		(833)		1,046
Income tax (benefit) expense from continuing operations				(100)		240		243		3		386
Income from continuing operations				651		408		437		(836)		660
Loss from discontinued operations, net of tax				0		(2)		(2)		0		(4)
Net income				651		406		435		(836)		656
Less: Net income attributable to noncontrolling interests				0		3		0		2		5
Net income attributable to Duke Energy Corporation			$	651	$	403	$	435	$	(838)	$	651
Comprehensive income, net of tax
	Comprehensive income		$	569	$	384	$	393	$	(772)	$	574
	Comprehensive income attributable to noncontrolling interests, net of tax			0		(3)		0		(2)		(5)
		Comprehensive income attributable to Duke Energy Corporation	$	569	$	381	$	393	$	(774)	$	569

Condensed Consolidating Balance Sheet
September 30, 2012
(in millions)			Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
ASSETS
Current assets
	Cash and cash equivalents		$	0	$	38	$	19	$	0	$	57
	Receivables, net			0		435		495		0		930
	Notes receivable from affiliated companies			676		0		209		(885)		0
	Inventory			0		618		749		(1)		1,366
	Prepayments and other current assets			59		417		293		(96)		673
		Total current assets		735		1,508		1,765		(982)		3,026
Investments and other assets
	Nuclear decommissioning trust funds			0		621		1,223		0		1,844
	Investment in consolidated subsidiaries			14,171		0		0		(14,171)		0
	Goodwill			0		0		0		3,655		3,655
	Other			151		232		695		(546)		532
		Total investments and other assets		14,322		853		1,918		(11,062)		6,031
Net property, plant and equipment				0		10,885		13,126		156		24,167
Regulatory assets and deferred debits
	Regulatory assets			0		1,446		1,885		0		3,331
	Other			23		49		30		(6)		96
		Total regulatory assets and deferred debits		23		1,495		1,915		(6)		3,427
		Total assets	$	15,080	$	14,741	$	18,724	$	(11,894)	$	36,651
LIABILITIES AND EQUITY
Current liabilities
	Current maturities of long-term debt		$	0	$	435	$	403	$	0	$	838
	Notes payable to affiliated companies			843		431		246		(885)		635
	Other			75		1,120		1,164		(96)		2,263
		Total current liabilities		918		1,986		1,813		(981)		3,736
Long-term debt				3,992		4,237		4,435		0		12,664
Long-term debt, affiliate				0		309		0		(35)		274
Deferred credits and other liabilities
	Deferred income taxes			0		960		2,091		(542)		2,509
	Asset retirement obligations			0		514		1,623		0		2,137
	Regulatory liabilities			0		880		1,667		157		2,704
	Other			20		923		1,432		6		2,381
		Total deferred credits and other liabilities		20		3,277		6,813		(379)		9,731
Preferred stock of subsidiaries				0		34		59		0		93
Equity
	Common shareholders' equity			10,150		4,895		5,604		(10,499)		10,150
	Noncontrolling interests			0		3		0		0		3
		Total equity		10,150		4,898		5,604		(10,499)		10,153
Total liabilities and equity			$	15,080	$	14,741	$	18,724	$	(11,894)	$	36,651

Condensed Consolidating Balance Sheet
December 31, 2011
(in millions)			Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
ASSETS
Current assets
	Cash and cash equivalents		$	117	$	92	$	21	$	0	$	230
	Receivables, net			0		367		516		0		883
	Notes receivable from affiliated companies			53		0		219		(272)		0
	Inventory			0		659		770		0		1,429
	Prepayments and other current assets			127		418		297		(64)		778
		Total current assets		297		1,536		1,823		(336)		3,320
Investments and other assets
	Nuclear decommissioning trust funds			0		559		1,088		0		1,647
	Investment in consolidated subsidiaries			14,043		0		0		(14,043)		0
	Goodwill			0		0		0		3,655		3,655
	Other			118		189		675		(478)		504
		Total investments and other assets		14,161		748		1,763		(10,866)		5,806
Net property, plant and equipment				0		10,455		11,677		160		22,292
Regulatory assets and deferred debits
	Regulatory assets			0		1,629		1,795		0		3,424
	Other			22		51		22		(6)		89
		Total regulatory assets and deferred debits		22		1,680		1,817		(6)		3,513
		Total assets	$	14,480	$	14,419	$	17,080	$	(11,048)	$	34,931
LIABILITIES AND EQUITY
Current liabilities
	Notes payable and commercial paper		$	250	$	233	$	188	$	0	$	671
	Current maturities of long-term debt			450		10		502		(1)		961
	Notes payable to affiliated companies			0		238		34		(272)		0
	Other			199		1,030		1,221		(63)		2,387
		Total current liabilities		899		1,511		1,945		(336)		4,019
Long-term debt				3,543		4,671		3,704		0		11,918
Long-term debt, affiliate				0		309		0		(36)		273
Deferred credits and other liabilities
	Deferred income taxes			0		757		1,903		(467)		2,193
	Asset retirement obligations			0		369		896		0		1,265
	Regulatory liabilities			0		1,024		1,543		160		2,727
	Other			17		1,012		1,384		5		2,418
		Total deferred credits and other liabilities		17		3,162		5,726		(302)		8,603
Preferred stock of subsidiaries				0		34		59		0		93
Equity
	Common shareholders' equity			10,021		4,728		5,646		(10,374)		10,021
	Noncontrolling interests			0		4		0		0		4
		Total equity		10,021		4,732		5,646		(10,374)		10,025
Total liabilities and equity			$	14,480	$	14,419	$	17,080	$	(11,048)	$	34,931

Condensed Consolidating Statement of Cash Flows
Nine months ended September 30, 2012
(in millions)		Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
Net cash provided by operating activities		$	335	$	733	$	865	$	(483)	$	1,450
Investing activities
Capital expenditures			0		(573)		(1,122)		0		(1,695)
Purchases of available-for-sale securities			0		(562)		(385)		0		(947)
Proceeds from sales and maturities of available-for-sale securities			0		561		359		1		921
Notes due from affiliate			(624)		0		10		614		0
Other			24		13		75		0		112
Net cash used by investing activities			(600)		(561)		(1,063)		615		(1,609)
Financing activities
Proceeds from the:
	Issuance of long-term debt		444		0		988		0		1,432
	Issuance of common stock related to employee benefit plans		6		0		0		0		6
Payments for the redemption of long-term debt			(450)		(9)		(502)		0		(961)
Notes payable and commercial paper			(250)		(233)		(188)		0		(671)
Distributions to noncontrolling interests			0		(3)		0		(3)		(6)
Dividends paid			(445)		0		0		0		(445)
Dividends paid to parent			0		(173)		(310)		483		0
Notes payable to affiliate			843		193		212		(613)		635
Other			0		(1)		(4)		1		(4)
Net cash provided (used) by financing activities			148		(226)		196		(132)		(14)
Net decrease in cash and cash equivalents			(117)		(54)		(2)		0		(173)
Cash and cash equivalents at beginning of period			117		92		21		0		230
Cash and cash equivalents at end of period		$	0	$	38	$	19	$	0	$	57

Condensed Consolidating Statement of Cash Flows
Nine months ended September 30, 2011
(in millions)		Parent		Subsidiary Guarantor		Non-Guarantor Subsidiaries		Other		Progress Energy, Inc.
Net cash provided by operating activities		$	659	$	664	$	863	$	(928)	$	1,258
Investing activities
Capital expenditures			0		(626)		(1,021)		0		(1,647)
Purchases of available-for-sale securities			0		(4,099)		(438)		0		(4,537)
Proceeds from sales and maturities of available-for-sale securities			0		4,101		408		0		4,509
Notes due from affiliate			(83)		22		(23)		84		0
Contributions to consolidated subsidiaries			(11)		0		0		11		0
Other			(6)		102		5		(1)		100
Net cash used by investing activities			(100)		(500)		(1,069)		94		(1,575)
Financing activities
Proceeds from the:
	Issuance of long-term debt		494		296		496		0		1,286
	Issuance of common stock related to employee benefit plans		42		0		0		0		42
Payments for the redemption of long-term debt			(700)		(309)		(1)		0		(1,010)
Notes payable and commercial paper			45		0		0		0		45
Distributions to noncontrolling interests			0		(4)		0		(2)		(6)
Dividends paid			(550)		0		0		0		(550)
Dividends paid to parent			0		(478)		(450)		928		0
Notes payable to affiliate			0		84		0		(84)		0
Contributions from parent			0		10		1		(11)		0
Other			0		1		(2)		3		2
Net cash (used) provided by financing activities			(669)		(400)		44		834		(191)
Net decrease in cash and cash equivalents			(110)		(236)		(162)		0		(508)
Cash and cash equivalents at beginning of period			110		270		231		0		611
Cash and cash equivalents at end of period		$	0	$	34	$	69	$	0	$	103

XML

Severance

9 Months Ended

Sep. 30, 2012

Restructuring and Related Activities [Abstract]

Restructuring and Related Activities Disclosure [Text Block]

13.       SEVERANCE

In conjunction with the merger, in November 2011, Duke Energy and Progress Energy offered a voluntary severance plan to certain eligible employees. As this is a voluntary severance plan, all severance benefits offered under this plan are considered special termination benefits under U.S. GAAP. Special termination benefits are measured upon employee acceptance and recorded immediately absent any significant retention period. If a significant retention period exists, the cost of the special termination benefits are recorded ratably over the retention period. Approximately 1,100 employees of the combined company, including approximately 650 employees of Progress Energy, accepted the termination benefits during the voluntary window period, which closed on November 30, 2011.The estimated amount of severance payments for Duke Energy associated with this voluntary plan and other severance benefits through 2014, excluding amounts incurred through September 30, 2012, are expected to range from $80 million to $110 million and most of the costs will be charged to Duke Energy Carolinas, PEC and PEF.

Amounts included in the following table represent severance expense recorded by the Progress Energy Registrants during 2012, which is included within O&M expense in the Statements of Operations and Comprehensive Income. The Progress Energy Registrants recorded insignificant amounts for severance expense during 2011.

(in millions)	Three months ended September 30, 2012			Nine months ended September 30, 2012
Progress Energy		$	66		$	66
PEC			42			42
PEF			24			24

Amounts included in the table below represent the severance liability for ourpast and ongoing severance plans.

(in millions)	Balance at December 31, 2011		Provisions / Adjustments		Cash Reductions		Balance at September 30, 2012
Progress Energy	$	5	$	53	$	(15)	$	43
PEC		5		26		(7)		24
PEF		-		10		(3)		7

XML

Fair Value Disclosures

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Line Items]

Fair Value Disclosures

9.       FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES

Under existing accounting guidance, fair value is considered to be the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date. The fair value definition focuses on an exit price, which is the price that would be received to sell an asset or paid to transfer a liability versus an entry price, which would be the price paid to acquire an asset or received to assume a liability.

The Progress Energy Registrants classify recurring and non-recurring fair value measurements based on the following fair value hierarchy, as prescribed by the accounting guidance for fair value, which prioritizes the inputs to valuation techniques used to measure fair value into three levels:

Level 1 – unadjusted quoted prices in active markets for identical assets or liabilities that the Progress Energy Registrants have the ability to access. An active market for the asset or liability is one in which transactions for the asset or liability occurs with sufficient frequency and volume to provide ongoing pricing information. The Progress Energy Registrants do not adjust quoted market prices on Level 1 for any blockage factor.

Level 2 – a fair value measurement utilizing inputs other than a quoted market price that are observable, either directly or indirectly, for the asset or liability. Level 2 inputs include, but are not limited to, quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active and inputs other than quoted market prices that are observable for the asset or liability, such as interest rate curves and yield curves observable at commonly quoted intervals, volatilities, credit risk and default rates. A Level 2 measurement cannot have more than an insignificant portion of the valuation based on unobservable inputs.

Level 3 – any fair value measurements which include unobservable inputs for the asset or liability for more than an insignificant portion of the valuation. A level 3 measurement may be based primarily on Level 2 inputs.

The fair value accounting guidance for financial instruments permits entities to elect to measure many financial instruments and certain other items at fair value that are not required to be accounted for at fair value under other GAAP. There are no financial assets or financial liabilities that are not required to be accounted for at fair value under GAAP for which the option to record at fair value has been elected by the Progress Energy Registrants. However, in the future, the Progress Energy Registrants may elect to measure certain financial instruments at fair value in accordance with this accounting guidance.

Nuclear Decommissioning Trust (NDTs) 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 CVOs, which are derivatives, in connection with the acquisition of Florida Progress. CVOs are further discussed in Note 8. At September 30, 2011, we determined the fair value of the CVOs based on the purchase price in a negotiated settlement agreement (a Level 3 input) and we classified CVOs as Level 3. The CVOs were previously recorded at fair value based on quoted prices from a less-than-active market and classified as Level 2. In November 2011, we commenced a public tender offer that expired on February 15, 2012. At September 30, 2012 and December 31, 2011,all CVOs not tendered, have been classified as Level 2 based on observable prices in the less-than-active market.

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. The Progress Energy Registrants' policy for the recognition of transfers between levels of the fair value hierarchy is to recognize the transfer at the end of the period.There were no transfers into (out of) Levels 1, 2 and 3 during the periods other than the CVO transfer previously discussed.

Valuation methods of the primary fair value measurements disclosed below are as follows:

Investments in equity securities – Investments in equity securities, other than those accounted for as equity and cost method investments, are typically valued at the closing price in the principal active market as of the last business day of the quarter. Principal active markets for equity prices include published exchanges such as NASDAQ and NYSE. Foreign equity prices are translated from their trading currency using the currency exchange rate in effect at the close of the principal active market. Prices have not been adjusted to reflect for after-hours market activity. The majority of investments in equity securities are valued using Level 1 measurements.

