Ranger Oil 10Q 2009 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2009

¨	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: 1-13283

PENN VIRGINIA CORPORATION

(Exact name of registrant as specified in its charter)

Virginia	23-1184320
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

THREE RADNOR CORPORATE CENTER, SUITE 300

100 MATSONFORD ROAD

RADNOR, PA 19087

(Address of principal executive offices) (Zip Code)

(610) 687-8900

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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

Indicate by check mark whether the registrant has submitted electronically and posted on 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 registrant was required to submit and post such files). Yes ¨ No ¨

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

Large accelerated filer	x	Accelerated filer	¨

Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

As of October 31, 2009, 45,385,352 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

INDEX

		Page
PART I.	Financial Information	1

Item 1.	Financial Statements	1

	Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2009 and 2008	1

	Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008	2

	Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2009 and 2008	3

	Notes to Consolidated Financial Statements	4

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45

Item 4.	Controls and Procedures	48

PART II.	Other Information	49

Item 6.	Exhibits	49

PART I. FINANCIAL INFORMATION

Item 1 Financial Statements

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME – unaudited

(in thousands, except per share data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Revenues
Natural gas	$	36,654		$	101,911		$	129,305		$	295,636
Crude oil		13,259			13,764			31,412			37,442
Natural gas liquids (NGLs)		2,847			10,481			10,553			18,887
Natural gas midstream		102,262			184,914			289,123			494,260
Coal royalties		29,821			33,308			90,448			88,911
Gain on sale of property and equipment		1,945			31,279			1,918			31,335
Other		8,375			9,955			25,481			28,690
Total revenues		195,163			385,612			578,240			995,161

Expenses
Cost of midstream gas purchased		77,248			155,564			228,579			408,247
Operating		21,167			23,437			66,517			66,653
Exploration		16,117			8,346			54,901			19,765
Taxes other than income		5,294			7,671			16,656			23,325
General and administrative		19,946			18,289			58,787			55,006
Depreciation, depletion and amortization		57,869			49,978			173,160			133,481
Impairments on assets held for sale		87,900			-			87,900			-
Other impairments		4,453			-			8,928			-
Loss on sale of assets		-			-			1,599			-
Total expenses		289,994			263,285			697,027			706,477

Operating income (loss)		(94,831	)		122,327			(118,787	)		288,684

Other income (expense)
Interest expense		(22,784	)		(13,221	)		(50,332	)		(35,313	)
Derivatives		(2,529	)		125,132			8,478			(4,387	)
Other		348			(4,088	)		2,274			(782	)

Income (loss) before income taxes and noncontrolling interests		(119,796	)		230,150			(158,367	)		248,202
Income tax benefit (expense)		50,405			(78,921	)		69,587			(74,352	)

Net income (loss)		(69,391	)		151,229			(88,780	)		173,850
Less net income attributable to noncontrolling interests		(10,509	)		(28,276	)		(20,512	)		(52,252	)

Income (loss) attributable to Penn Virginia Corporation	$	(79,900	)	$	122,953		$	(109,292	)	$	121,598

Earnings (loss) per share - basic and diluted:
Earnings (loss) per share attributable to Penn Virginia Corporation
Basic	$	(1.76	)	$	2.94		$	(2.52	)	$	2.91
Diluted	$	(1.76	)	$	2.88		$	(2.52	)	$	2.88

Weighted average shares outstanding, basic		45,427			41,881			43,324			41,715
Weighted average shares outstanding, diluted		45,427			42,544			43,324			42,028

The accompanying notes are an integral part of these consolidated financial statements.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands, except share data)

	September 30,			December 31,
	2009			2008
Assets
Current assets
Cash and cash equivalents	$	105,034		$	18,338
Accounts receivable, net of allowance for doubtful accounts		100,454			149,241
Derivative assets		25,675			67,569
Inventory		12,134			18,468
Assets held for sale		47,107			-
Other current assets		3,079			9,902
Total current assets		293,483			263,518

Property and equipment
Oil and gas properties (successful efforts method)		1,939,442			2,107,128
Other property and equipment		1,139,449			1,076,471
Total property and equipment		3,078,891			3,183,599
Accumulated depreciation, depletion and amortization		(706,568	)		(671,422	)
Net property and equipment		2,372,323			2,512,177

Equity investments		87,520			78,443
Intangibles, net		87,108			92,672
Derivative assets		1,950			4,070
Other assets		58,885			45,685
Total assets	$	2,901,269		$	2,996,565

Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	-		$	7,542
Accounts payable and accrued liabilities		120,180			206,902
Derivative liabilities		16,261			15,534
Deferred taxes		1,776			17,598
Income taxes payable		7,139			18
Total current liabilities		145,356			247,594

Other liabilities		43,797			45,887
Derivative liabilities		7,217			8,721
Deferred income taxes		217,820			258,037
Long-term debt of PVR		628,100			568,100
Revolving credit facility		-			332,000
Senior notes		291,432			-
Convertible notes		204,935			199,896

Shareholders’ equity:
Common stock of $0.01 par value – 64,000,000 shares authorized; shares issued and
outstanding of 45,385,258 and 41,870,893 at September 30, 2009 and December 31, 2008		265			230
Paid-in capital		704,147			599,855
Retained earnings		327,076			443,646
Deferred compensation obligation		2,282			2,237
Accumulated other comprehensive loss		(1,598	)		(4,182	)
Treasury stock – 106,558 and 85,227 shares common stock, at cost, on
September 30, 2009 and December 31, 2008		(2,791	)		(2,683	)
Total Penn Virginia Corporation shareholders’ equity		1,029,381			1,039,103
Noncontrolling interests of subsidiaries		333,231			297,227
Total shareholders’ equity		1,362,612			1,336,330
Total liabilities and shareholders’ equity	$	2,901,269		$	2,996,565

The accompanying notes are an integral part of these consolidated financial statements.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008

Cash flows from operating activities
Net income (loss)	$	(69,391	)	$	151,229		$	(88,780	)	$	173,850
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation, depletion and amortization		57,869			49,978			173,160			133,481
Impairments		92,353			-			96,828			-
Commodity derivative contracts:
Total derivative losses (gains)		6,312			(123,628	)		(2,821	)		8,516
Cash settlements of derivatives		15,507			(19,755	)		51,936			(46,740	)
Deferred income taxes		(51,928	)		61,552			(70,728	)		60,105
Dry hole and unproved leasehold expense		10,593			5,520			30,476			14,992
Other		2,685			(27,374	)		16,064			(26,118	)
Changes in operating assets and liabilities		20,046			(5,727	)		15,888			(41,399	)
Net cash provided by operating activities		84,046			91,795			222,023			276,687

Cash flows from investing activities
Acquisitions		(32,068	)		(162,078	)		(38,261	)		(278,185	)
Additions to property, plant and equipment		(25,363	)		(162,857	)		(218,558	)		(392,031	)
Other		2,876			33,215			8,698			33,954
Net cash used in investing activities		(54,555	)		(291,720	)		(248,121	)		(636,262	)

Cash flows from financing activities
Dividends paid		(2,559	)		(2,351	)		(7,278	)		(7,037	)
Distributions paid to noncontrolling interest holders		(18,455	)		(17,917	)		(55,365	)		(45,829	)
Proceeds from (repayments of) bank borrowings		-			46,431			(7,542	)		46,431
Net proceeds from PVR borrowings		31,000			176,600			60,000			146,000
Net proceeds from (repayments of) Company borrowings		(70,000	)		(25,000	)		(332,000	)		58,000
Net proceeds from issuance of senior notes		-			-			291,009			-
Net proceeds from issuance of PVR partners' capital		-			-			-			138,015
Net proceeds from the sale of PVG units		118,080			-			118,080			-
Net proceeds from issuance of equity		-			-			64,835			-
Other		(860	)		(2,311	)		(18,945	)		8,475
Net cash provided by financing activities		57,206			175,452			112,794			344,055

Net increase (decrease) in cash and cash equivalents		86,697			(24,473	)		86,696			(15,520	)
Cash and cash equivalents – beginning of period		18,337			43,480			18,338			34,527
Cash and cash equivalents – end of period	$	105,034		$	19,007		$	105,034		$	19,007

Supplemental disclosure:
Cash paid (received) during the periods for:
Interest	$	6,055		$	8,599		$	31,309		$	26,490
Income taxes	$	(1,047	)	$	2,791		$	1,906		$	4,970

The accompanying notes are an integral part of these consolidated financial statements.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – unaudited

September 30, 2009

1. Organization

Penn Virginia Corporation (“Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company primarily engaged in the development, exploration and production of natural gas and oil in various domestic onshore regions including East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast. We also indirectly own partner interests in Penn Virginia Resource Partners, L.P. (“PVR”), a publicly traded limited partnership formed by us in 2001. Our ownership interests in PVR are held principally through our general partner interest and 51.4% limited partner interest in Penn Virginia GP Holdings, L.P. (“PVG”), a publicly traded limited partnership formed by us in 2006. As of September 30, 2009, PVG owned an approximately 37% limited partner interest in PVR and 100% of the general partner of PVR, which holds a 2% general partner interest in PVR and all of the incentive distribution rights.

We are engaged in three primary business segments: (i) oil and gas, (ii) coal and natural resource management and (iii) natural gas midstream. We directly operate our oil and gas segment and PVR operates our coal and natural resource management and natural gas midstream segments.

2. Basis of Presentation

Our consolidated financial statements include the accounts of Penn Virginia and all of its subsidiaries, including PVG and PVR. Investments in non-controlled entities over which we exercise significant influence are accounted for using the equity method. Intercompany balances and transactions have been eliminated in consolidation. Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our consolidated financial statements have been included. Our consolidated financial statements should be read in conjunction with our consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2008. Operating results for the three and nine months ended September 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009. Certain reclassifications have been made to conform to the current period’s presentation. In preparing the accompanying consolidated financial statements, we have evaluated subsequent events through November 5, 2009.

3. Noncontrolling Interests

Effective January 1, 2009, we adopted the new accounting standard on noncontrolling interests in consolidated financial statements. This standard requires that the noncontrolling interests in PVG and PVR be reported on our consolidated balance sheets as a separate item within shareholders’ equity. Net income attributable to the noncontrolling interests in PVG and PVR is separately presented on the face of our consolidated statements of income. Our consolidated financial statements have been retroactively adjusted to reflect the adoption of this standard. Comprehensive income attributable to the noncontrolling interests in PVG and PVR is separately presented in our schedule of comprehensive income. The standard also requires that gains from the sales of subsidiary units be recorded directly to shareholders’ equity. If we sell sufficient controlling interests in our subsidiaries to require deconsolidation of those subsidiaries, then we expect to record a gain or loss on our consolidated statements of income.

The following is a reconciliation of the carrying amount of shareholders’ equity attributable to us, shareholders’ equity attributable to the noncontrolling interests in PVG and PVR and total shareholders’ equity:

	Penn Virginia						Total
	Corporation			Noncontrolling			Shareholders'			Comprehensive
	Shareholders			Interests			Equity			Income (Loss)
	(in thousands)
Balance at December 31, 2008	$	1,039,103		$	297,227		$	1,336,330
Dividends paid ($0.05625 per share)		(7,276	)		-			(7,276	)
Distributions to noncontrolling interests holders		-			(55,365	)		(55,365	)
Issuance of equity		64,835			-			64,835
Sale of PVG units		32,739			67,713			100,452
Other changes to shareholders' equity		6,688			2,416			9,104
Comprehensive income:
Net income (loss)		(109,292	)		20,512			(88,780	)	$	(88,780	)
Hedging unrealized gain (loss), net of tax		291			(353	)		(62	)		(62	)
Hedging reclassification adjustment, net of tax		2,293			1,081			3,374			3,374
Balance at September 30, 2009	$	1,029,381		$	333,231		$	1,362,612		$	(85,468	)

Balance at December 31, 2007	$	835,793		$	174,420		$	1,010,213
Dividends paid ($0.05625 per share)		(7,039	)		-			(7,039	)
Distributions to noncontrolling interests holders		-			(45,829	)		(45,829	)
Issuance of PVR units		-			138,015			138,015
Recognition of SAB 51 gain		39,723			(39,723	)		-
Sale of PVG units		36,429			-			36,429
Change related to acquisition		-			23,469			23,469
Other changes to shareholders' equity		14,967			1,845			16,812
Comprehensive income:
Net income		121,598			52,252			173,850		$	173,850
Hedging unrealized loss, net of tax		(408	)		(1,657	)		(2,065	)		(2,065	)
Hedging reclassification adjustment, net of tax		220			4,561			4,781			4,781
Balance at September 30, 2008	$	1,041,283		$	307,353		$	1,348,636		$	176,566

In September 2009, we sold 10,000,000 common units of PVG owned by us for $118.1 million, which increased noncontrolling interests by $67.7 million and additional paid-in capital by $50.4 million less $17.7 million in taxes. Prior to the sale, we owned 30,077,429 PVG common units, representing a 77.0% limited partner interest in PVG. After the sale, we owned 20,077,429 PVG common units, representing a 51.4% limited partner interest in PVG.

The following table discloses the effects of changes in our ownership interest in PVG on our equity:

	Three Months Ended			Nine Months Ended
	September 30, 2009			September 30, 2009
	(in thousands)
Loss attributable to PennVirginia Corporation	$	(79,900	)	$	(109,292	)
Transfer to noncontrolling interests
Increase in PennVirginia Corporation's paid-in capital
for sale of PVG units, net of $17,629 in taxes		32,739			32,739
Changes from loss attributable to PennVirginia Corporation and transfer to noncontrolling interests	$	(47,161	)	$	(76,553	)

4. Fair Value Measurements

Effective January 1, 2009, we adopted the new accounting standard on fair value measurements and disclosures applicable to both our financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis. Our financial instruments that are subject to fair value disclosures consist of cash and cash equivalents, accounts receivable, assets held for sale, accounts payable, derivative instruments and long-term debt. We have followed consistent methods and assumptions to estimate the fair values as more fully described in our Annual Report on Form 10-K for the year ended December 31, 2008. In addition to those methods, the fair value of assets held for sale was derived using a market approach based on indications of interest from potential third-party purchasers of the assets. At September 30, 2009, the carrying values of all of these financial instruments, except the portion of long-term debt attributable to our 4.50% Convertible Senior Subordinated Notes due 2012 (the “Convertible Notes”), approximated fair value. The fair value of the portion of our long-term debt attributable to the Convertible Notes at September 30, 2009 was $206.9 million, which was derived from quoted market prices.

The following table summarizes the valuation of certain assets and liabilities by category as of September 30, 2009:

				Fair Value Measurement at September 30, 2009, Using
Description	Fair Value Measurements at September 30, 2009			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
				(in thousands)
Publicly traded equities	$	5,257		$	5,257		$	-		$	-
Deferred compensation - noncurrent liability		(5,955	)		(5,955	)		-			-
Interest rate swap assets - noncurrent		1,138			-			1,138			-
Interest rate swap liabilities - current		(10,629	)		-			(10,629	)		-
Interest rate swap liabilities - noncurrent		(4,548	)		-			(4,548	)		-
Commodity derivative assets - current		25,674			-			25,674			-
Commodity derivative assets - noncurrent		813			-			813			-
Commodity derivative liabilities - current		(5,631	)		-			(5,631	)		-
Commodity derivative liabilities - noncurrent		(2,670	)		-			(2,670	)		-
Assets held for sale		47,107			-			47,107			-
Total	$	50,556		$	(698	)	$	51,254		$	-

See Note 5, “Derivative Instruments,” for the effects of derivative instruments on our consolidated financial statements.