Investments in debt securities – Most debt investments (including those held in the NDT)are valued based on a calculation using interest rate curves and credit spreads applied to the terms of the debt instrument (maturity and coupon interest rate) and consider the counterparty credit rating. Most debt valuations are Level 2 measurements. If the market for a particular fixed income security is relatively inactive or illiquid, the measurement is a Level 3 measurement. U.S. Treasury debt is typically a Level 1 measurement.

Commodity derivatives – The pricing for commodity derivatives is primarily a calculated value which incorporates the forward price and is adjusted for liquidity (bid-ask spread), credit or non-performance risk (after reflecting credit enhancements such as collateral) and discounted to present value. The primary difference between a Level 2 and a Level 3 measurement relates to the level of activity in forward markets for the commodity. If the market is relatively inactive, the measurement is deemed to be a Level 3 measurement. Commodity derivatives with clearinghouses are classified as Level 1 measurements.

The following tables provide the fair value measurement amounts for financial assets and liabilities recorded at fair value on our and the Utilities' Balance Sheets.Derivative amounts in the tables below exclude cash collateral amounts, which are disclosed in Note 8. See Note 10 for additional information related to investments by major security type.

PROGRESS ENERGY
(in millions)			Total		Level 1		Level 2		Level 3
September 30, 2012
Nuclear decommissioning trust fund equity securities		$	1,226	$	1,220	$	6	$	-
Nuclear decommissioning trust fund debt securities and other			618		131		487		-
Other long-term available-for-sale debt securities and other(a)			60		21		39		-
Derivative assets(b)			1		-		1		-
	Total assets		1,905		1,372		533		-
Derivative liabilities(c)			(435)		-		(399)		(36)
	Net assets	$	1,470	$	1,372	$	134	$	(36)
(in millions)			Total		Level 1		Level 2		Level 3
December 31, 2011
Nuclear decommissioning trust fund equity securities		$	1,062	$	1,061	$	1	$	-
Nuclear decommissioning trust fund debt securities and other			585		87		498		-
Other long-term available-for-sale debt securities and other(a)			20		20		-		-
Derivative assets(b)			5		-		5		-
	Total assets		1,672		1,168		504		-
Derivative liabilities(c)			(799)		-		(775)		(24)
	Net assets	$	873	$	1,168	$	(271)	$	(24)
(a)	Included in Other within Investments and Other Assets in the Consolidated Balance Sheets.
(b)	Included in Prepayments and Other Current Assets within Current Assets and Other within Investments and Other Assets in the Consolidated Balance Sheets.
(c)	Included in Derivative Liabilities within Current Liabilities and Other within Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.
PEC
(in millions)			Total		Level 1		Level 2		Level 3
September 30, 2012
Nuclear decommissioning trust fund equity securities		$	797	$	797	$	-	$	-
Nuclear decommissioning trust fund debt securities and other			426		105		321		-
Other long-term available-for-sale debt securities and other(a)			6		6		-		-
	Total assets		1,229		908		321		-
Derivative liabilities(c)			(155)		-		(119)		(36)
	Net assets	$	1,074	$	908	$	202	$	(36)
(in millions)			Total		Level 1		Level 2		Level 3
December 31, 2011
Nuclear decommissioning trust fund equity securities		$	690	$	690	$	-	$	-
Nuclear decommissioning trust fund debt securities and other			398		81		317		-
Other long-term available-for-sale debt securities and other(a)			6		6		-		-
	Total assets		1,094		777		317		-
Derivative liabilities(c)			(248)		-		(224)		(24)
	Net assets	$	846	$	777	$	93	$	(24)
(a)	Included in Other within Investments and Other Assets in the Consolidated Balance Sheets.
(b)	Included in Prepayments and Other Current Assets within Current Assets and Other within Investments and Other Assets in the Consolidated Balance Sheets.
(c)	Included in Derivative Liabilities within Current Liabilities and Other within Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.
PEF
(in millions)			Total		Level 1		Level 2		Level 3
September 30, 2012
Nuclear decommissioning trust fund equity securities		$	429	$	423	$	6	$	-
Nuclear decommissioning trust fund debt securities and other			192		26		166		-
Other long-term available-for-sale debt securities and other(a)			41		2		39		-
Derivative assets(b)			1		-		1		-
	Total assets		663		451		212		-
Derivative liabilities(c)			(276)		-		(276)		-
	Net assets	$	387	$	451	$	(64)	$	-
(in millions)			Total		Level 1		Level 2		Level 3
December 31, 2011
Nuclear decommissioning trust fund equity securities		$	372	$	371	$	1	$	-
Nuclear decommissioning trust fund debt securities and other			187		6		181		-
Other long-term available-for-sale debt securities and other(a)			1		1		-		-
Derivative assets(b)			5		-		5		-
	Total assets		565		378		187		-
Derivative liabilities(c)			(499)		-		(499)		-
	Net assets	$	66	$	378	$	(312)	$	-
(a)	Included in Other within Investments and Other Assets in the Balance Sheets.
(b)	Included in Prepayments and Other Current Assets within Current Assets and Other within Investments and Other Assets in the Balance Sheets.
(c)	Included in Derivative Liabilities within Current Liabilities and Other within Deferred Credits and Other Liabilities in the Balance Sheets.

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.

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 periods endedSeptember 30 follows:

PROGRESS ENERGY
	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
Derivatives, net at beginning of period	$	30	$	37	$	24	$	36
Total pre-tax realized or unrealized gains included in earnings − regulated electric		(2)		-		(2)		-
Total (gains) losses, included in the consolidated Balance Sheet as regulatory asset or liability		(4)		6		2		7
Issuances		16		-		16		-
Settlements		(4)		-		(4)		-
Transfers into Level 3 − CVOs		-		74		-		74
Derivatives, net at end of period	$	36	$	117	$	36	$	117
PEC
	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
Derivatives, net at beginning of period	$	28	$	37	$	24	$	36
Total pre-tax realized or unrealized gains included in earnings − regulated electric		(2)		-		(2)		-
Total (gains) losses, included in the consolidated Balance Sheet as regulatory asset or liability		(2)		5		2		6
Issuances		16		-		16		-
Settlements		(4)		-		(4)		-
Derivatives, net at end of period	$	36	$	42	$	36	$	42

During the three and nine months ended September 30, 2012 and 2011, PEF's assets and liabilities classified as Level 3 were not material.

Substantially all unrealized gains and losses on derivatives are deferred as regulatory liabilities or assets consistent with ratemaking treatment. Unrealized losses on the change in fair value of our CVOs are discussed in Note 8. 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. 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. For the commodity derivative contracts classified as Level 3, the pricing inputs for natural gas and electricity forward price curves are not observable for the full term of the related contracts. In isolation, increases (decreases) in unobservable natural gas forward prices would result in favorable (unfavorable) fair value adjustments for gas purchase contracts. In isolation, increases (decreases) in unobservable electricity forward prices would result in unfavorable (favorable) fair value adjustments for electricity sales contracts. We regularly evaluate and validate the pricing inputs we use to estimate fair value of gas purchase contracts 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's derivative liabilities classified as Level 3 follows:

PROGRESS ENERGY
(in millions)	Fair Value		Valuation Technique	Unobservable Input		Range
September 30, 2012
Commodity natural gas hedges	$	27	Discounted cash flow	Forward natural gas curves - price per MMBtu	$	4.178	-	4.588
FERC mitigation power sale agreements		9	Discounted cash flow	Forward electricity curves - price per MWh		24.88	-	49.78
PEC
(in millions)	Fair Value		Valuation Technique	Unobservable Input		Range
September 30, 2012
Commodity natural gas hedges	$	27	Discounted cash flow	Forward natural gas curves - price per MMBtu	$	4.178	-	4.588
FERC mitigation power sale agreements		9	Discounted cash flow	Forward electricity curves - price per MWh		24.88	-	49.78

ADDITIONAL FAIR VALUE DISCLOSURES

At September 30, 2012 and December 31, 2011,the fair value of cash and cash equivalents, accounts and notes receivable, accounts payable, notes payable and commercial paper and non-recourse notes payable of variable interest entities are not materially different from their carrying amounts because of the short-term nature of these instruments and/or because the stated rates approximate market rates.

The fair value of our long-term debt, including current maturities, is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined are not necessarily indicative of the amounts the Progress Energy Registrants could have settled in current markets. The fair value of the long-term debt is determined using Level 2 measurements.

		September 30, 2012				December 31, 2011
(in millions)		Book Value		Fair Value		Book Value		Fair Value
Progress Energy	$	13,776	$	16,160	$	13,152	$	15,518
PEC		4,838		5,352		4,206		4,735
PEF		4,672		5,646		4,681		5,633

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Goodwill

9 Months Ended

Sep. 30, 2012

Goodwill Disclosure [Abstract]

Goodwill

7.GOODWILL

In the third quarter of 2012, Progress Energy changed its goodwill impairment testing date for the PEC and PEF reporting units from October 31 to August 31. The change in the goodwill impairment test date is preferable as it better aligns the annual goodwill impairment testing procedures for PEC and PEF with the other reporting units of Duke Energy. This change in accounting principle did not accelerate, delay, avoid, or cause a goodwill impairment charge. Neither the change in the goodwill impairment testing date nor the merger resulted in anychanges to the PEC or PEF reporting units. Due to significant judgments and estimates that are utilized in a goodwill impairment analysis, we determined it was impracticable to objectively determine, without the use of hindsight, projected cash flows and related valuation estimates as of each August 31 for periods prior to August 31, 2012. As such, we have prospectively applied the change in the annual goodwill impairment testing date from August 31, 2012.The results of our 2012 annual test of goodwill indicated the carrying amounts of goodwill were not impaired.

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Risk Management Activities and Derivative Transactions

9 Months Ended

Sep. 30, 2012

Risk Management Activities And Derivative Transactions Disclosure [Line Items]

Risk Management Activities And Derivative Transactions

8.RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

The Progress Energy Registrants utilize various derivative instruments to manage risks primarily associated with commodity prices and interest rates. The primary use of energy commodity derivatives is to hedge the generation portfolio against the changes in the prices of power and fuel. Interest rate derivatives are entered into to manage interest rate risk associated with variable-rate and fixed-rate borrowings.

Certain derivative instruments qualify for hedge accounting and are designated as cash flow hedges, while others either do not qualify as accounting hedges (such as economic hedges) or have not been designated as hedges (herein after referred to as undesignated contracts). All derivative instruments not meeting the criteria for the normal purchasesor sales exception are recognized aseither assets or liabilities at fair value in the Balance Sheets. As PEC and PEF meet the criteria for regulatory accounting treatment, the majority of the derivative contracts entered into by PEC and PEF are not designated as hedges since gains and losses on such contracts are deferred as regulatory liabilities and assets, respectively. Thus, there is no immediate earnings impact associated with changes in fair values of such derivative contracts. Cash flows relative to derivative instruments are considered operating activities based on the nature of the underlying transactions.

For derivative instruments that qualify and are designated as cash flow hedges, the effective portion of the gain or loss is reported as a component of Accumulated Other Comprehensive Income (AOCI) and reclassified into earnings in the same period or periods during which the hedged transactions affect earnings. Any gains or losses on the derivative that represent either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

• COMMODITY PRICE RISK

The Progress Energy Registrants are exposed to the impact of market changes in the future prices of natural gas, coal, fuel oil, electricity and other energy-related products marketed and purchased as a result of our ownership of energy-related assets. With respect to commodity price risks associated with electricity generation, PEC and PEF are exposed to changes including, but not limited to, the cost of the coal, natural gas and fuel oil used to generate electricity, the prices of electricity in wholesale markets, the cost of capacity and electricity purchased for resale in wholesale markets and the cost of emissions allowances primarily at the coal fired power plants. Risks associated with commodity price changes on future operations are closely monitored and, where appropriate, various commodity contracts are used to mitigate the effect of such fluctuations on operations. Exposure to commodity price risk is influenced by a number of factors, including, but not limited to, the term of the contracts, the liquidity of the market and delivery location.

COMMODITY CASH FLOW HEDGES

The Progress Energy Registrants use commodity instruments, such as swaps, futures, forwards and options, to protect margins for a portion of future revenues and fuel and purchased power expenses.

UNDESIGNATED CONTRACTS

The Progress Energy Registrants use derivative contracts as economic hedges to manage the market risk exposures that arise from providing electricity generation and capacity to large energy customers, energy aggregators, retail customers and other wholesale companies. Undesignated contracts may include contracts not designated as a hedge, contracts that do not qualify for hedge accounting, derivatives that do not or no longer qualify for the normal purchases or sales scope exemption, and de-designated hedge contracts. These undesignated contracts expire as late as 2015.

PEC uses derivative contracts as economic hedges to manage the market risk exposures that arise from electricity generation. PEC has also entered into firm power sale agreements, some of which are accounted for as derivative instruments, as part of the Interim FERC Mitigation in connection with Progress Energy's merger with Duke Energy (See Note 2). Undesignated contracts at September 30, 2012 are primarily associated with forward purchases and sales of electricity and forward purchases of fuel used in electricity generation.

PEF uses derivative contracts as economic hedges to manage the market risk exposures that arise from electricity generation. Undesignated contracts at September 30, 2012 are primarily associated with forward purchases of fuel used in electricity generation.