5. Derivative Instruments

Commodity Derivatives

Oil and Gas Segment

We determine the fair values of our oil and gas derivative agreements using third-party quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil as of the end of the reporting period and discount rates adjusted for the credit risk of our counterparties if the derivative in an asset position and our own credit risk if the derivative is in a liability position. ��The following table sets forth our oil and gas commodity derivative positions as of September 30, 2009:

	Average	Weighted Average Price						Fair Value at
	Volume	Additional						September 30,
	Per Day	Put Option		Floor		Ceiling		2009
								(in thousands)
Natural Gas Costless Collars	(MMBtu)	($ per MMBtu)
Fourth Quarter 2009	15,000				4.25		5.70	$	64
First Quarter 2010	35,000				4.96		7.41		(325	)
Second Quarter 2010	30,000				5.33		8.02		539
Third Quarter 2010	30,000				5.33		8.02		204
Fourth Quarter 2010	50,000				5.65		8.77		201
First Quarter 2011	50,000				5.65		8.77		(1,266	)
Second Quarter 2011	30,000				5.67		7.58		(188	)
Third Quarter 2011	30,000				5.67		7.58		(498	)

Natural Gas Three-Way Collars	(MMBtu)	($ per MMBtu)
Fourth Quarter 2009	30,000		6.83		9.50		13.60		7,084
First Quarter 2010	30,000		6.83		9.50		13.60		6,055

Natural Gas Swaps	(MMBtu)	($ per MMBtu)
Fourth Quarter 2009	40,000				4.91				579
First Quarter 2010	15,000				6.19				297
Second Quarter 2010	30,000				6.17				554
Third Quarter 2010	30,000				6.17				(31	)

Crude Oil Three-Way Collars	(barrels)	($ per barrel)
Fourth Quarter 2009	500		80.00		110.00		179.00		1,315

Crude Oil Swaps	(barrels)	($ per barrel)
Fourth Quarter 2009	500				59.25				(541	)

Crude Oil Costless Collars	(barrels)	($ per barrel)
First Quarter 2010	500				60.00		74.75		(159	)
Second Quarter 2010	500				60.00		74.75		(227	)
Third Quarter 2010	500				60.00		74.75		(271	)
Fourth Quarter 2010	500				60.00		74.75		(317	)

Settlements to be paid in subsequent period									297

Oil and gas segment commodity derivatives - net asset								$	13,366

See the “Financial Statement Impact of Derivatives” section below for the impact of our oil and gas commodity derivatives on our consolidated financial statements.

PVR Natural Gas Midstream Segment

PVR determines the fair values of its derivative agreements using quoted forward prices for the respective commodities as of the end of the reporting period and discount rates adjusted for the credit risk of PVR’s counterparties if the derivative is in an asset position and PVR’s own credit risk if the derivative is in a liability position. The following table sets forth PVR’s positions as of September 30, 2009 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:

	Average			Weighted Average Price						Fair Value at
	Volume	Swap		Additional						September 30,
	Per Day	Price		Put Option		Put		Call		2009
										(in thousands)
Crude Oil Three-Way Collar	(barrels)					($ per barrel)
Fourth Quarter 2009	1,000				70.00		90.00		119.25	$	1,433

Frac Spread Collar	(MMBtu)					($ per MMBtu)
Fourth Quarter 2009	6,000						9.09		13.94		864

Crude Oil Collar	(barrels)					($ per barrel)
First Quarter 2010 through Fourth Quarter 2010	750						70.00		81.25		228

Crude Oil Collar	(barrels)					($ per barrel)
First Quarter 2010 through Fourth Quarter 2010	1,000						68.00		80.00		(155	)

Natural Gas Purchase Swap	(MMBtu)	($ per MMbtu)
First Quarter 2010 through Fourth Quarter 2010	5,000		5.815								709

Settlements to be received in subsequent period											1,742

Natural gas midstream segment commodity derivatives - net asset										$	4,821

See the “Financial Statement Impact of Derivatives” section below for the impact of PVR’s natural gas midstream commodity derivatives on our consolidated financial statements.

Interest Rate Swaps

In 2006, we entered into interest rate swaps (the “Interest Rate Swaps”) with notional amounts of $50.0 million to establish fixed interest rates on a portion of the then outstanding borrowings under our revolving credit facility (the “Revolver”) through December 2010. During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps were recognized in the derivative line item on our consolidated statements of income.

We reported a net derivative liability of $2.9 million at September 30, 2009 related to the Interest Rate Swaps. In September 2009, we paid off all amounts outstanding under the Revolver and, as a result, we reclassified the net hedging losses remaining in accumulated other comprehensive income (“AOCI”) related to the Interest Rate Swaps from AOCI to interest expense. In connection with periodic settlements and the pay down of the Revolver, we reclassified a total of $3.4 million of net hedging losses on the Interest Rate Swaps from AOCI to interest expense during the nine months ended September 30, 2009. See the “Financial Statement Impact of Derivatives” section below for the impact of the Interest Rate Swaps on our consolidated financial statements.

PVR Interest Rate Swaps

PVR has entered into interest rate swaps (the “PVR Interest Rate Swaps”) to establish fixed interest rates on a portion of the outstanding borrowings under its revolving credit facility (the “PVR Revolver”). The following table sets forth the PVR Interest Rate Swap positions at September 30, 2009:

Dates	Notional Amounts		Weighted-Average Fixed Rate
	(in millions)
Until March 2010	$	310.0		3.54	%
March 2010 - December 2011	$	250.0		3.37	%
December 2011 - December 2012	$	100.0		2.09	%

During the first quarter of 2009, PVR discontinued hedge accounting for all of the PVR Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the PVR Interest Rate Swaps are recognized in the derivatives line item on our consolidated statements of income. At September 30, 2009, a $2.2 million loss remained in AOCI related to the PVR Interest Rate Swaps. The $2.2 million loss will be recognized in interest expense as the PVR Interest Rate Swaps settle.

PVR reported a (i) net derivative liability of $11.2 million at September 30, 2009 and (ii) loss in AOCI of $2.2 million at September 30, 2009 related to the PVR Interest Rate Swaps. In connection with periodic settlements, PVR reclassified a total of $2.6 million of net hedging losses on the PVR Interest Rate Swaps from AOCI to interest expense during the nine months ended September 30, 2009. See the “Financial Statement Impact of Derivatives” section below for the impact of the PVR Interest Rate Swaps on our consolidated financial statements.

Financial Statement Impact of Derivatives

The following table summarizes the effects of our and PVR’s derivative activities, as well as the location of the gains and losses, on our consolidated statements of income for the three and nine months ended September 30, 2009 and 2008:

	Location of gain (loss)	Three Months Ended						Nine Months Ended
	on derivatives recognized	September 30,						September 30,
	in income	2009			2008			2009			2008
		(in thousands)
Derivatives de-designated as hedging instruments:
Interest rate contracts (1)	Interest expense	$	(3,781	)	$	(1,179	)	$	(6,464	)	$	(1,891	)
Increase (decrease) in net income resulting from derivatives de-designated as hedging instruments			(3,781	)		(1,179	)		(6,464	)		(1,891	)

Derivatives not designated as hedging instruments:
Interest rate contracts	Derivatives		(4,368	)		(1,333	)		(3,849	)		(1,333	)
Commodity contracts (1)	Natural gas midstream revenues		-			(1,987	)		-			(6,235	)
Commodity contracts (1)	Cost of midstream gas purchased		-			484			-			2,107
Commodity contracts	Derivatives		1,839			126,464			12,327			(3,055	)
Increase (decrease) in net income resulting from derivatives not designated as hedging instruments			(2,529	)		123,628			8,478			(8,516	)

Total increase (decrease) in net income resulting from derivatives		$	(6,310	)	$	122,449		$	2,014		$	(10,407	)

Realized and unrealized derivative impact:
Cash received (paid) for commodity and interest rate settlements	Derivatives	$	15,507		$	(19,755	)	$	51,936		$	(46,740	)
Cash paid for interest rate contract settlements	Interest expense		-			(1,179	)		(808	)		(1,891	)
Unrealized derivative gain (loss) (2)			(21,817	)		143,383			(49,114	)		38,224
Total increase (decrease) in net income resulting from derivatives		$	(6,310	)	$	122,449		$	2,014		$	(10,407	)

(1)	Represents amounts reclassified out of AOCI and into interest expense. At September 30, 2009, a $2.2 million loss remained in AOCI related to the PVR Interest Rate Swaps on which PVR discontinued hedge accounting.

(2)	Represents net unrealized gains (losses) in the natural gas midstream, cost of midstream gas purchased, interest expense and derivatives line items on our consolidated statements of income.

The following table summarizes the fair value of our and PVR’s derivative instruments, as well as the locations of these instruments, on our consolidated balance sheets as of September 30, 2009 and December 31, 2008:

		Fair Values at				Fair Values at
		September 30, 2009				December 31, 2008
		Derivative		Derivative		Derivative		Derivative
	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(in thousands)
Derivatives de-designated as hedging instruments:
Interest rate contracts	Derivative liabilities - current	$	xx	$	-	$	-	$	3,177
Interest rate contracts	Derivative liabilities - noncurrent		-		-		-		3,648
Total derivatives de-designated as hedging instruments			-		-		-		6,825

Derivatives not designated as hedging instruments:
Interest rate contracts	Derivative assets/liabilities - current		-		10,629		-		4,663
Interest rate contracts	Derivative assets/liabilities - noncurrent		1,138		4,548		-		5,073
Commodity contracts	Derivative assets/liabilities - current		25,674		5,631		67,569		7,694
Commodity contracts	Derivative assets/liabilities - noncurrent		813		2,670		4,070		-
Total derivatives not designated as hedging instruments			27,625		23,478		71,639		17,430

Total fair value of derivative instruments		$	27,625	$	23,478	$	71,639	$	24,255

See Note 4, “Fair Value Measurements,” for a description of how the above-described financial instruments are valued.

The following table summarizes our interest expense for the three and nine months ended September 30, 2009 and 2008, including the effect of the Interest Rate Swaps and the PVR Interest Rate Swaps:

	Three Months Ended September 30,						Nine Months Ended September 30,
Source	2009			2008			2009			2008
	(in thousands)
Interest on borrowings	$	19,567		$	12,534		$	45,565		$	35,652
Capitalized interest		(566	)		(492	)		(1,697	)		(2,230	)
Interest rate swaps		3,783			1,179			6,464			1,891
Total interest expense	$	22,784		$	13,221		$	50,332		$	35,313

At September 30, 2009, we reported a commodity derivative asset related to our oil and gas segment of $13.4 million. At September 30, 2009, we reported a commodity derivative asset related to the PVR natural gas midstream segment of $4.8 million. The contracts underlying such commodity derivative asset are with four counterparties, all of which are investment grade financial institutions, and such commodity derivative asset is substantially concentrated with one of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. Neither we nor PVR paid or received collateral with respect to our or PVR’s derivative positions. The maximum amount of loss due to credit risk if counterparties to our or PVR’s derivative asset positions fail to perform according to the terms of the contracts would be equal to the fair value of the contracts as of September 30, 2009. No significant uncertainties related to the collectability of amounts owed to us or PVR exist with regard to these counterparties.

The above-described hedging activity represents cash flow hedges. As of September 30, 2009, neither we nor PVR owned any derivative instruments that were classified as fair value hedges or trading securities or that contained credit risk contingencies.

6. Common Stock Offering

On May 22, 2009, we completed the sale of 3.5 million shares of our common stock in a registered public offering. The net sales proceeds of $64.8 million were used to repay borrowings under the Revolver.

7. Long-Term Debt

The long-term debt on our consolidated balance sheet as of September 30, 2009 consisted of our 10.375% Senior Notes due 2016 (the “Senior Notes”), the Convertible Notes and PVR’s outstanding debt under the PVR Revolver. There was no debt outstanding under the Revolver as of September 30, 2009.

In June 2009, we issued and sold $300.0 million of Senior Notes. The Senior Notes mature on June 15, 2016 and bear interest at an annual rate of 10.375%. The Senior Notes were sold at 97% of par, equating to an effective yield to maturity of approximately 11%. The net proceeds from the sale of the Senior Notes of $281.6 million were used to repay borrowings under the Revolver. The obligations under the Senior Notes are fully and unconditionally guaranteed by our oil and gas subsidiaries, which are also guarantors under the Revolver. See Note 8, “Guarantor Subsidiaries.”

In December 2007, we issued and sold $230.0 million of Convertible Notes. The Convertible Notes mature on November 15, 2012 and bear interest at an annual rate of 4.50%. See Note 9, “Convertible Notes.”

In June 2009, the borrowing base under the Revolver was revised from $450.0 million to $367.0 million due to the issuance of the Senior Notes. The Revolver, which matures in December 2010, is secured by a portion of our proved reserves. As of December 31, 2008, the weighted average interest rate on borrowings outstanding under the Revolver was approximately 2.6%. As of September 30, 2009, we had no debt outstanding under the Revolver. Interest is payable at a base rate plus an applicable margin of ranging from 1.125% to 2.125% if we select the base rate borrowing option under the Revolver, or at a rate derived from the London Interbank Offered Rate (“LIBOR”) plus an applicable margin ranging from 2.00% to 3.00% if we select the LIBOR-based borrowing option.

In March 2009, PVR increased the size of the PVR Revolver from $700.0 million to $800.0 million, which resulted in $9.3 million of debt issuance costs that will be amortized over the remaining life of the PVR Revolver. The PVR Revolver is secured with substantially all of PVR’s assets. The December 2011 maturity date for the PVR Revolver did not change. As of September 30, 2009, all of PVR’s long-term debt was indebtedness outstanding under the PVR Revolver. PVR’s debt is non-recourse to us and PVG. Interest is payable at a base rate plus an applicable margin of up to 1.25% if PVR selects the base rate borrowing option under the PVR Revolver, or at a rate derived from the LIBOR plus an applicable margin ranging from 1.75% to 2.75% if PVR selects the LIBOR-based borrowing option. As of September 30, 2009 and December 31, 2008, the weighted average interest rate on borrowings outstanding under the PVR Revolver was approximately 2.5% and 3.2%.

The following table summarizes our and PVR’s long-term debt as of September 30, 2009 and December 31, 2008:

	September 30,		December 31,
	2009		2008
	(in thousands)
Short-term borrowings	$	-	$	7,542
Revolving credit facility		-		332,000
Senior notes, net of discount (1)		291,432		-
Convertible notes, net of discount		204,935		199,896
Total recourse debt of the Company	$	496,367	$	539,438
Long-term debt of PVR		628,100		568,100

Total consolidated debt		1,124,467		1,107,538
Less: Short-term borrowings		-		(7,542	)
Total consolidated long-term debt	$	1,124,467	$	1,099,996

(1)	Includes original issue discount of $9.0 million, which is amortizable through June 15, 2016.