B. INTEREST RATE RISK

The Progress Energy Registrants are exposed to risk resulting from changes in interest rates as a result of their issuances or anticipated issuance of variable and fixed-rate debt and commercial paper. Interest rate exposure is managed by limiting variable-rate exposures to a percentage of total debt and by monitoring the effects of market changes in interest rates. To manage risk associated with changes in interest rates, the Progress Energy Registrantsmay enter into financial contracts; primarily interest rate swaps and U.S. Treasury lock agreements. Additionally, in anticipationof certain fixed-rate debt issuances, a series of forward starting interest rate swaps may be executed to lock in components of the market interest rates at the time and terminated prior to or upon the issuance of the corresponding debt. When these transactions occur within a business that meets the criteria for regulatory accounting treatment, these contracts may be treated as undesignated and any pre-tax gain or loss recognized from inception to termination of the hedges would be recorded as a regulatory liability or asset and amortized as a component of interest expense over the life of the debt. Alternatively, these derivatives may be designated as hedges whereby, any pre-tax gain or loss from inception to termination of the hedges would be recorded in AOCI and amortized as a component of interest expense over the life of the debt.

During the third quarter of 2012, $117 million and $42 million in pre-tax deferred net losses on derivative instruments related to interest rate cash flow hedgesfor regulated operations were reclassified from AOCI to regulatory assets at PEC and PEF, respectively.

The following tables show the notional amounts for derivatives related to interest rate risk:

Notional Amounts of Derivative Instruments Related to Interest Rate
		Progress Energy		PEC		PEF
(in millions)		September 30, 2012
Undesignated contracts	$	100	$	50	$	50
(in millions)		December 31, 2011
Cash flow hedges	$	500	$	250	$	50

C. VOLUMES

The following tables show information relating to the volume of the Progress Energy Registrants' outstanding commodity derivative activity. Amounts disclosed represent the notional volumes of commodities contracts accounted for at fair value. For option contracts, notional amounts include only delta-equivalent volumes which represent the notional volumes times the probability of exercising the option based on current price volatility. Volumes associated with contracts qualifying for the normal purchase or sales exceptions have been excluded from the tables below. Amounts disclosed represent the absolute value of notional amounts. Contractual amounts have been netted where offsetting purchase and sale contracts exist with identical delivery locations and times of delivery. Where all commodity positions are perfectly offset, no quantities are shown below. For additional information on notional dollar amounts of debt subject to derivative contracts accounted for at fair value, see “Interest Rate Risk” section above.

Underlying Notional Amounts for Commodity Derivative Instruments Accounted for At Fair Value
		Progress Energy	PEC	PEF
		September 30, 2012
Commodity contracts
	Electricity-energy (Gigawatt-hours)(a)	1,850	1,850	0
	Electricity-capacity (Gigawatt-months)(a)	5	5	0
	Natural gas (millions of decatherms)	297	89	208
	Fuel oil (millions of gallons)	6	0	6
		December 31, 2011
Commodity contracts
	Natural gas (millions of decatherms)	347	103	244
	Fuel oil (millions of gallons)	10	0	10
(a)	Interim FERC Mitigation power sales agreements entered into in connection with the merger with Duke Energy.

D. DERIVATIVE INSTRUMENT AND HEDGING ACTIVITY INFORMATION

The following tables show fair value amounts of derivative contracts and the line item(s) in the Balance Sheets in which such amounts are included. The fair values of derivative contracts are presented on a gross basis, even when the derivative instruments are subject to master netting arrangements where the Progress Energy Registrants net the fair value of derivative contracts subject to master arrangements with the same counterparty in the Balance Sheets. Cash collateral payables and receivables associated with the derivative contracts have not been netted against the fair value amounts.

Location and Fair Value of Derivatives Reflected in the Balance Sheets
				Progress Energy				PEC				PEF
Instrument / Balance Sheet location				September 30, 2012
(in millions)			Asset		Liability		Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity contracts
	Derivative liabilities, current				$	1			$	-			$	1
		Total derivatives designated as hedging instruments				1				0				1
Derivatives not designated as hedging instruments
Commodity contracts(a)
	Investments and other assets: other		$	1		0	$	0		0	$	1		0
	Derivative liabilities, current			8		220		3		74		5		146
	Deferred credits and other liabilities: other			14		209		2		74		12		135
Interest rate contracts(a)
	Derivative liabilities, current					23				11				12
CVOs(b)
	Deferred credits and other liabilities: other					4				0				0
		Total derivatives not designated as hedging instruments		23		456		5		159		18		293
		Total derivatives	$	23	$	457	$	5	$	159	$	18	$	294
(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 Contingent Value Obligations (CVOs) in connection with the acquisition of Florida Progress Corporation (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.
				Progress Energy				PEC				PEF
Instrument / Balance Sheet location			December 31, 2011
(in millions)			Asset		Liability		Asset		Liability		Asset		Liability
Derivatives designated as hedging instruments
Commodity contracts
	Derivative liabilities, current				$	2			$	-			$	2
	Deferred credits and other liabilities: other					1				-				1
Interest rate contracts
	Derivative liabilities, current					76				38				0
	Deferred credits and other liabilities: other					17				9				8
		Total derivatives designated as hedging instruments				96				47				11
Derivatives not designated as hedging instruments
Commodity contracts(a)
	Derivative liabilities, current		$	5		357	$	0		91	$	5		266
	Deferred credits and other liabilities: other			0		332		0		110		0		222
CVOs(b)
	Current liabilities: other					14				-				-
		Total derivatives not designated as hedging instruments		5		703		0		201		5		488
		Total derivatives	$	5	$	799	$	0	$	248	$	5	$	499
(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. In 2011, we repurchased and continue to hold 80.1 million CVOs in a negotiated settlement agreement and subsequent tender offer.

The following tables show the amount of gains and losses recognized on derivative instruments designated and qualifying as cash flow hedges by type of derivative contract and the Statements line items in which such gains and losses are included.

Cash Flow Hedges - Location and Amount of Pre-Tax Gains and (Losses) Recognized in Comprehensive Income
				Progress Energy				PEC				PEF
			Three months ended September 30
(in millions)			2012		2011		2012		2011		2012		2011
Pre-tax gains (losses) recognized in OCI(a)
	Commodity contracts		$	1	$	(1)	$	0	$	0	$	1	$	(1)
	Interest rate contracts(b)			0		(111)		0		(58)		0		(27)
Total pre-tax gains (losses) recognized in OCI			$	1	$	(112)	$	0	$	(58)	$	1	$	(28)
Location of pre-tax gains (losses) reclassified from OCI into income(a)
	Interest rate contracts(b)
		Interest expense	$	(2)	$	(3)	$	0	$	(2)	$	0	$	0
Total pre-tax gains (losses) reclassified from OCI into income			$	(2)	$	(3)	$	0	$	(2)	$	0	$	0
Location of pre-tax gains (losses) recognized in income on derivatives(c)
	Interest rate contracts(b)
		Interest expense	$	0	$	(1)	$	0	$	(1)	$	0	$	0
Total pre-tax gains (losses) recognized in income on derivatives			$	0	$	(1)	$	0	$	(1)	$	0	$	0
(a)	Effective portion.
(b)	Amounts in AOCI 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.
(c)	Related to ineffective portion and amount excluded from effectiveness testing.
				Progress Energy				PEC				PEF
			Nine months ended September 30
(in millions)			2012		2011		2012		2011		2012		2011
Pre-tax gains (losses) recognized in OCI(a)
	Commodity contracts		$	1	$	(1)	$	0	$	0	$	1	$	(1)
	Interest rate contracts(b)			(11)		(134)		(7)		(67)		(2)		(35)
Total pre-tax gains (losses) recognized in OCI			$	(10)	$	(135)	$	(7)	$	(67)	$	(1)	$	(36)
Location of pre-tax gains (losses) reclassified from OCI into income(a)
	Interest rate contracts(b)
		Interest expense	$	(12)	$	(9)	$	(5)	$	(5)	$	(2)	$	0
Total pre-tax gains (losses) reclassified from OCI into income			$	(12)	$	(9)	$	(5)	$	(5)	$	(2)	$	0
Location of pre-tax gains (losses) recognized in income on derivatives(c)
	Interest rate contracts(b)
		Interest expense	$	0	$	(3)	$	0	$	(1)	$	0	$	0
Total pre-tax gains (losses) recognized in income on derivatives			$	0	$	(3)	$	0	$	(1)	$	0	$	0
(a)	Effective portion.
(b)	Amounts in AOCI 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.
(c)	Related to ineffective portion and amount excluded from effectiveness testing.

PROGRESS ENERGY

At September 30, 2012 and December 31, 2011, $71 million and $232 million, respectively, of pre-tax deferred net losses on derivative instruments related to interest rate cash flow hedges remained in AOCI and $5 million pre-tax loss is expected to be recognized in earnings during the next 12 months as the hedged transactions occur.

PEC

At December 31, 2011,$116 million of pre-tax deferred net losses on derivative instruments related to interest rate cash flow hedges remained in AOCI.At September 30, 2012,such losses were reclassified to regulatory assets.

PEF

At December 31, 2011, $41 million of pre-tax deferred net losses on derivative instruments related to interest rate cash flow hedges remained in AOCI.At September 30, 2012,such losses were reclassified to regulatory assets.

The following tables show the amount of the pre-tax gains and losses recognized on undesignated contracts by type of derivative instrument and the line item(s) in the Statements of Operations and Comprehensive Income in which such gains and losses are included or deferred in the Balance Sheets as regulatory assets and liabilities.

Undesignated Contracts - Location and Amount of Pre-Tax Gains and (Losses) Recognized in Income or as Regulatory Assets or Liabilities
				Progress Energy				PEC				PEF
				Three months ended September 30
(in millions)				2012	2011			2012	2011			2012	2011
Location of pre-tax gains and (losses) recognized in earnings
	Commodity contracts
		Regulated electric revenue	$	(9)	$	0	$	(9)	$	0	$	0	$	0
		Fuel used in electric generation and purchased power(a)		(135)		(91)		(35)		(20)		(100)		(71)
	Interest rate contracts
		Interest expense(b)		(4)		0		(3)		0		(1)		0
Total pre-tax gains (losses) recognized in earnings			$	(148)	$	(91)	$	(47)	$	(20)	$	(101)	$	(71)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities
	Commodity contracts(c)
		Regulatory asset	$	60	$	(157)	$	15	$	(42)	$	45	$	(115)
	Interest rate contracts(b)
		Regulatory asset		2		0		2		0		0		0
Total pre-tax gains (losses) recognized as regulatory assets or liabilities			$	62	$	(157)	$	17	$	(42)	$	45	$	(115)
Location of pre-tax gains and (losses) recognized in income on derivatives
	Fair value loss transition adjustment
		Regulated electric revenue	$	0	$	1	$	0	$	1	$	0	$	0
	CVOs
		Other income and expenses, net		(1)		(63)		0		0		0		0
Total pre-tax gains (losses) recognized in income on derivatives			$	(1)	$	(62)	$	0	$	1	$	0	$	0
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts in regulatory assets and liabilities related to terminated hedges are reclassified to earnings as the interest expense is recorded. The hedges will be amortized to interest expense over the term of the related debt.
(c)	Amounts are recorded in regulatory assets and liabilities in the Balance Sheets until derivatives are settled.
				Progress Energy				PEC				PEF
				Nine months ended September 30
(in millions)				2012	2011			2012	2011			2012	2011
Location of pre-tax gains and (losses) recognized in earnings
	Commodity contracts
		Regulated electric revenue	$	(9)	$	0	$	(9)	$	0	$	0	$	0
		Fuel used in electric generation and purchased power(a)		(395)		(219)		(100)		(42)		(295)		(177)
	Interest rate contracts
		Interest expense(b)		(4)		0		(3)		0		(1)		0
Total pre-tax gains (losses) recognized in earnings			$	(408)	$	(219)	$	(112)	$	(42)	$	(296)	$	(177)
Location of pre-tax gains and (losses) recognized as regulatory assets or liabilities
	Commodity contracts(c)
		Regulatory asset	$	(108)	$	(201)	$	(34)	$	(55)	$	(74)	$	(146)
	Interest rate contracts(b)
		Regulatory asset		2		0		2		0		0		0
Total pre-tax gains (losses) recognized as regulatory assets or liabilities			$	(106)	$	(201)	$	(32)	$	(55)	$	(74)	$	(146)
Location of pre-tax gains and (losses) recognized in income on derivatives
	Commodity contracts
		Regulated electric revenue	$	2	$	1	$	2	$	1	$	0	$	0
	Fair value loss transition adjustment
		Regulated electric revenue		1		1		1		1		0		0
	CVOs
		Other income and expenses, net		7		(59)		0		0		0		0
Total pre-tax gains (losses) recognized in income on derivatives			$	10	$	(57)	$	3	$	2	$	0	$	0
(a)	After settlement of the derivatives and the fuel is consumed, gains or losses are passed through the fuel cost-recovery clause.
(b)	Amounts in regulatory assets and liabilities related to terminated hedges are reclassified to earnings as the interest expense is recorded. The hedges will be amortized to interest expense over the term of the related debt.
(c)	Amounts are recorded in regulatory assets and liabilities in the Balance Sheets until derivatives are settled.

E. CREDIT RISK

Certain of PEC and PEF's derivative contracts contain contingent features, such as material adverse change clauses or payment acceleration clauses that could result in immediate payments, the posting of letters of credit or the termination of the derivative contract before maturity if specific events occur, such as a downgrade in the individual company's credit rating below investment grade.

The following tables show information with respect to derivative contracts that are in a net liability position and contain objective credit-risk-related payment provisions. The amounts disclosed in the table below represent the aggregate fair value amounts of such derivative instruments at the end of the reporting period, the aggregate fair value of assets that are already posted as collateral under such derivative instruments at the end of the reporting period and the aggregate fair value of the additional assets that would need to be transferred in the event that credit-risk-related contingent features were triggered.