8. Guarantors Subsidiaries

The Senior Notes are fully and unconditionally and joint and severally guaranteed by our oil and gas subsidiaries (collectively, the “Guarantor Subsidiaries”). The primary non-guarantor subsidiaries are PVG and PVR (collectively, the “Non-guarantor Subsidiaries”). As such, the Company is subject to the requirements Rule 3-10(f) of Regulation S-X of the Securities and Exchange Commission regarding financial statements of guarantors and issuers of registered guaranteed securities.

The condensed consolidating financial information below present the financial position, results of operations and cash flows of the Company, the Guarantor Subsidiaries and Non-guarantor Subsidiaries:

Balance Sheets	September 30, 2009
	Penn Virginia		Guarantor		Non-guarantor
	Corporation		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(in thousands)
Assets
Cash and cash equivalents	$	83,336	$	-	$	21,698	$	-		$	105,034
Accounts receivable		-		40,449		60,005		-			100,454
Inventory		-		10,314		1,820		-			12,134
Assets held for sale		-		47,107		-		-			47,107
Other current assets		16,794		341		12,525		(906	)		28,754
Total current assets		100,130		98,211		96,048		(906	)		293,483
Property and equipment, net		7,074		1,483,397		910,103		(28,251	)		2,372,323
Investments in affiliates (equity method)		1,492,547		183,762		-		(1,676,309	)		-
Other assets		19,476		48		237,809		(21,870	)		235,463
Total assets	$	1,619,227	$	1,765,418	$	1,243,960	$	(1,727,336	)	$	2,901,269

Liabilities and shareholders’ equity
Accounts payable and accrued liabilities	$	16,831	$	45,615	$	57,734	$	-		$	120,180
Other current liabilities		16,960		-		10,900		(2,684	)		25,176
Total current liabilities		33,791		45,615		68,634		(2,684	)		145,356
Deferred income taxes		19,137		220,552		-		(21,869	)		217,820
Long-term debt of PVR		-		-		628,100		-			628,100
Long-term debt of the Company		496,367		-		-		-			496,367
Other long-term liabilities		14,077		6,704		30,233		-			51,014
Shareholders’ equity		1,055,855		1,492,547		183,762		(1,702,783	)		1,029,381
Noncontrolling interests in subsidiaries		-		-		333,231		-			333,231
Total liabilities and shareholders’ equity	$	1,619,227	$	1,765,418	$	1,243,960	$	(1,727,336	)	$	2,901,269

Balance Sheets	December 31, 2008
	Penn Virginia		Guarantor		Non-guarantor
	Corporation		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(in thousands)
Assets
Cash and cash equivalents	$	-	$	-	$	18,338	$	-		$	18,338
Accounts receivable		-		75,962		73,279		-			149,241
Inventory		-		16,595		1,873		-			18,468
Other current assets		37,455		7,241		32,823		(48	)		77,471
Total current assets		37,455		99,798		126,313		(48	)		263,518
Property and equipment, net		8,255		1,637,832		895,247		(29,157	)		2,512,177
Investments in affiliates (equity method)		1,574,758		268,314		-		(1,843,072	)		-
Other assets		32,857		49		237,065		(49,101	)		220,870
Total assets	$	1,653,325	$	2,005,993	$	1,258,625	$	(1,921,378	)	$	2,996,565

Liabilities and shareholders’ equity
Current maturities of long-term debt	$	7,542	$	-	$	-	$	-		$	7,542
Accounts payable and accrued liabilities		8,294		129,190		69,418		-			206,902
Other current liabilities		15,032		-		18,166		(48	)		33,150
Total current liabilities		30,868		129,190		87,584		(48	)		247,594
Deferred income taxes		11,868		295,270		-		(49,101	)		258,037
Long-term debt of PVR		-		-		568,100		-			568,100
Long-term debt of the Company		531,896		-		-		-			531,896
Other long-term liabilities		10,433		6,775		37,400		-			54,608
Shareholders’ equity		1,068,260		1,574,758		268,314		(1,872,229	)		1,039,103
Noncontrolling interests in subsidiaries		-		-		297,227		-			297,227
Total liabilities and shareholders’ equity	$	1,653,325	$	2,005,993	$	1,258,625	$	(1,921,378	)	$	2,996,565

Income Statements	Three Months Ended September 30, 2009
	Penn Virginia			Guarantor			Non-guarantor
	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues	$	-		$	55,748		$	155,596		$	(16,181	)	$	195,163
Cost of midstream gas purchased		-			-			92,355			(15,107	)		77,248
Operating		-			13,277			8,964			(1,074	)		21,167
Exploration		-			16,117			-			-			16,117
Taxes other than income		103			4,186			1,005			-			5,294
General and administrative		6,359			5,133			8,454			-			19,946
Depreciation, depletion and amortization		987			39,326			17,857			(301	)		57,869
Impairments on assets held for sale		-			87,900			-			-			87,900
Impairments		-			4,453			-			-			4,453
Loss on sale of assets		-			-			-			-			-
Operating expenses		7,449			170,392			128,635			(16,482	)		289,994
Operating income		(7,449	)		(114,644	)		26,961			301			(94,831	)
Equity in earnings of subsidiaries		(65,354	)		4,462			-			60,892			-
Interest expense and other		(16,841	)		566			(6,161	)		-			(22,436	)
Derivatives		281			-			(2,810	)		-			(2,529	)
Income (loss) before income taxes and noncontrolling interests		(89,363	)		(109,616	)		17,990			61,193			(119,796	)
Income tax benefit (expense)		9,162			44,262			(3,019	)		-			50,405
Net income (loss)		(80,201	)		(65,354	)		14,971			61,193			(69,391	)
Less net income attributable to noncontrolling interests		-			-			(10,509	)		-			(10,509	)
Net income (loss) attributable to Penn Virginia Corporation	$	(80,201	)	$	(65,354	)	$	4,462		$	61,193		$	(79,900	)

Income Statements	Three Months Ended September 30, 2008
	Penn Virginia			Guarantor			Non-guarantor
	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues	$	-		$	156,725		$	285,453		$	(56,566	)	$	385,612
Cost of midstream gas purchased		-			-			211,262			(55,698	)		155,564
Operating		-			15,067			9,238			(868	)		23,437
Exploration		-			8,346			-			-			8,346
Taxes other than income		145			6,537			989			-			7,671
General and administrative		5,542			5,122			7,625			-			18,289
Depreciation, depletion and amortization		867			32,665			16,907			(461	)		49,978
Impairments		-			-			-			-			-
Operating expenses		6,554			67,737			246,021			(57,027	)		263,285
Operating income		(6,554	)		88,988			39,432			461			122,327
Equity in earnings of subsidiaries		63,757			9,504			-			(73,261	)		-
Interest expense and other		(6,604	)		493			(11,198	)		-			(17,309	)
Derivatives		109,390			-			15,742			-			125,132
Income (loss) before income taxes and noncontrolling interests		159,989			98,985			43,976			(72,800	)		230,150
Income tax benefit (expense)		(37,497	)		(35,229	)		(6,195	)		-			(78,921	)
Net income (loss)		122,492			63,756			37,781			(72,800	)		151,229
Less net income attributable to noncontrolling interests		-			-			(28,276	)		-			(28,276	)
Net income (loss) attributable to Penn Virginia Corporation	$	122,492		$	63,756		$	9,505		$	(72,800	)	$	122,953

Income Statements	Nine Months Ended September 30, 2009
	Penn Virginia			Guarantor			Non-guarantor
	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues	$	-		$	176,092		$	461,907		$	(59,759	)	$	578,240
Cost of midstream gas purchased		-			-			285,129			(56,550	)		228,579
Operating		-			42,788			26,938			(3,209	)		66,517
Exploration		-			54,901			-			-			54,901
Taxes other than income		692			12,756			3,208			-			16,656
General and administrative		17,384			15,970			25,433			-			58,787
Depreciation, depletion and amortization		2,836			119,242			51,988			(906	)		173,160
Impairments on assets held for sale		-			87,900			-			-			87,900
Impairments		-			8,928			-			-			8,928
Loss on sale of assets		-			1,599			-			-			1,599
Operating expenses		20,912			344,084			392,696			(60,665	)		697,027
Operating income		(20,912	)		(167,992	)		69,211			906			(118,787	)
Equity in earnings of subsidiaries		(90,132	)		11,790			-			78,342			-
Interest expense and other		(32,045	)		1,453			(17,466	)		-			(48,058	)
Derivatives		20,483			-			(12,005	)		-			8,478
Income (loss) before income taxes and noncontrolling interests		(122,606	)		(154,749	)		39,740			79,248			(158,367	)
Income tax benefit (expense)		12,408			64,617			(7,438	)		-			69,587
Net income (loss)		(110,198	)		(90,132	)		32,302			79,248			(88,780	)
Less net income attributable to noncontrolling interests		-			-			(20,512	)		-			(20,512	)
Net income (loss) attributable to Penn Virginia Corporation	$	(110,198	)	$	(90,132	)	$	11,790		$	79,248		$	(109,292	)

Income Statements	Nine Months Ended September 30, 2008
	Penn Virginia			Guarantor			Non-guarantor
	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues	$	3		$	383,391		$	719,228		$	(107,461	)	$	995,161
Cost of midstream gas purchased		-			-			513,778			(105,531	)		408,247
Operating		-			43,370			25,213			(1,930	)		66,653
Exploration		-			19,765			-			-			19,765
Taxes other than income		821			19,480			3,024			-			23,325
General and administrative		18,063			14,869			22,074			-			55,006
Depreciation, depletion and amortization		2,516			90,849			41,337			(1,221	)		133,481
Impairments		-			-			-			-			-
Operating expenses		21,400			188,333			605,426			(108,682	)		706,477
Operating income		(21,397	)		195,058			113,802			1,221			288,684
Equity in earnings of subsidiaries		142,925			23,668			-			(166,593	)		-
Interest expense and other		(17,609	)		1,555			(20,041	)		-			(36,095	)
Derivatives		2,037			-			(6,424	)		-			(4,387	)
Income (loss) before income taxes and noncontrolling interests		105,956			220,281			87,337			(165,372	)		248,202
Income tax benefit (expense)		14,421			(77,355	)		(11,418	)		-			(74,352	)
Net income (loss)		120,377			142,926			75,919			(165,372	)		173,850
Less net income attributable to noncontrolling interests		-			-			(52,252	)		-			(52,252	)
Net income (loss) attributable to Penn Virginia Corporation	$	120,377		$	142,926		$	23,667		$	(165,372	)	$	121,598

Statements of Cash Flows	Three Months Ended September 30, 2009
	Penn Virginia			Guarantor			Non-guarantor
	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
Net cash provided by (used in) operating activitities	$	(32,443	)	$	73,615		$	42,874		$	-		$	84,046
Cash flows provided by (used in) investing activities:
Investment in (distributions from) affiliates		188,080			129,948			-			(318,028	)		-
Additions to property and equipment		(201	)		(18,059	)		(39,171	)		-			(57,431	)
Proceeds from the sale of assets and other		-			2,576			300			-			2,876
Cash flows provided by (used in) investing activities		187,879			114,465			(38,871	)		(318,028	)		(54,555	)
Cash flows provided by (used in) financing activities:
Distributions paid to noncontrolling interest holders		-			-			(18,455	)		-			(18,455	)
Net proceeds from (repayments of) borrowings		(70,000	)		-			31,000			-			(39,000	)
Net proceeds from issuance of senior notes		-			-			-			-			-
Net proceeds from the sale of PVG units		-			-			118,080			-			118,080
Net proceeds from issuance of equity		-			-			-			-			-
Capital contributions from (distributions to) affiliates		-			(188,080	)		(129,948	)		318,028			-
Other		(3,419	)		-			-			-			(3,419	)
Cash flows provided by (used in) financing activities		(73,419	)		(188,080	)		677			318,028			57,206
Net decrease in cash and cash equivalents		82,017			-			4,680			-			86,697
Cash and cash equivalents - beginning of period		1,319			-			17,018			-			18,337
Cash and cash equivalents - end of period	$	83,336		$	-		$	21,698		$	-		$	105,034

Statements of Cash Flows	Three Months Ended September 30, 2008
	Penn Virginia			Guarantor			Non-guarantor
	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
Net cash provided by operating activitities	$	(15,949	)	$	87,190		$	20,554		$	-		$	91,795
Cash flows provided by (used in) investing activities:
Investment in (distributions from) affiliates		(21,431	)		72,718			-			(51,287	)		-
Additions to property and equipment		(260	)		(213,572	)		(111,103	)		-			(324,935	)
Proceeds from the sale of assets and other		-			32,233			982			-			33,215
Cash flows provided by (used in) investing activities		(21,691	)		(108,621	)		(110,121	)		(51,287	)		(291,720	)
Cash flows provided by (used in) financing activities:
Distributions paid to noncontrolling interest holders		-			-			(17,917	)		-			(17,917	)
Net proceeds from (repayments of) borrowings		21,431			-			176,600			-			198,031
Net proceeds from equity issuance								-			-			-
Capital contributions from (distributions to) affiliates		-			21,431			(72,718	)		51,287			-
Other		(1,208	)		-			(3,454	)		-			(4,662	)
Cash flows provided by (used in) financing activities		20,223			21,431			82,511			51,287			175,452
Net increase in cash and cash equivalents		(17,417	)		-			(7,056	)		-			(24,473	)
Cash and cash equivalents - beginning of period		17,465			-			26,015			-			43,480
Cash and cash equivalents - end of period	$	48		$	-		$	18,959		$	-		$	19,007

Statements of Cash Flows	Nine Months Ended September 30, 2009
	Penn Virginia			Guarantor			Non-guarantor
	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
Net cash provided by operating activitities	$	(16,124	)	$	122,813		$	115,334		$	-		$	222,023
Cash flows provided by (used in) investing activities:
Investment in (distributions from) affiliates		101,778			153,012			-			(254,790	)		-
Additions to property and equipment		(1,655	)		(181,873	)		(73,291	)		-			(256,819	)
Proceeds from the sale of assets and other		-			7,826			872			-			8,698
Cash flows provided by (used in) investing activities		100,123			(21,035	)		(72,419	)		(254,790	)		(248,121	)
Cash flows provided by (used in) financing activities:
Distributions paid to noncontrolling interest holders		-			-			(55,365	)		-			(55,365	)
Net proceeds from (repayments of) borrowings		(339,542	)		-			60,000			-			(279,542	)
Net proceeds from issuance of senior notes		291,009			-			-			-			291,009
Net proceeds from the sale of PVG units		-			-			118,080						118,080
Net proceeds from issuance of equity		64,835			-			-			-			64,835
Capital contributions from (distributions to) affiliates		-			(101,778	)		(153,012	)		254,790			-
Other		(16,965	)		-			(9,258	)		-			(26,223	)
Cash flows provided by (used in) financing activities		(663	)		(101,778	)		(39,555	)		254,790			112,794
Net increase (decrease) in cash and cash equivalents		83,336			-			3,360			-			86,696
Cash and cash equivalents - beginning of period		-			-			18,338			-			18,338
Cash and cash equivalents - end of period	$	83,336		$	-		$	21,698		$	-		$	105,034