Information Regarding Derivative Instruments that Contain Credit-Risk-Related Contingent Features
	Progress Energy		PEC		PEF
(in millions)		September 30, 2012
Aggregate fair value amounts of derivative instruments in a net liability position	$	325	$	118	$	207
Collateral already posted		74		13		61
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered at the end of the reporting period		251		105		146
(in millions)		December 31, 2011
Aggregate fair value amounts of derivative instruments in a net liability position	$	489	$	152	$	337
Collateral already posted		147		24		123
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered at the end of the reporting period		342		128		214

NETTINGOF CASH COLLATERALAND DERIVATIVE ASSETSAND LIABILITIES UNDERMASTER NETTING ARRANGEMENTS

In accordance with applicable accounting rules, the Progress Energy Registrants have elected to offset fair value amounts (or amounts that approximate fair value) recognized in their Balance Sheets related to cash collateral amounts receivable or payable against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting agreement. The amounts disclosed in the table below represent the receivables related to the right to reclaim cash collateral and payables related to the obligation to return cash collateral under master netting arrangements. See Note 9 for additional information on fair value disclosures related to derivatives.

Information Regarding Cash Collateral under Master Netting Arrangements
		Progress Energy				PEC				PEF
	September 30, 2012
(in millions)	Receivables		Payables		Receivables		Payables		Receivables		Payables
Amounts offset against net derivative positions	$	73	$	0	$	13	$	0	$	60	$	0
Amounts not offset against net derivative positions		1		0		0		0		1		0
	December 31, 2011
(in millions)	Receivables		Payables		Receivables		Payables		Receivables		Payables
Amounts offset against net derivative positions	$	140	$	0	$	23	$	0	$	117	$	0
Amounts not offset against net derivative positions		3		0		0		0		3		0

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Investments

9 Months Ended

Sep. 30, 2012

Investments Disclosure [Line Items]

Investments

10.INVESTMENTS IN DEBT AND EQUITY SECURITIES

Certain investments in debt and equity securities that have readily determinable market values are accounted for as available-for-sale securities, which are reported at fair value in the Balance Sheets with unrealized gains and losses excluded from earnings and reported either as a regulatory asset or liability.

Our available-for-sale securities are primarily comprised of investments held in PEC's and PEF's NDTs,pursuant to NRC requirements, to fund certain costs of decommissioning the Utilities' nuclear plants as discussed in Note 5C of the 2011Form 10-K, as well asinvestments in a grantor trust at PEF related to other post-retirement benefit plans. Progress Energy classifies its investments in debt and equity securities held within the PEC and PEF NDTs and the PEF grantor trust as long-term.

The investments within the PEC and PEF NDTs and the PEF grantor trust are managed by independent investment managers with discretion to buy, sell and invest pursuant to the objectives set forth by the trust agreements. Therefore, we and the Utilities have limited oversight of the day-to-day management of these investments. Since day-to-day investment decisions, including buy and sell decisions, are made by the investment manager, the ability to hold investments in unrealized loss positions is outside our and the Utilities' control. Accordingly, all unrealized gains and losses associated with equity securities within thePEC and PEF NDTs and the PEF grantor trust are considered other-than-temporary and are recognized immediately when the fair value of individual investments is less than the cost basis of the investment. Pursuant to regulatory accounting, substantially all realized and unrealized gains and losses associated withinvestments in debt and equity securities within the PEC and PEF NDTs and the PEF grantor trust are deferred as a regulatory asset or liability. As a result, there is no immediate impact on our or the Utilities' earnings.Therefore, the following tables include the unrealized gains and losses for the NDT and the PEF grantor trust funds based on the original cost of the trust investments.

The following tables summarizeProgress Energy's, PEC's and PEF's available-for-sale securities at September 30, 2012 and December 31, 2011:

PROGRESS ENERGY
(in millions)		Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2012
Nuclear decommissioning trust funds
	Equity securities	$	1,226	$	21	$	534
	Corporate debt securities		85		-		9
	Municipal bonds		134		1		10
	U.S. government bonds		295		-		17
	Other		104		1		3
Total nuclear decommissioning trust funds			1,844		23		573
Other investments
	Municipal bonds		39		-		-
	Other		21		-		-
	Total	$	1,904	$	23	$	573
December 31, 2011
Nuclear decommissioning trust funds
	Equity securities	$	1,062	$	29	$	412
	Corporate debt securities		86		-		6
	Municipal bonds		127		2		7
	U.S. government bonds		268		-		18
	Other		87		-		1
Total nuclear decommissioning trust funds			1,630		31		444
Other investments
	Other		20		-		-
	Total	$	1,650	$	31	$	444

PEC
(in millions)		Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2012
Nuclear decommissioning trust funds
	Equity securities	$	797	$	15	$	340
	Corporate debt securities		75		-		8
	Municipal bonds		61		-		4
	U.S. government bonds		230		-		15
	Other		60		-		1
Total nuclear decommissioning trust funds			1,223		15		368
Other investments
	Other		6		-		-
	Total	$	1,229	$	15	$	368
December 31, 2011
Nuclear decommissioning trust funds
	Equity securities	$	690	$	20	$	262
	Corporate debt securities		69		-		5
	Municipal bonds		55		-		3
	U.S. government bonds		225		-		16
	Other		62		-		1
Total nuclear decommissioning trust funds			1,101		20		287
Other investments
	Other		6		-		-
	Total	$	1,107	$	20	$	287

PEF
(in millions)		Fair Value		Unrealized Losses		Unrealized Gains
September 30, 2012
Nuclear decommissioning trust funds
	Equity securities	$	429	$	6	$	194
	Corporate debt securities		10		-		1
	Municipal bonds		73		1		6
	U.S. government bonds		65		-		2
	Other		44		1		2
Total nuclear decommissioning trust funds			621		8		205
Other investments
	Municipal bonds		39		-		-
	Other		2		-		-
	Total	$	662	$	8	$	205
December 31, 2011
Nuclear decommissioning trust funds
	Equity securities	$	372	$	9	$	150
	Corporate debt securities		17		-		1
	Municipal bonds		72		2		4
	U.S. government bonds		43		-		2
	Other		25		-		-
Total nuclear decommissioning trust funds			529		11		157
Other investments
	Other		1		-		-
	Total	$	530	$	11	$	157

The table below summarizes the maturity date for available-for-sale debt securities held by Progress Energy, PEC and PEF at September 30, 2012:

(in millions)	< 1 Year		1-5 Years		6-10 Years		Thereafter		Total
Progress Energy	$	13	$	125	$	136	$	301	$	575
PEC		11		102		72		194		379
PEF		2		18		55		82		157

The following tables present selected information about Progress Energy's, PEC'sand PEF's sales of available-for-salesecurities during the three and nine months ended September 30, 2012 and 2011. Realized gains and losses were determined on a specific identification basis.

PROGRESS ENERGY
	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
Proceeds	$	274	$	1,062	$	794	$	4,254
Realized gains		8		9		23		24
Realized losses		6		11		12		20

PEC
	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
Proceeds	$	101	$	136	$	351	$	386
Realized gains		4		4		14		10
Realized losses		2		4		5		9

PEF
	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
Proceeds	$	173	$	926	$	443	$	3,861
Realized gains		4		5		9		14
Realized losses		4		7		7		11

The fair values and gross unrealized losses of available-for-sale debt and equity securities, which are in an unrealized loss position for which other-than-temporary investment losses have not been recorded in earnings, summarized by investment type and length of time that the securities have been in continuous loss position, are presented in the tables below for Progress Energy, PEC and PEF at September 30, 2012 and December 31, 2011:

PROGRESS ENERGY
(in millions)		Fair Value		Unrealized Loss Positions > 12 months		Unrealized Loss Positions < 12 months
September 30, 2012
Nuclear decommissioning trust funds
	Equity securities	$	89	$	13	$	8
	Corporate debt securities		3		-		-
	Municipal bonds		14		1		-
	U.S. government bonds		10		-		-
	Other		1		-		1
Total nuclear decommissioning trust funds			117		14		9
Other investments
	Other		4		-		-
	Total	$	121	$	14	$	9
December 31, 2011
Nuclear decommissioning trust funds
	Equity securities	$	112	$	10	$	19
	Corporate debt securities		20		-		-
	Municipal bonds		21		2		-
	U.S. government bonds		(23)		-		-
	Other		6		-		-
	Total	$	136	$	12	$	19

PEC
(in millions)		Fair Value		Unrealized Loss Positions > 12 months		Unrealized Loss Positions < 12 months
September 30, 2012
Nuclear decommissioning trust funds
	Equity securities	$	56	$	10	$	5
	Corporate debt securities		2		-		-
	Municipal bonds		5		-		-
	U.S. government bonds		11		-		-
	Total	$	74	$	10	$	5
December 31, 2011
Nuclear decommissioning trust funds
	Equity securities	$	69	$	10	$	10
	Corporate debt securities		10		-		-
	Municipal bonds		8		-		-
	U.S. government bonds		9		-		-
	Other		2		-		-
	Total	$	98	$	10	$	10

PEF
(in millions)		Fair Value		Unrealized Loss Positions > 12 months		Unrealized Loss Positions < 12 months
September 30, 2012
Nuclear decommissioning trust funds
	Equity securities	$	33	$	3	$	3
	Municipal bonds		9		1		-
	Other		1		-		1
Total nuclear decommissioning trust funds			43		4		4
Other investments
	Other		4		-		-
	Total	$	47	$	4	$	4
December 31, 2011
Nuclear decommissioning trust funds
	Equity securities	$	43	$	-	$	9
	Corporate debt securities		10		-		-
	Municipal bonds		13		2		-
	U.S. government bonds		(32)		-		-
	Other		4		-		-
	Total	$	38	$	2	$	9

Unrealized losses on investments within the PEC and PEF NDTs and the PEF grantor trust are deferred as regulatory assets pursuant to regulatory accounting treatment.

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Benefit Plans (Tables)

3 Months Ended

9 Months Ended

Sep. 30, 2012

Sep. 30, 2012

Benefit Plans Disclosure [Line Items]

Schedule of Net Benefit Costs [Tables]

PROGRESS ENERGY
		Qualified					Non-Qualified			Other Post-Retirement
		Pension Plans				Pension Plans				Benefit Plans
(in millions)			2012		2011		2012		2011		2012		2011
Service cost		$	16	$	13	$	0	$	0	$	5	$	3
Interest cost on projected benefit obligation			32		33		2		2		11		10
Expected return on plan assets			(48)		(45)		0		0		0		0
Amortization of prior service cost (a)			2		2		0		0		0		0
Amortization net transition liability(a)			0		0		0		0		1		1
Amortization of actuarial loss(a)			24		15		1		1		10		3
Special termination costs			0		0		0		0		5		0
Other			1		0		0		0		0		0
	Net periodic cost	$	27	$	18	$	3	$	3	$	32	$	17
(a)	Adjusted to reflect PEF’s rate treatment. See Note 17B in the 2011 Form 10-K.

PROGRESS ENERGY
			Qualified				Non-Qualified			Other Post-Retirement
			Pension Plans				Pension Plans					Benefit Plans
(in millions)			2012		2011		2012		2011			2012		2011
Service cost		$	47	$	39	$	1	$	1		$	12	$	8
Interest cost on projected benefit obligation			95		98		6		7			32		30
Expected return on plan assets			(141)		(136)		0		0			(1)		(1)
Amortization of prior service cost (a)			7		5		0		0			0		0
Amortization of net transition liability(a)			0		0		0		0			3		4
Amortization of actuarial loss(a)			69		47		3		2			25		9
Special termination cost			0		0		0		0			5		0
Other			1		0		0		0			0		0
	Net periodic cost	$	78	$	53	$	10	$	10		$	76	$	50
(a)	Adjusted to reflect PEF’s rate treatment. See Note 17B in the 2011 Form 10-K.

Net periodic cost weighted-average actuarial assumptions [Tables]

		Qualified Pension Benefits	Non-Qualified Pension Benefits	Other Post-Retirement Benefits
Discount rate		4.60%	4.60%	4.60%
Rate of increase in future compensation
	Bargaining	4.00%	N/A	N/A
	Supplementary plans	N/A	5.25%	N/A
Expected long-term rate of return on plan assets		8.00%	N/A	N/A

Weighted-average actuarial assumptions in year-end obligation calculations [Tables]

Health care cost trend rate assumed for 2012	8.75%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.00%
Year that the rate reaches the ultimate trend rate	2020

PEC [Member]

Benefit Plans Disclosure [Line Items]

Schedule of Net Benefit Costs [Tables]

PEC
		Qualified					Non-Qualified			Other Post-Retirement
		Pension Plans				Pension Plans				Benefit Plans
(in millions)			2012		2011		2012		2011		2012		2011
Service cost		$	6	$	5	$	0	$	0	$	2	$	2
Interest cost on projected benefit obligation			15		15		1		1		6		5
Expected return on plan assets			(25)		(23)		0		0		0		0
Amortization of prior service cost			2		1		0		0		0		0
Amortization net transition liability			0		0		0		0		0		0
Amortization of actuarial loss			9		7		0		0		6		1
Special termination costs			0		0		0		0		2		0
Other			1		0		0		0		0		0
	Net periodic cost	$	8	$	5	$	1	$	1	$	16	$	8

PEC
			Qualified				Non-Qualified			Other Post-Retirement
			Pension Plans				Pension Plans				Benefit Plans
(in millions)			2012		2011		2012		2011		2012		2011
Service cost		$	19	$	15	$	1	$	1	$	6	$	3
Interest cost on projected benefit obligation			43		46		1		1		17		15
Expected return on plan assets			(72)		(68)		0		0		0		0
Amortization of prior service cost			6		4		0		0		0		0
Amortization of net transition liability			0		0		0		0		0		1
Amortization of actuarial loss			28		19		1		0		14		4
Special termination cost			0		0		0		0		2		0
Other			1		0		0		0		0		0
	Net periodic cost	$	25	$	16	$	3	$	2	$	39	$	23

Defined contribution plan contributions [Table]

	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
PEC	$	7	$	6	$	18	$	18
PEF		4		4		11		11

PEF [Member]

Benefit Plans Disclosure [Line Items]

Schedule of Net Benefit Costs [Tables]

PEF
		Qualified					Non-Qualified			Other Post-Retirement
		Pension Plans				Pension Plans				Benefit Plans
(in millions)			2012		2011		2012		2011		2012		2011
Service cost		$	8	$	6	$	0	$	0	$	2	$	1
Interest cost on projected benefit obligation			14		14		1		1		4		4
Expected return on plan assets			(21)		(19)		0		0		0		0
Amortization net transition liability			0		0		0		0		1		1
Amortization of actuarial loss			13		8		0		0		3		2
Special termination costs			0		0		0		0		1		0
	Net periodic cost	$	14	$	9	$	1	$	1	$	11	$	8

PEF
			Qualified				Non-Qualified			Other Post-Retirement
			Pension Plans				Pension Plans				Benefit Plans
(in millions)			2012		2011		2012		2011		2012		2011
Service cost		$	22	$	18	$	0	$	0	$	5	$	3
Interest cost on projected benefit obligation			42		43		2		2		13		13
Expected return on plan assets			(61)		(59)		0		0		(1)		(1)
Amortization of net transition liability			0		0		0		0		2		3
Amortization of actuarial loss			36		25		0		0		9		6
Special termination cost			0		0		0		0		1		0
	Net periodic cost	$	39	$	27	$	2	$	2	$	29	$	24

Defined contribution plan contributions [Table]

	Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
PEC	$	7	$	6	$	18	$	18
PEF		4		4		11		11

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Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012		Dec. 31, 2011
Variable Interest Entity [Line Items]
Net property, plant and equipment	$ 12	[1]	$ 12	[1]
Equity investment in non consolidated variable interest entities	9		9
Prepayments and other current assets	2	[1]	1	[1]
Net assets of consolidated VIEs	14		13
Long-term debt, affiliate	274		273
VIE-exposure to loss from non-consolidated VIE's	9
PEC [Member]
Variable Interest Entity [Line Items]
Net property, plant and equipment	12	[1]	12	[1]
Prepayments and other current assets	2	[1]	1	[1]
Net assets of consolidated VIEs	$ 14		$ 13

[1] 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. 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.

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Related Party Transactions

9 Months Ended

Sep. 30, 2012

Related party transactions [Line Items]

Related party transactions

15.       RELATED PARTY TRANSACTIONS

The Progress Energy Registrants engage in related party transactions, which are generally performed at cost and in accordance with the applicable state and federal commission regulations. Refer to the Balance Sheets for balances due to or due from related parties. Amounts related to transactions with related parties included in the Statements of Operations and Comprehensive Income are presented in the following table:

		Three months ended September 30				Nine months ended September 30
(in millions)		2012		2011		2012		2011
PROGRESS ENERGY
Corporate governance and shared services provided by Duke Energy(a)		$	31	$	0	$	31	$	0
Corporate governance and shared services provided to Duke Energy(b)			30		0		30		0
JDA revenues(c)			37		0		37		0
JDA expenses(d)			8		0		8		0
Indemnification coverage expenses(e)			7		0		7		0
PEC
Corporate governance and shared service expenses(a)		$	72	$	48	$	183	$	155
JDA revenues(c)			37		0		37		0
JDA expenses(d)			8		0		8		0
Indemnification coverage expenses(e)			3		0		3		0
PEF
Corporate governance and shared service expenses(a)		$	52	$	41	$	136	$	122
Indemnification coverage expenses(e)			4		0		4		0
(a)	Progress Energy Registrants are charged their proportionate share of corporate governance and other costs by PESC (only applicable to PEC and PEF) and an unconsolidated affiliate that is a consolidated affiliate of Duke Energy. Corporate governance and other shared costs are primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These expenses are recorded in O&M in the Statements of Operations and Comprehensive Income.
(b)	PESC charges a proportionate share of corporate governance and other costs to unconsolidated affiliates that are consolidated affiliates of Duke Energy. Corporate governance and other shared costs are primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These charges are recorded as an offset to O&M in the Statements of Operations and Comprehensive Income.
(c)	Effective with the consummation of the merger, PEC and Duke Energy Carolinas began to participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customers' rates (See Note 4). The revenues from the sale of power to Duke Energy Carolinas are recorded in regulated electric revenues in the Consolidated Statements of Operations and Comprehensive Income.
(d)	Effective with the consummation of the merger, PEC and Duke Energy Carolinas began to participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customers' rates (See Note 4). The expenses from the purchase of power from Duke Energy Carolinas are recorded in fuel used in electric generation and purchased power in the Consolidated Statements of Operations and Comprehensive Income.
(e)	Effective with the consummation of the merger, Progress Energy Registrants incur expenses related to certain indemnification coverages through Bison, Duke Energy's wholly owned captive insurance subsidiary. These expenses are recorded in O&M in the Statements of Operations and Comprehensive Income.

Prior to the merger, PEC and PEF participated in an internal money pool, administered by PESC, to more effectively utilize cash resources and to reduce outside short-term borrowings. The money pool was also used to settle intercompany balances. Effective with the consummation of the merger, the Progress Energy Registrants began to participate in a money pool arrangement with Duke Energy (See Note 6). Interest income and expense associated with money pool activity were immaterial for the three and nine months ended September 30, 2012 and 2011.

In addition, the Parent has issued $300 million in guarantees for certain payments of two wholly owned indirect subsidiaries (See Note 17).

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Merger and Sales of Other Assets (Tables)

9 Months Ended

Sep. 30, 2012

Merger Disclosure [Line Items]

Accounting charges recognized related to the merger consummation

(in millions)		PEC		PEF		Progress Energy
FERC Mitigation		$	71	$	-	$	71
Severance costs			42		24		66
Community support, charitable contributions and other			54		9		63
	Total	$	167	$	33	$	200

Merger and integration costs [Tables]

	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
Progress Energy	$	218	$	14	$	241	$	32
PEC		180		7		194		17
PEF		38		7		47		15

Exit cost liabilities [Tables]

(in millions)
Balance, December 31, 2011		$	5
Additional exit cost recognized			5
Balance, June 30, 2012			10
Additional exit cost recognized(a)			2
Balance, September 30, 2012(b)		$	12
(a)	PEC, PEF and other Duke Energy subsidiaries recognized exit costs of $1 million, $- million and $1 million, respectively, for the three months ended September 30, 2012, and $4 million, $2 million and $1 million, respectively, for the nine months ended September 30, 2012.
(b)	Expense related to the recognition of the cumulative exit cost liability at September 30, 2012, was attributed to PEC, PEF and other Duke Energy subsidiaries totaling $8 million, $3 million and $1 million, respectively.

PEC [Member]

Merger Disclosure [Line Items]

Accounting charges recognized related to the merger consummation

(in millions)		PEC		PEF		Progress Energy
FERC Mitigation		$	71	$	-	$	71
Severance costs			42		24		66
Community support, charitable contributions and other			54		9		63
	Total	$	167	$	33	$	200

Merger and integration costs [Tables]

	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
Progress Energy	$	218	$	14	$	241	$	32
PEC		180		7		194		17
PEF		38		7		47		15

Exit cost liabilities [Tables]

(in millions)
Balance, December 31, 2011		$	5
Additional exit cost recognized			5
Balance, June 30, 2012			10
Additional exit cost recognized(a)			2
Balance, September 30, 2012(b)		$	12
(a)	PEC, PEF and other Duke Energy subsidiaries recognized exit costs of $1 million, $- million and $1 million, respectively, for the three months ended September 30, 2012, and $4 million, $2 million and $1 million, respectively, for the nine months ended September 30, 2012.
(b)	Expense related to the recognition of the cumulative exit cost liability at September 30, 2012, was attributed to PEC, PEF and other Duke Energy subsidiaries totaling $8 million, $3 million and $1 million, respectively.

PEF [Member]

Merger Disclosure [Line Items]

Accounting charges recognized related to the merger consummation

(in millions)		PEC		PEF		Progress Energy
FERC Mitigation		$	71	$	-	$	71
Severance costs			42		24		66
Community support, charitable contributions and other			54		9		63
	Total	$	167	$	33	$	200

Merger and integration costs [Tables]

	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
Progress Energy	$	218	$	14	$	241	$	32
PEC		180		7		194		17
PEF		38		7		47		15

Exit cost liabilities [Tables]

(in millions)
Balance, December 31, 2011		$	5
Additional exit cost recognized			5
Balance, June 30, 2012			10
Additional exit cost recognized(a)			2
Balance, September 30, 2012(b)		$	12
(a)	PEC, PEF and other Duke Energy subsidiaries recognized exit costs of $1 million, $- million and $1 million, respectively, for the three months ended September 30, 2012, and $4 million, $2 million and $1 million, respectively, for the nine months ended September 30, 2012.
(b)	Expense related to the recognition of the cumulative exit cost liability at September 30, 2012, was attributed to PEC, PEF and other Duke Energy subsidiaries totaling $8 million, $3 million and $1 million, respectively.

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Fair Value Disclosures - (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011	Sep. 30, 2012		Sep. 30, 2011	Dec. 31, 2011
Derivatives
Derivative assets	$ 1	[1]		$ 1	[1]		$ 5	[1]
Other marketable securities
Total assets	1,905			1,905			1,672
Derivatives
Derivative liabilities	(435)	[2]		(435)	[2]		(799)	[2]
Net assets	1,470			1,470			873
PEC [Member]
Other marketable securities
Total assets	1,229			1,229			1,094
Derivatives
Derivative liabilities	(155)	[2]		(155)	[2]		(248)	[2]
Net assets	1,074			1,074			846
PEF [Member]
Derivatives
Derivative assets	1	[3]		1	[3]		5	[3]
Other marketable securities
Total assets	663			663			565
Derivatives
Derivative liabilities	(276)	[4]		(276)	[4]		(499)	[4]
Net assets	387			387			66
Equity Securities [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	1,226			1,226			1,062
Equity Securities [Member] | PEC [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	797			797			690
Equity Securities [Member] | PEF [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	429			429			372
Debt Securities [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	618			618			585
Other marketable securities
Other marketable securities	60	[5]		60	[5]		20	[5]
Debt Securities [Member] | PEC [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	426			426			398
Other marketable securities
Other marketable securities	6	[5]		6	[5]		6	[5]
Debt Securities [Member] | PEF [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	192			192			187
Other marketable securities
Other marketable securities	41	[6]		41	[6]		1	[6]
Level 1 [Member]
Other marketable securities
Total assets	1,372			1,372			1,168
Derivatives
Net assets	1,372			1,372			1,168
Level 1 [Member] | PEC [Member]
Other marketable securities
Total assets	908			908			777
Derivatives
Net assets	908			908			777
Level 1 [Member] | PEF [Member]
Other marketable securities
Total assets	451			451			378
Derivatives
Net assets	451			451			378
Level 1 [Member] | Equity Securities [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	1,220			1,220			1,061
Level 1 [Member] | Equity Securities [Member] | PEC [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	797			797			690
Level 1 [Member] | Equity Securities [Member] | PEF [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	423			423			371
Level 1 [Member] | Debt Securities [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	131			131			87
Other marketable securities
Other marketable securities	21	[5]		21	[5]		20	[5]
Level 1 [Member] | Debt Securities [Member] | PEC [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	105			105			81
Other marketable securities
Other marketable securities	6	[5]		6	[5]		6	[5]
Level 1 [Member] | Debt Securities [Member] | PEF [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	26			26			6
Other marketable securities
Other marketable securities	2	[6]		2	[6]		1	[6]
Level 2 [Member]
Additional Fair Value Elements [Abstract]
Carrying amount of long term debt including current maturities	13,776			13,776			13,152
Long-term Debt, Fair Value	16,160			16,160			15,518
Derivatives
Derivative assets	1	[1]		1	[1]		5	[1]
Other marketable securities
Total assets	533			533			504
Derivatives
Derivative liabilities	(399)	[2]		(399)	[2]		(775)	[2]
Net assets	134			134			(271)
Level 2 [Member] | PEC [Member]
Additional Fair Value Elements [Abstract]
Carrying amount of long term debt including current maturities	4,838			4,838			4,206
Long-term Debt, Fair Value	5,352			5,352			4,735
Other marketable securities
Total assets	321			321			317
Derivatives
Derivative liabilities	(119)	[2]		(119)	[2]		(224)	[2]
Net assets	202			202			93
Level 2 [Member] | PEF [Member]
Additional Fair Value Elements [Abstract]
Carrying amount of long term debt including current maturities	4,672			4,672			4,681
Long-term Debt, Fair Value	5,646			5,646			5,633
Derivatives
Derivative assets	1	[3]		1	[3]		5	[3]
Other marketable securities
Total assets	212			212			187
Derivatives
Derivative liabilities	(276)	[4]		(276)	[4]		(499)	[4]
Net assets	(64)			(64)			(312)
Level 2 [Member] | Equity Securities [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	6			6			1
Level 2 [Member] | Equity Securities [Member] | PEF [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	6			6			1
Level 2 [Member] | Debt Securities [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	487			487			498
Other marketable securities
Other marketable securities	39	[5]		39	[5]
Level 2 [Member] | Debt Securities [Member] | PEC [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	321			321			317
Level 2 [Member] | Debt Securities [Member] | PEF [Member]
Nuclear decommissioning trust funds
Decommissioning fund investments	166			166			181
Other marketable securities
Other marketable securities	39	[6]		39	[6]
Level 3 [Member]
Derivatives
Derivative liabilities	(36)	[2]		(36)	[2]		(24)	[2]
Net assets	(36)			(36)			(24)
Fair value hierarchy
Derivatives, net at beginning of period	30		37	24		36
Total pre-tax realized or unrealized losses included in earnings - regulated electric	(2)			(2)
Deferred as regulatory assets and liabilities, net	(4)		6	2		7
Issuances	16			16
Settlements	(4)			(4)
Transfers into Level 3			74			74
Derivatives, net at end of period	36		117	36		117
Level 3 [Member] | PEC [Member]
Derivatives
Derivative liabilities	(36)	[2]		(36)	[2]		(24)	[2]
Net assets	(36)			(36)			(24)
Fair value hierarchy
Derivatives, net at beginning of period	28		37	24		36
Total pre-tax realized or unrealized losses included in earnings - regulated electric	(2)			(2)
Deferred as regulatory assets and liabilities, net	(2)		5	2		6
Issuances	16			16
Settlements	(4)			(4)
Derivatives, net at end of period	36		42	36		42
Level 3 [Member] | Commodity Natural Gas Hedges [Member]
Derivatives
Derivative liabilities	(27)			(27)
Level 3 [Member] | Commodity Natural Gas Hedges [Member] | PEC [Member]
Derivatives
Derivative liabilities	(27)			(27)
Level 3 [Member] | FERC Mitigation Power Sale Agreements [Member]
Derivatives
Derivative liabilities	(9)			(9)
Level 3 [Member] | FERC Mitigation Power Sale Agreements [Member] | PEC [Member]
Derivatives
Derivative liabilities	$ (9)			$ (9)
Level 3 [Member] | Maximum [Member] | Commodity Natural Gas Hedges [Member]
Fair Value Inputs Liabilities Quantitative Information [Abstract]
Fair value inputs, price per MMBtu				4.588
Level 3 [Member] | Maximum [Member] | Commodity Natural Gas Hedges [Member] | PEC [Member]
Fair Value Inputs Liabilities Quantitative Information [Abstract]
Fair value inputs, price per MMBtu				4.588
Level 3 [Member] | Maximum [Member] | FERC Mitigation Power Sale Agreements [Member]
Fair Value Inputs Liabilities Quantitative Information [Abstract]
Fair value inputs, price per MWh				49.78
Level 3 [Member] | Maximum [Member] | FERC Mitigation Power Sale Agreements [Member] | PEC [Member]
Fair Value Inputs Liabilities Quantitative Information [Abstract]
Fair value inputs, price per MWh				49.78
Level 3 [Member] | Minimum [Member] | Commodity Natural Gas Hedges [Member]
Fair Value Inputs Liabilities Quantitative Information [Abstract]
Fair value inputs, price per MMBtu				4.178
Level 3 [Member] | Minimum [Member] | Commodity Natural Gas Hedges [Member] | PEC [Member]
Fair Value Inputs Liabilities Quantitative Information [Abstract]
Fair value inputs, price per MMBtu				4.178
Level 3 [Member] | Minimum [Member] | FERC Mitigation Power Sale Agreements [Member]
Fair Value Inputs Liabilities Quantitative Information [Abstract]
Fair value inputs, price per MWh				24.88
Level 3 [Member] | Minimum [Member] | FERC Mitigation Power Sale Agreements [Member] | PEC [Member]
Fair Value Inputs Liabilities Quantitative Information [Abstract]
Fair value inputs, price per MWh				24.88