Statements of Cash Flows	Nine Months Ended September 30, 2008
	Penn Virginia			Guarantor			Non-guarantor
	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
Net cash provided by operating activitities	$	(8,440	)	$	192,049		$	93,078		$	-		$	276,687
Cash flows provided by (used in) investing activities:
Investment in (distributions from) affiliates		(104,431	)		94,197			-			10,234			-
Additions to property and equipment		(1,059	)		(422,974	)		(246,183	)		-			(670,216	)
Proceeds from the sale of assets and other		-			32,297			1,657			-			33,954
Cash flows provided by (used in) investing activities		(105,490	)		(296,480	)		(244,526	)		10,234			(636,262	)
Cash flows provided by (used in) financing activities:
Distributions paid to noncontrolling interest holders		-			-			(45,829	)		-			(45,829	)
Net proceeds from (repayments of) borrowings		104,431			-			146,000			-			250,431
Net proceeds from equity issuance		-			-			138,015			-			138,015
Capital contributions from (distributions to) affiliates		-			104,431			(94,197	)		(10,234	)		-
Other		5,512			-			(4,074	)		-			1,438
Cash flows provided by (used in) financing activities		109,943			104,431			139,915			(10,234	)		344,055
Net increase (decrease) in cash and cash equivalents		(3,987	)		-			(11,533	)		-			(15,520	)
Cash and cash equivalents - beginning of period		4,035			-			30,492			-			34,527
Cash and cash equivalents - end of period	$	48		$	-		$	18,959		$	-		$	19,007

9. Convertible Notes

Effective January 1, 2009, we adopted the new accounting standard regarding convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, and accounted for the adoption of this standard as a change in accounting principle. This standard therefore been applied retroactively to all periods presented.

Because the Convertible Notes can be settled wholly or partly in cash upon conversion into our common stock, this standard requires us to account separately for the liability and equity components in a manner that reflects our nonconvertible debt borrowing rate when measuring interest cost of the Convertible Notes. The value assigned to the liability component was the estimated value of a similar debt issuance without the conversion feature as of the issuance date in December 2007. Transaction costs associated with issuing the instrument were allocated to the liability and equity components in proportion to the allocation of the original proceeds and were accounted for as debt issuance costs and equity issuance costs. In addition, recognizing the Convertible Notes as two separate components resulted in a tax basis difference associated with the liability component that represents a temporary difference. Because the liability component was valued exclusive of the conversion feature, the Convertible Notes were recorded at a discount reflecting the below-market coupon interest rate. This discount is accreted through additional interest expense to par value over the remaining expected life of the debt of approximately four years.

The following tables reflect the effects of adopting the standard on our consolidated statements of income for the three and nine months ended September 30, 2008:

	Three Months Ended September 30, 2008
	As originally						Effects of
Consolidated Statement of Income	reported			As adjusted			change
	(in thousands)
Interest expense - (1)	$	(11,938	)	$	(13,221	)	$	(1,283	)
Income tax benefit (expense) - (2)		79,419			78,921			(498	)
Net income (loss) - (3)		152,014			151,229			(785	)
Net loss attributable to Penn Virginia Corporation		123,738			122,953			(785	)

Income per share attributable to Penn Virginia Corporation:
Basic	$	2.95		$	2.94		$	(0.01	)
Diluted	$	2.90		$	2.88		$	(0.02	)

	Nine Months Ended September 30, 2008
	As originally						Effects of
Consolidated Statement of Income	reported			As adjusted			change
	(in thousands)
Interest expense - (1)	$	(31,600	)	$	(35,313	)	$	(3,713	)
Income tax benefit (expense) - (2)		75,792			74,352			(1,440	)
Net income (loss) - (3)		176,123			173,850			(2,273	)
Net income (loss) attributable to Penn Virginia Corporation		123,871			121,598			(2,273	)

Income per share attributable to Penn Virginia Corporation:
Basic	$	2.96		$	2.91		$	(0.05	)
Diluted	$	2.94		$	2.88		$	(0.06	)

(1)

Represents additional interest expense that would have been recorded related to the debt discount had the standard been in place when the Convertible Notes were issued. This increase is partially offset by variances in capitalized interest and the amortization of debt issuance costs, which resulted from the separation of the debt and equity components of the Convertible Notes.

(2)	The adjustment to income tax benefit (expense) is based on our effective tax rates.

(3)	Net income (loss) includes noncontrolling interests.

The following tables reflect the effects of adopting the standard on our consolidated balance sheet at December 31, 2008:

	December 31, 2008
	As originally				Effects of
Consolidated Balance Sheet	reported		As adjusted		change
	(in thousands)
Oil and gas properties (1)	$	2,106,126	$	2,107,128	$	1,002
Other assets (2)		46,674		45,685		(989	)
Deferred income taxes (3)		245,789		258,037		12,248
Convertible notes (4)		230,000		199,896		(30,104	)
Paid-in capital (5)		578,639		599,855		21,216
Retained earnings (6)		446,993		443,646		(3,347	)

(1)	The impact on oil and gas properties is due to capitalized interest.

(2)	The adjustment to other assets reflects a decrease in debt issuance costs.

(3)	The impact on deferred income taxes is due to the change in the tax basis of the liability component.

(4)	The impact on the Convertible Notes balance is due to the unamortized discount balance.

(5)	The impact on the paid-in capital balance is due to the equity component and related issue costs as well as the change in deferred income taxes.

(6)	The impact on retained earnings is due to the additional interest expense, net of tax, that would have been incurred had the standard been in place when the Convertible Notes were issued.

The following tables reflect the effects of adopting the standard on our consolidated statements of cash flows for the three and nine months ended September 30, 2008:

	Three Months Ended September 30, 2008
	As originally						Effects of
Consolidated Statement of Cash Flows	reported			As adjusted			change
	(in thousands)
Cash flows from operating activities
Net income (loss)	$	152,014		$	151,229		$	(785	)
Deferred income taxes		62,050			61,552			(498	)
Other		(28,657	)		(27,374	)		1,283
Total impact on the statement of cash flows	$	185,407		$	185,407		$	-

	Nine Months Ended September 30, 2008
	As originally						Effects of
Consolidated Statement of Cash Flows	reported			As adjusted			change
	(in thousands)
Cash flows from operating activities
Net income	$	176,123		$	173,850		$	(2,273	)
Deferred income taxes		61,545			60,105			(1,440	)
Other		(29,831	)		(26,118	)		3,713
Total impact on the statement of cash flows	$	207,837		$	207,837		$	-

The net carrying amount of the liability component is reported as long-term debt on our consolidated balance sheets. The carrying amount of the equity component is reported in paid-in capital on our consolidated balance sheets. The discount amortization is recorded in interest expense on our consolidated statements of income. The following table reflects the carrying amounts of the liability and equity components of the Convertible Notes:

	September 30,			December 31,
	2009			2008
	(in thousands)
Principal	$	230,000		$	230,000
Unamortized discount		(25,065	)		(30,104	)
Net carrying amount of liability component	$	204,935		$	199,896

Carrying amount of equity component	$	36,850		$	36,850

The unamortized discount will be amortized through the end of 2012. The effective interest rate on the liability component of the Convertible Debt for the three and nine months ended September 30, 2009 was 8.5%. For the three and nine months ended September 30, 2009, we recognized $2.6 million and $7.8 million of interest expense related to the contractual coupon rate on the Convertible Notes and $1.7 million and $5.0 million of interest expense related to the amortization of the discount.