[1] Included in Prepayments and Other Current Assets within Current Assets and Other within Investments and Other Assets in the Consolidated Balance Sheets.

[2] Included in Derivative Liabilities within Current Liabilities and Other within Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.

[3] Included in Prepayments and Other Current Assets within Current Assets and Other within Investments and Other Assets in the Balance Sheets.

[4] Included in Derivative Liabilities within Current Liabilities and Other within Deferred Credits and Other Liabilities in the Balance Sheets.

[5] Included in Other within Investments and Other Assets in the Consolidated Balance Sheets.

[6] Included in Other within Investments and Other Assets in the Balance Sheets.

XML

Regulatory Matters - Retail Rate Matters (Details) (USD $)	9 Months Ended		9 Months Ended				9 Months Ended			3 Months Ended		9 Months Ended		36 Months Ended												9 Months Ended	12 Months Ended	9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2012 PEC [Member]	Dec. 31, 2011 PEC [Member]	Sep. 30, 2012 PEC [Member] HF Lee Energy Complex [Member]	Sep. 30, 2012 PEC [Member] LV Sutton Plant [Member]	Sep. 30, 2012 PEC [Member] North Carolina Rate Case [Member] North Carolina Rate [Member]	Sep. 30, 2012 PEC [Member] North Carolina Rate Case, net of Energy Efficiency and Demand Side Management [Member] North Carolina Rate [Member]	Sep. 30, 2012 PEF [Member]	Sep. 30, 2012 PEF [Member] Base Rate Settlement Agreement [Member] Regulatory Costs Approved [Member]	Sep. 30, 2011 PEF [Member] Base Rate Settlement Agreement [Member] Regulatory Costs Approved [Member]	Sep. 30, 2012 PEF [Member] Base Rate Settlement Agreement [Member] Regulatory Costs Approved [Member]	Sep. 30, 2011 PEF [Member] Base Rate Settlement Agreement [Member] Regulatory Costs Approved [Member]	Sep. 30, 2012 PEF [Member] Nuclear Cost Recovery [Member] CR3 Outage [Member]		Sep. 30, 2012 PEF [Member] Nuclear Cost Recovery [Member] CR3 Outage [Member] Planned Scenario [Member] M	Sep. 30, 2012 PEF [Member] Nuclear Cost Recovery [Member] CR3 Outage [Member] Previous Bid Scenario [Member] M	Sep. 30, 2012 PEF [Member] Nuclear Cost Recovery [Member] CR3 Outage [Member] Expanded Scope Of Work [Member] M	Sep. 30, 2012 PEF [Member] Nuclear Cost Recovery [Member] CR3 Outage [Member] Worst Case Scenario [Member] M	Sep. 30, 2012 PEF [Member] Nuclear Cost Recovery [Member] CR3 Outage [Member] Minimum [Member]	Sep. 30, 2012 PEF [Member] Nuclear Cost Recovery [Member] CR3 Outage [Member] Maximum [Member]	Sep. 30, 2012 PEF [Member] Nuclear Cost Recovery [Member] Levy Units 1 And 2 [Member]	Sep. 30, 2012 PEF [Member] Nuclear Cost Recovery [Member] Levy Units 1 And 2 [Member] Minimum [Member]	Sep. 30, 2012 PEF [Member] Nuclear Cost Recovery [Member] Levy Units 1 And 2 [Member] Maximum [Member]	Sep. 30, 2012 PEF [Member] Environmental Cost Recovery Clause [Member] Anclote Units 1 And 2 [Member]	Sep. 30, 2012 PEF [Member] 2012 Settlement Agreement [Member] Regulatory Costs Approved [Member] Base Rates Customer Refund And Other [Member]	Dec. 31, 2011 PEF [Member] 2012 Settlement Agreement [Member] Regulatory Costs Approved [Member] Base Rates Customer Refund And Other [Member]	Sep. 30, 2012 PEF [Member] 2012 Settlement Agreement [Member] Regulatory Costs Approved [Member] Crystal River Three [Member]	Sep. 30, 2012 PEF [Member] 2012 Settlement Agreement [Member] Regulatory Costs Approved [Member] Proposed Levy Plant [Member]
Public utilities, disclosure of date of regulatory filing							October 12, 2012
Requested Rate Increase Amount to State Commission							$ 387,000,000	$ 359,000,000
Percent increase in rates							12.00%	11.00%
Increase in rates total																										150,000,000
Return on equity							11.25%
Capital Structure, equity percentage							55.00%
Capital Structure, long-term debt percentage							45.00%
Estimated capital cost of new utility plant, including AFUDC					750,000,000	600,000,000																	19,000,000,000	24,000,000,000	79,000,000
Repair costs, range of possible costs																				900,000,000	1,300,000,000
Independent review repair costs																1,490,000,000	1,550,000,000	2,440,000,000	3,430,000,000
Independent review, estimated time to return to service																35	31	60	96
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														573,000,000
NEIL insurance recoveries related to replacement power costs														(162,000,000)
Amount included in deferred fuel regulatory asset, replacement power costs														411,000,000	[1]
Amount of repair costs incurred														324,000,000
NEIL insurance recoveries related to repair costs														(143,000,000)
Repair costs to be recovered														181,000,000	[1]
Public utilities, cost of removal reserve, reduction taken subject to regulatory order										60,000,000	71,000,000	118,000,000	205,000,000
Public utilities, cost of removal reserve, amount subject to regulatory order										169,000,000		169,000,000
Public utilities, rate of returns, authorized																										11.50%
Public utilities, rate of returns below threshold, subject to regulatory order																										9.50%
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
Replacement power refund																												100,000,000
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
Amount of Reduction to Carrying Amount of Regulatory Liabilities																										47,000,000
Plant in-service date, projected					December 2012	December 2013																2024
NEIL reimbursements withheld														70,000,000
Allocated wholesale costs																												130,000,000	60,000,000
Generation facilities to be retired, net	164,000,000	163,000,000	164,000,000	163,000,000
Net carrying value of retired generating facilities			57,000,000
Asset Retirement Obligation Revision Of Estimate	$ 813,000,000		$ 684,000,000						$ 129,000,000

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

XML

Unaudited Condensed Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Cash flows from operating activities
Net income	$ 373	$ 656
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization (including amortization of nuclear fuel)	678	621
Equity component of AFUDC	(77)	(77)
Severance expense	39	0
FERC mitigation costs	71	0
Community support and charitable contributions expense	40	0
Amount to be refunded to customers (Note 4B)	100	0
Gains on sales of other assets	(21)	0
Deferred income taxes	257	430
Contributions to qualified pension plans	(122)	(313)
Accrued pension and other post-retirement benefit costs	137	89
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions	(12)	37
Receivables	(97)	(109)
Receivables from affiliate	(24)	0
Inventory	60	(151)
Other current assets	(6)	(62)
Increase (decrease) in
Accounts payable	6	(95)
Payables to affiliate	29	0
Taxes accrued	175	156
Other current liabilities	(15)	16
Other assets	0	(48)
Other liabilities	(141)	108
Net cash provided (used) by operating activities	1,450	1,258
Cash flows from investing activities
Capital expenditures	(1,695)	(1,647)
Purchases of available-for-sale securities	(947)	(4,537)
Proceeds from sales and maturities of available-for-sale securities	921	4,509
Insurance proceeds	7	78
Change in restricted cash	24	(7)
Other	81	29
Net cash provided (used) by investing activities	(1,609)	(1,575)
Proceeds from the:
Issuance of long-term debt	1,432	1,286
Issuance of common stock related to employee benefit plans	6	42
Payments for the redemption of long-term debt	(961)	(1,010)
Payments of short-term debt with original maturities greater than 90 days	(65)	0
Proceeds from issuance of short-term debt with original maturities greater than 90 days	65	0
Notes payable and commercial paper	(671)	45
Distributions to noncontrolling interests	(6)	(6)
Dividends paid	(445)	(550)
Notes payable to affiliate	635	0
Other	(4)	2
Net cash provided (used) by financing activities	(14)	(191)
Net increase (decrease) in cash and cash equivalents	(173)	(508)
Cash and cash equivalents at beginning of period	230	611
Cash and cash equivalents at end of period	57	103
Significant noncash transactions
Accrued capital expenditures	250	329
Asset retirement obligation additions	813	3
Capital expenditures financed through capital leases	137	0
PEC [Member]
Cash flows from operating activities
Net income	180	437
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization (including amortization of nuclear fuel)	499	489
Equity component of AFUDC	(50)	(53)
Severance expense	16	0
FERC mitigation costs	71	0
Community support and charitable contributions expense	40	0
Gains on sales of other assets	(2)	0
Deferred income taxes	127	222
Contributions to qualified pension plans	(60)	(207)
Accrued pension and other post-retirement benefit costs	58	32
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions	(33)	(17)
Receivables	(35)	34
Receivables from affiliate	(10)	7
Inventory	23	(142)
Other current assets	(6)	88
Increase (decrease) in
Accounts payable	(20)	(44)
Payables to affiliate	23	(11)
Taxes accrued	62	55
Other current liabilities	16	(8)
Other assets	(19)	(31)
Other liabilities	(27)	37
Net cash provided (used) by operating activities	853	888
Cash flows from investing activities
Capital expenditures	(1,098)	(1,010)
Purchases of available-for-sale securities	(385)	(430)
Proceeds from sales and maturities of available-for-sale securities	359	401
Notes due from affiliate	0	(59)
Other	75	4
Net cash provided (used) by investing activities	(1,049)	(1,094)
Proceeds from the:
Issuance of long-term debt	988	496
Payments for the redemption of long-term debt	(502)	(1)
Notes payable and commercial paper	(188)	0
Dividends paid on preferred stock	(2)	(2)
Dividends to parent	(310)	(450)
Notes payable to affiliate	212	0
Other	(3)	0
Net cash provided (used) by financing activities	195	43
Net increase (decrease) in cash and cash equivalents	(1)	(163)
Cash and cash equivalents at beginning of period	20	230
Cash and cash equivalents at end of period	19	67
Significant noncash transactions
Accrued capital expenditures	144	255
Asset retirement obligation additions	684	3
Capital expenditures financed through capital leases	137	0
PEF [Member]
Cash flows from operating activities
Net income	311	418
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization (including amortization of nuclear fuel)	161	115
Equity component of AFUDC	(27)	(24)
Severance expense	7	0
Amount to be refunded to customers (Note 4B)	100	0
Gains on sales of other assets	(2)	(2)
Deferred income taxes	192	291
Contributions to qualified pension plans	(61)	(104)
Accrued pension and other post-retirement benefit costs	52	38
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions	64	11
Receivables	(76)	(132)
Receivables from affiliate	(12)	1
Inventory	36	(10)
Other current assets	(47)	(58)
Increase (decrease) in
Accounts payable	68	(7)
Payables to affiliate	11	(5)
Taxes accrued	110	105
Other current liabilities	(15)	27
Other assets	21	(2)
Other liabilities	(123)	58
Net cash provided (used) by operating activities	770	720
Cash flows from investing activities
Capital expenditures	(573)	(626)
Purchases of available-for-sale securities	(562)	(4,097)
Proceeds from sales and maturities of available-for-sale securities	561	4,098
Insurance proceeds	7	74
Other	4	28
Net cash provided (used) by investing activities	(563)	(523)
Proceeds from the:
Issuance of long-term debt	0	296
Payments for the redemption of long-term debt	(9)	(309)
Payments of short-term debt with original maturities greater than 90 days	(65)	0
Proceeds from issuance of short-term debt with original maturities greater than 90 days	65	0
Notes payable and commercial paper	(233)	0
Dividends paid on preferred stock	(1)	(1)
Dividends to parent	(170)	(475)
Notes payable to affiliate	213	60
Other	(3)	1
Net cash provided (used) by financing activities	(203)	(428)
Net increase (decrease) in cash and cash equivalents	4	(231)
Cash and cash equivalents at beginning of period	16	249
Cash and cash equivalents at end of period	20	18
Significant noncash transactions
Accrued capital expenditures	102	72
Asset retirement obligation additions	$ 129	$ 0

XML

Regulatory Matters

9 Months Ended

Sep. 30, 2012

Regulatory Matters Disclosure [Line Items]

Regulatory Matters

4.       REGULATORY MATTERS

RATE RELATED INFORMATION

The NCUC, the PSCSC and the FPSC approve rates for retail electric services within their states. The FERC approves rates for electric sales to certain wholesale customers served under cost-based rates, as well as sales of transmission service.

A.       PEC

2012 NORTH CAROLINA RATE CASE

On October 12, 2012, PEC filed an application with the NCUC for an increase in base rates of approximately $387 million, or an average 12% increase in revenues. The request for increase is based upon an 11.25% return on equity and a capital structure of 55% equity and 45% long-term debt. The rate increase is designed primarily to recover the cost of plant modernization and other capital investments in generation, transmission and distribution systems, as well as increased expenditures for nuclear plants and personnel, vegetation management and other operating costs. The rate case includes a corresponding decrease in PEC's energy efficiency (EE) and demand side management (DSM) rider, resulting in a net requested increase of $359 million, or 11% increase in revenues.

PEC expects revised rates, if approved, to go into effect in the second or third quarter of 2013.

JOINT DISPATCH AGREEMENT

On June 29, 2012, and July 2, 2012, the NCUC and the PSCSC, respectively, approved the JDA between Duke Energy Carolinas and PEC. The JDA provides for joint dispatch of the generating facilities of both Duke Energy Carolinas and PEC for the purpose of reducing the cost of serving the native loads of both companies. As set forth in the JDA, Duke Energy Carolinas will act as the joint dispatcher, on behalf of both Duke Energy Carolinas and PEC. As joint dispatcher, Duke Energy Carolinas will direct the dispatch of both Duke Energy Carolinas' and PEC's power supply resources, determine payments between the parties for the purchase and sale of energy between Duke Energy Carolinas and PEC as a result of the JDA, and calculate and allocate the fuel cost savings to the parties as a result of the JDA.

HF LEE AND L.V. SUTTON COMBINED CYCLE FACILITY

PEC is in the process of constructing two new generating facilities, which consist of an approximately 920-MW combined cycle natural gas-fired generating facility at the HF Lee Energy Complex (Lee) in Wayne County, N.C., and an approximately 625-MW natural gas-fired generating facility at theL.V. Sutton plant (Sutton) in New Hanover County, N.C. Lee has an expected in-service date of December 2012 and Sutton has an expected in-service date of December 2013. Based on updated cost estimates, total costs (including allowance for funds used during construction [AFUDC]) for the Lee and Sutton projects are estimated to be approximately $750 million and $600 million, respectively.

HARRIS NUCLEAR PLANT EXPANSION

In 2006, PEC selected a site at its existing Shearon Harris Nuclear Power Plant (Harris) to evaluate for possible future nuclear expansion. On February 19, 2008, PEC filed its combined license (COL) application with the NRC for two Westinghouse Electric AP-1000 reactors at Harris, which the NRC docketed on April 17, 2008. No petitions to intervene have been admitted in the Harris COL application.

B.       PEF

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: the Crystal River Nuclear Plant Unit 3 (CR3) delamination prudence review then pending before the FPSC, PEF's proposed Levy Nuclear Plant (Levy) cost recovery, and certain base rate issues. Refer to each of these respective sections for further discussion.

CR3 OUTAGE

In September 2009, 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, it was determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when an opening was created 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 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 evaluates possible 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.

PEFworked with two potential vendors for repair work and received repair proposals from both vendors. After analyzing those proposals, PEF selected a single vendor that would be engaged to complete the repair of CR3 should the choice to repair be made. See discussion below regarding CR3 cost recovery and other provisions, as a result of a 2012 settlement agreement with the FPSC.

Based on an analysis of possible repair options performed by outside engineering consultants, PEF selected an option, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls. The preliminary cost estimate of $900 million to $1.3 billion is currently under review and could change following completion of further detailed engineering studies, vendor negotiations and final risk assessments. These engineering studies and risk assessments include analyses by independent entities currently in progress. The risk assessment process includes analysis of events that, although currently deemed unlikely, could have a significant impact on the cost estimate or feasibility of repair. This preliminary cost estimate and project scope are under review, as described further below, however, the cost estimate is trending upward.

InMarch 2012, Duke Energy commissioned an independent review team led by Zapata Incorporated (Zapata) to review and assess the PEFCR3 repair plan, including the repair scope, risks, costs and schedule. In its final report, Zapata found that the current repair scope appears to be technically feasible, but there are significant risks that need to be addressed regarding the approach, construction methodology, scheduling and licensing. Zapata performed four separate analyses of the estimated project cost and schedule to repair CR3, including; (i) an independent review of the current repair scope (without existing assumptions or data), of which Zapata estimated costs of $1.49 billion with a project duration of 35 months; (ii) a review of PEF's previous bid information, which included cost estimate data from PEF, of which Zapata estimated costs of $1.55billion with a project duration of 31 months; (iii) an expanded scope of work scenario, that included the PEF scope plus the replacement of the containment building dome and the removal and replacement of concrete in the lower building elevations, of which Zapata estimated costs of approximately $2.44 billion with a project duration of 60 months, and; (iv) a “worst case” scenario, assuming PEF performed the more limited scope of work, and at the conclusion of that work, additional damage occurred in the dome and in the lower elevations, which forced replacement of each, of which Zapata estimated costs of $3.43 billion with a project duration of 96 months.The principal difference between Zapata's estimate and PEF's previous estimate appears to be due to the respective levels of contingencies included by each party, including higher project risk and longer project duration. PEF has filed a copy of the Zapata report with the FPSC and with the NRC.The FPSC held a status conference on October 30, 2012 to discussDuke Energy's analysis of the Zapata report.

PEF continues to analyze the various aspects of the repair option as well as the option of early retirement. This analysis includes the evaluation of the potential implications to scope, cost estimate and schedule from the project risks identified in the Zapata report. A number of factors could affect the decision to repair, the return-to-service date and repair costs incurred, including, but not limited to, state regulatory and NRC reviews, insurance recoveries from Nuclear Electric Insurance Limited (NEIL), the ability to obtain builder's risk insurance with appropriate coverage, final engineering designs, vendor contract negotiations, the ultimate work scope completion, performance testing, weather and the impact of new information discovered during additional testing and analysis. We will proceed with the repair option only if there is a high degree of confidence that the repair can be successfully completed and licensed within the final estimated costs and schedule, and it is in the best interests of PEF's customers, the joint owners and Duke Energy's investors.

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through NEIL. NEIL provides insurance coverage for repair costs for covered events, as well as the cost of replacement power of up to $490 million per event when the unit is out of service as a result of these events. Actual replacement power costs have exceeded 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. NEIL has made payments on the first delamination; however, NEIL has withheld payment of approximately $70 million of replacement power cost claims and repair cost claims related to the first delamination event. NEIL has unresolved concerns and has not made any payments on the second delamination and has not provided a written coverage decision for either 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 that we believe them to owe under the applicable insurance policies. Consistent with the terms and procedures under the insurance coverage with NEIL, we have agreed to mediation prior to commencing any formal dispute resolution. We are in the process of providing information as requested by NEIL and currently have scheduled the mediation to commence in November 2012. Given the circumstances, accounting standards require full recovery to be probable to recognize an insurance receivable. As of September 30, 2012, PEF has no insurance receivables from NEIL related to either the first or second delamination. 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, as discussed above, through September 30, 2012:

(in millions)			Replacement Power Costs		Repair Costs
Spent to date			$	573	$	324
NEIL proceeds received to date				(162)		(143)
	Balance for recovery(a)		$	411	$	181
(a)		See discussion below of PEF's ability to recover prudently incurred fuel and purchased power costs and CR3 repair costs.

As a result of the 2012 settlement agreement with the FPSC, PEF will be permitted to recover prudently incurred fuel and purchased power costs through its fuel clause without regard for the absence of CR3 for the period from the beginning of the CR3 outage through the earlier of the return of CR3 to commercial service or December 31, 2016. 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.

As a result of the ongoing analysis of repair options, including scope, schedule, cost estimate and project risks, PEFhas determined that it is unlikely to be in a position to begin the repair of CR3 prior to December 31, 2012. Consistent with the 2012 settlement agreement regarding the timing of commencement of repairs, PEF recorded a regulatory liability of $100 million related to replacement power obligations. This amount is included within fuel used in electric generation and purchased power in the Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2012.

In the event that repair activities continue beyond December 31, 2016, the parties are not prohibited from contesting PEF's right to recover replacement power costs incurred after 2016. 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 Duke Energy's Board of Directors, will be the basis for project measurement. If costs exceed the board-approved estimate, overruns will be split evenly between Duke Energy 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. The wholesale portion of CR3 investments, which are not covered by the 2012 settlement agreement, totals approximately $130 million as of September 30, 2012. The recoverability of the wholesale portion of CR3 will continue to be evaluated as decisions are made regarding repair or retirement. Recovery of the wholesale portion of CR3 under the retirement option is at risk based on prior treatment of early retired plants in wholesale rates. 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. Retirement of the plant could impact funding obligations associated with PEF's nuclear decommissioning trust fund.

PEF believes the actions taken and costs incurred in response to the CR3 delaminations 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.

PEF is a party to a master participation agreement and other related agreements with the joint owners of CR3 which convey certain rights and obligations on PEF and the joint owners. PEF is meeting with the joint owners on a regular basis to discuss the parties' mutual obligations under these agreements and to better understand their views and positions on these issues. We cannot predict the outcome of this matter.

OTHER BASE RATE MATTERS

As a result 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 increase in revenue requirements effective with the first billing cycle of January 2013, while maintaining the current ROE range of 9.5 percent to 11.5percent. 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 no adjustment for the three months ended September 30, 2012, and a $47 million benefit for the nine months ended September 30, 2012, which reduced O&M expense in its Statements of Operations and Comprehensive Income. Additionally, costs 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 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. In the month following CR3's return to commercial service, PEF's ROE range will increase to between9.7 percent and11.7 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. See the discussion above regarding recovery of CR3 investments if the plant is retired.

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. In 2011, the corresponding charge was recorded as a reduction of operating revenues in PEF's Statements of Operations and Comprehensive Income.

LEVY

On July 30, 2008, PEF filed its COL application with the NRC for two Westinghouse Electric AP-1000 reactors at Levy, which the NRC docketed on October 6, 2008. Various parties filed a joint petition to intervene in the Levy COL application.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 Levy, 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, 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 has shifted 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, Levy is considered to be PEF's preferred baseload generation option.

Under the terms of the 2012 settlement agreement, PEF will beginresidential cost-recovery ofits proposed Levy project effective in the first billing cycle of January 2013 at the fixed rates contained in the settlement 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 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. PEF will true up any actual costs not recovered during the five-year period.

The 2012 settlement agreement also provides that PEF will treat the allocated wholesale cost of Levy (approximately $60 million) 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.

ANCLOTE UNITS 1 AND 2

On March 29, 2012, PEF announced plans to convert the 1,010-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 Environmental Cost Recovery Clause (ECRC). PEF believes this conversion is the most cost-effective alternative for Anclote to achieve and maintain compliance with applicable environmental regulations (See Note 5A). On September 13, 2012, the FPSC approved PEF's request to seek cost recovery through the ECRC.PEF anticipates that both converted units will be placed in service by the end of 2013.

PEF COST OF REMOVAL RESERVE

The 2012 and 2010 settlement agreements provide 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. PEF may not reduce amortization expense if the reduction would cause PEF to exceed the appropriate high point of the ROE range, as established in the settlement agreements. Pursuant to the settlement agreements, PEF recognized a reduction in amortization expense of $60 million and $71 million for the three months ended September 30, 2012 and 2011, respectively. PEF recognized reductions in amortization expense of $118 million and $205 million for the nine months ended September 30, 2012 and 2011, respectively.PEF had eligible cost of removal reserves of $169 millionremaining at September 30, 2012, which is 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.

C.       OTHER REGULATORY MATTERS

On July 6, 2012, the NCUC issued an order initiating investigation and scheduling hearings addressing the timing of the Duke Energy Board of Directors' decision on July 2, 2012, to replace William D. Johnson with James E. Rogers as President and Chief Executive Officer (CEO) of Duke Energy, as well as other related matters.

Pursuant to the merger agreement, William D. Johnson, Chairman, President and CEO of Progress Energy became President and CEO of Duke Energy and James E. Rogers, Chairman, President and CEO of Duke Energy became Executive Chairman of Duke Energy upon close of the merger. Mr. Johnson subsequently resigned as the President and CEO of Duke Energy, effective July 3, 2012, and Mr. Rogers was appointed to be CEO.

Pursuant to the NCUC's July 6, 2012 order, Mr. Rogers appeared before the NCUC on July 10, 2012, and provided testimony regarding the approval and closing of the merger and his replacement of Mr. Johnson as the President and CEO of Duke Energy. On July 19, 2012, Mr. Johnson, as well as E. Marie McKee and James B. Hyler, Jr., both former members of the Progress Energy Board of Directors andcurrent members of the post-merger Duke Energy Board of Directors, appeared before the NCUC. Ann M. Gray and Michael G. Browning, both members of the pre-merger and post-merger Duke Energy Board of Directors, appeared before the NCUC on July 20, 2012. All provided testimony on the timing of the decision to replace Mr. Johnson with Mr. Rogers, as well as other related matters.

The NCUC's order also requests that Duke Energy provide certain documents related to the issue for its review.Duke Energy also received an Investigative Demand issued by the North Carolina Department of Justice (NCDOJ) on July 6, 2012, requesting the production of certain documents related to the issues which are also the subject of the NCUC Investigation. Duke Energy's responses to these requests were submitted on August 7, 2012.On August 1, 2012, the NCUC engaged the law firm of Jenner & Block to conduct an investigation of these matters. That investigation is underway and to date has involved the production of more documents to the NCUC and a series of informal interviews by Jenner & Block of a number of persons with knowledge of these matters, including executive officers of Duke Energy. This process is ongoing and will also involve interviews of the members of the legacy Duke Energy Board of Directors.

Duke Energy has also been contacted by the SEC to explain the circumstances surrounding the NCUC investigation and shareholder lawsuits in connection with the closing of the merger of Duke Energy and Progress Energy. A meeting was held with the SEC staff in late October. Duke Energy intends to continue to assist the SEC staff, as they request.

We are unable to predict the ultimate outcome of these proceedings.

D.       PLANT RETIREMENTS AND ASSET RETIREMENT OBLIGATIONS

PEC filed a plan with the NCUC and the PSCSC to retire all of its coal-fired generating facilities in the Carolinas that do not have scrubbers. On October 1, 2011, PEC retired the Weatherspoon coal-fired generating units, on September 15, 2012, PEC retired the Lee coal-fired generating units, and on October 1, 2012, PEC retired the Cape Fear coal-fired generating units and the H.B. Robinson Unit 1 coal-fired unit. PEC expects to retire the Sutton coal-fired facility by the end of 2013.

In addition, on October 1, 2012, PEC retired six combustion turbine units in North Carolina, totaling approximately 100 MW of capacity.

The net carrying value of the remaining facilities at September 30, 2012, of $164 millionand the net carrying value of the retired facilities of $57 million are included in generation facilities to be retired, net and regulatory assets, respectively, in the Consolidated Balance Sheets. The net carrying value of the retired facilities is expected to be recovered over a 10-year period as presented in our updated depreciation study filed with the NCUC and PSCSC. However, such recovery, including recovery of carrying costs on remaining book values, could be subject to future regulatory approvals and therefore cannot be assured.

PEF is considering the impact pending environmental regulations may have on the Crystal River Units 1 and 2 coal-fired steam turbines (CR1 and CR2), and the possibility of retiring these plants (See Note 5A).

During the three months ended September 30, 2012, we recorded increases to asset retirement obligations of $813 million, including $684 million at PEC and $129 million at PEF, with offsetting increases to asset retirement costs, included in property, plant and equipment in the Balance Sheets. These increases are the result of conforming with Duke Energy's assumptions for the types of estimated costs in the obligations, primarily related to including nuclear spent fuel disposal in the calculation.

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Related Party Transactions (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011
Related party transactions [Line Items]
Guarantee obligations related party	$ 300				$ 300
Corporate Governance And Shared Service [Member]
Related party transactions [Line Items]
Related party transaction, revenues from transactions with related party	30	[1]			30	[1]
Related party transaction, expenses from transactions with related party	31	[2]	0	[2]	31	[2]	0	[2]
Corporate Governance And Shared Service [Member] | PEC [Member]
Related party transactions [Line Items]
Related party transaction, expenses from transactions with related party	72	[2]	48	[2]	183	[2]	155	[2]
Corporate Governance And Shared Service [Member] | PEF [Member]
Related party transactions [Line Items]
Related party transaction, expenses from transactions with related party	52	[2]	41	[2]	136	[2]	122	[2]
Indemnification Coverages [Member]
Related party transactions [Line Items]
Related party transaction, expenses from transactions with related party	7	[3]			7	[3]
Indemnification Coverages [Member] | PEC [Member]
Related party transactions [Line Items]
Related party transaction, expenses from transactions with related party	3	[3]			3	[3]
Indemnification Coverages [Member] | PEF [Member]
Related party transactions [Line Items]
Related party transaction, expenses from transactions with related party	4	[3]			4	[3]
Joint Dispatch Agreement [Member]
Related party transactions [Line Items]
Related party transaction, revenues from transactions with related party	37	[4]			37	[4]
Related party transaction, expenses from transactions with related party	8	[5]			8	[5]
Joint Dispatch Agreement [Member] | PEC [Member]
Related party transactions [Line Items]
Related party transaction, revenues from transactions with related party	37	[4]			37	[4]
Related party transaction, expenses from transactions with related party	$ 8	[5]			$ 8	[5]

[1] PESC charges a proportionate share of corporate governance and other costs to unconsolidated affiliates that are consolidated affiliates of Duke Energy. Corporate governance and other shared costs are primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These charges are recorded as an offset to O&M in the Statements of Operations and Comprehensive Income.

[2] Progress Energy Registrants are charged their proportionate share of corporate governance and other costs by PESC (only applicable to PEC and PEF) and an unconsolidated affiliate that is a consolidated affiliate of Duke Energy. Corporate governance and other shared costs are primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These expenses are recorded in O&M in the Statements of Operations and Comprehensive Income.

[3] Effective with the consummation of the merger, Progress Energy Registrants incur expenses related to certain indemnification coverages through Bison, Duke Energy's wholly owned captive insurance subsidiary. These expenses are recorded in O&M in the Statements of Operations and Comprehensive Income.

[4] Effective with the consummation of the merger, PEC and Duke Energy Carolinas began to participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customers' rates (See Note 4). The revenues from the sale of power to Duke Energy Carolinas are recorded in regulated electric revenues in the Consolidated Statements of Operations and Comprehensive Income.

[5] Effective with the consummation of the merger, PEC and Duke Energy Carolinas began to participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customers' rates (See Note 4). The expenses from the purchase of power from Duke Energy Carolinas are recorded in fuel used in electric generation and purchased power in the Consolidated Statements of Operations and Comprehensive Income.

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Financial Information by Business Segment (Tables)

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Business segment data

BUSINESS SEGMENT DATA
(in millions)			Unaffiliated Revenues		Affiliated Revenues		Total Revenues		Segment Income/ Consolidated Net Income(a)
Three months ended September 30, 2012
Franchised Electric			$	2,747	$	39	$	2,786	$	333
	Total reportable segment			2,747		39		2,786		333
Other				3		0		3		(181)(b)
Eliminations				0		(1)		(1)		0
Add back of noncontrolling interest component				0		0		0		2
Income from discontinued operations, net of tax				0		0		0		3
	Total consolidated		$	2,750	$	38	$	2,788	$	157
Three months ended September 30, 2011
Franchised Electric			$	2,750	$	0	$	2,750	$	408
	Total reportable segment			2,750		0		2,750		408
Other				3		0		3		(117)(b)
Add back of noncontrolling interest component				0		0		0		2
	Total consolidated		$	2,753	$	0	$	2,753	$	293
(in millions)			Unaffiliated Revenues		Affiliated Revenues		Total Revenues		Segment Income/ Consolidated Net Income(a)
Nine months ended September 30, 2012
Franchised Electric			$	7,132	$	40	$	7,172	$	636
	Total reportable segment			7,132		40		7,172		636
Other				8		0		8		(278)(b)
Eliminations				0		(2)		(2)		0
Add back of noncontrolling interest component				0		0		0		5
Income from discontinued operations, net of tax				0		0		0		10
	Total consolidated		$	7,140	$	38	$	7,178	$	373
Nine months ended September 30, 2011
Franchised Electric			$	7,188	$	1	$	7,189	$	874
	Total reportable segment			7,188		1		7,189		874
Other				8		0		8		(219)(b)
Eliminations				0		(1)		(1)		0
Add back of noncontrolling interest component				0		0		0		5
Loss from discontinued operations, net of tax				0		0		0		(4)
	Total consolidated		$	7,196	$	0	$	7,196	$	656
(a)		Segment income excludes noncontrolling interests and results of entities classified as discontinued operations.
(b)		Segment income includes after-tax costs to achieve the merger with Duke Energy of $132 million and $149 million for the three and nine months ended September 30, 2012, respectively, and $9 million and $27 million for the three and nine months ended September 30, 2011, respectively.

Segment assets

SEGMENT ASSETS
Segment assets in the following table exclude all intercompany assets between the Progress Energy Registrants.
(in millions)			September 30, 2012		December 31, 2011
Franchised Electric			$	36,135	$	34,166
	Total reportable segment			36,135		34,166
Other				549		765
Reclassifications(a)				(33)		0
	Total consolidated assets		$	36,651	$	34,931
(a)		Primarily represents reclassification of federal tax balances in consolidation.

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Organization and Summary of Significant Accounting Policies (Details) (USD $)	Sep. 30, 2012	Dec. 31, 2011
Disclosure Organization And Summary Of Significant Accounting Policies [Line Items]
Consideration transferred in the merger	$ 18,000,000,000
Unbilled accounts receivable	190,000,000	157,000,000
PEC [Member]
Disclosure Organization And Summary Of Significant Accounting Policies [Line Items]
Unbilled accounts receivable	99,000,000	102,000,000
PEF [Member]
Disclosure Organization And Summary Of Significant Accounting Policies [Line Items]
Unbilled accounts receivable	$ 91,000,000	$ 55,000,000

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Income Taxes

9 Months Ended

Sep. 30, 2012

Income Taxes Disclosure [Line Items]

Income Taxes

14.       INCOME TAXES AND OTHER TAXES

INCOME TAXES

Progress Energy and its subsidiaries file income tax returns in the U.S. with federal and various state governmental authorities. Progress Energy and its subsidiaries have a tax sharing agreement where the separate return method is used to allocate tax expenses and benefits to the subsidiaries whose investments or results of operations provide these tax expenses and benefits. The accounting for income taxes essentially represents the income taxes that each of these subsidiaries would incur if it were a separate company filing its own tax return as a C-corporation.

The effective tax rates for each of the Progress Energy Registrants are as follows:

	Three months ended September 30				Nine months ended September 30
	2012		2011		2012		2011
Progress Energy	32.8	%	37.8	%	34.7	%	36.9	%
PEC	31.9	%	33.4	%	31.6	%	34.2	%
PEF	35.9	%	37.0	%	36.9	%	37.0	%

For the three and nine months ended September 30, 2012, Progress Energy's effective tax rate decreased primarily due toadecrease in pretax income as well as adecrease in the changein fair value of outstanding CVOs.

In addition, for the three and nine months ended September 30, 2012, PEC's effective tax rate decreased primarily due to a decrease in pretax income.

In addition, for the three and nine months ended September 30, 2012, PEF's effective tax ratehad an insignificant change.

For the three and nine months ended September 30, 2012, Progress Energy's effective tax rate decreased primarily due toadecrease in pretax income as well as adecrease in the changein fair value of outstanding CVOs.

In addition, for the three and nine months ended September 30, 2012, PEC's effective tax rate decreased primarily due to a decrease in pretax income.

In addition, for the three and nine months ended September 30, 2012, PEF's effective tax ratehad an insignificant change.

EXCISE TAXES

Certain excise taxes levied by state or local governments are collected by the Utilities from their customers. Taxesthat are required to be paid regardless of the ability to collect from the customer are accounted for on a gross basis. When the Utilities act as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis. Excise taxes accounted for on a gross basis and recorded as revenues and other tax expense in the respective Statements of Operations and Comprehensive Income were as follows:

	Three months ended September 30				Nine months ended September 30
(in millions)	2012		2011		2012		2011
PEC	$	33	$	33	$	85	$	86
PEF		62		63		156		159
Progress Energy	$	95	$	96	$	241	$	245