The Convertible Notes are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.316 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment, and, if not converted or repurchased earlier, will mature on November 15, 2012.

10. Impairments

Other Impairments

We review long-lived assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. We recognize an impairment loss when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows related to that asset.

For the three months ended September 30, 2009, we recorded impairment charges related to our oil and gas segment properties and tubular inventories of $4.5 million. Of this amount, $3.7 million resulted from market declines in the spot and future oil and gas prices and $0.8 million related to our tubular inventory valuation. For the nine months ended September 30, 2009, we recorded impairment charges related to our oil and gas segment properties and tubular inventories of $8.9 million. Of this amount, $4.1 million related to our tubular inventory valuation and $4.8 million resulted from market declines in the spot and future oil and gas prices.

Impairments on Assets Held for Sale

As of September 30, 2009, certain oil and gas properties located in Texas, Louisiana and North Dakota were classified as current assets held for sale on our consolidated balance sheet. We completed the sale of the North Dakota properties in October 2009 and expect to complete the sale of the Louisiana and Texas properties in the fourth quarter of 2009. As a result of classifying these assets as held for sale, we incurred an impairment charge of $87.9 million to record the assets at fair value less costs to sell. Anticipated sales prices are difficult to predict and subject to revision in future periods. Due to the uncertainty of the sale process, we cannot predict when or if future impairment charges or gains or losses on the sales of these assets will be recorded. These anticipated asset dispositions did not qualify for accounting as discontinued operations because we expect to redeploy the proceeds of the sale in the same geographic area.

11. Earnings per Share

On January 1, 2009, we adopted the new accounting standard which determines whether instruments granted in share-based payment transactions are participating securities. Under this standard, unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are participating securities and, therefore, are included in computing earnings per share pursuant to the two-class method. Under the two-class method, earnings per share are determined for each class of common stock and participating securities according to dividends or dividend equivalents and their respective participation rights in undistributed earnings. We have determined that our unvested phantom stock awards contain non-forfeitable rights to dividends and, therefore, are participating securities for purposes of this standard.

We also adopted the new accounting standard applicable to the Convertible Notes. See Note 9, “Convertible Notes.” This standard also had an effect on our earnings per share. We applied both new standards retroactively to all periods presented as required.

The following tables set forth the effect of the retroactive application of the new standards as of January 1, 2009 for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,
				2008
				As originally						Effects of
	2009			reported			As adjusted (1)			changes
	(in thousands, except per share data)
Net income (loss) attributable to common shareholders	$	(79,900	)	$	123,738		$	122,953		$	(785	)
Portion of subsidiary net income allocated to undistributed share-based compensation awards (net of tax)		(34	)		(219	)		(219	)		-
	$	(79,934	)		123,519		$	122,734		$	(785	)

Weighted average shares, basic		45,427			41,881			41,881			-
Effect of dilutive securities (2)		-			663			663			-
Weighted average shares, diluted		45,427			42,544			42,544			-

Net income (loss) per common share, basic	$	(1.76	)	$	2.95		$	2.94		$	0.01
Net income (loss) per common share, diluted	$	(1.76	)	$	2.90		$	2.88		$	0.02

(1)	Represents the impact of the adoption of both new standards described above as of January 1, 2009.

(2)	For the three months ended September 30, 2009, approximately 0.1 million potentially dilutive securities, including the Convertible Notes, stock options, restricted stock and phantom stock had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.

	Nine Months Ended September 30,
				2008
				As originally						Effects of
	2009			reported			As adjusted (1)			changes
	(in thousands, except per share data)
Net income (loss) attributable to common shareholders	$	(109,292	)	$	123,871		$	121,598		$	(2,273	)
Portion of subsidiary net income allocated to undistributed share-based compensation awards (net of tax)		(68	)		(418	)		(418	)		-
	$	(109,360	)	$	123,453		$	121,180		$	(2,273	)

Weighted average shares, basic		43,324			41,715			41,715			-
Effect of dilutive securities (2)		-			313			313			-
Weighted average shares, diluted		43,324			42,028			42,028			-

Net income (loss) per common share, basic	$	(2.52	)	$	2.96		$	2.91		$	(0.05	)
Net income (loss) per common share, diluted	$	(2.52	)	$	2.94		$	2.88		$	(0.06	)

(1)	Represents the impact of the adoption of both new standards described above as of January 1, 2009.

(2)	For the nine months ended September 30, 2009, approximately 0.1 million potentially dilutive securities, including the Convertible Notes, stock options, restricted stock and phantom stock had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.

12. Share-Based Compensation

On a consolidated basis, we recognized a total of $3.7 million and $2.5 million of compensation expense for the three months ended September 30, 2009 and 2008 and $11.6 million and $7.0 million of compensation expense for the nine months ended September 30, 2009 and 2008 related to our, PVG’s and PVR’s equity-based compensation plans. We record compensation expense in the general and administrative expenses line item on our consolidated statements of income.

Stock Compensation Plans

Our stock compensation plans permit the grant of common stock, deferred common stock units, restricted stock and phantom stock to our employees and directors. We recognized compensation expense of $2.5 million and $1.6 million for the three months ended September 30, 2009 and 2008 and $7.4 million and $4.3 million for the nine months ended September 30, 2009 and 2008 related to the granting of common stock and deferred common stock units under our stock compensation plans and the vesting of restricted stock and phantom stock granted under our stock compensation plans. Common stock and deferred common stock units granted under our stock compensation plans are immediately vested, and we recognize compensation expense related to those grants on the grant date. Restricted stock and phantom stock granted under our stock compensation plans vest over a three-year period, with one-third vesting in each year, and we recognize compensation expense related to those grants on a straight-line basis over the vesting period.

PVR Long-Term Incentive Plan

The Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan (the “PVR LTIP”) permits the grant of common units, deferred common units, restricted units and phantom units to employees and directors of its general partner and its affiliates. PVR recognized compensation expense of $1.1 million and $0.8 million for the three months ended September 30, 2009 and 2008 and $3.9 million and $2.4 million for the nine months ended September 30, 2009 and 2008 related to the granting of common and deferred common units under the PVR LTIP and the vesting of restricted units and phantom units granted under the PVR LTIP. Common units and deferred common units granted under the LTIP are immediately vested, and PVR recognizes compensation expense related to those grants on the grant date. Restricted units and phantom units granted under the PVR LTIP vest over a three-year period, with one-third vesting in each year, and PVR recognizes compensation expense related to those grants on a straight-line basis over the vesting period.

PVG Long-Term Incentive Plan

The PVG GP, LLC Amended and Restated Long-Term Incentive Plan (the “PVG LTIP”) likewise permits the grant of common units, deferred common units, restricted units and phantom units to its employees and directors of its general partner and affiliates. PVG recognized compensation expense of $0.1 million for both the three months ended September 30, 2009 and 2008 and $0.3 million for both the nine months ended September 30, 2009 and 2008 related to the granting of deferred common units under the PVG LTIP.

13. Commitments and Contingencies

Drilling Rig Commitments and Standby Charges

In the first quarter of 2009, our oil and gas segment reduced its drilling program due to unfavorable economic conditions. In conjunction with the drilling program reduction, we amended certain drilling rig contracts to delay commencement of drilling until January 2010. For the nine months ended September 30, 2009, we recognized charges of $20.3 million for cancellation fees, minimum daily standby fees and demobilization fees. These fees and costs were recorded as exploration expense on our consolidated statements of income. We will continue to evaluate economic conditions through the remainder of 2009 to determine whether or not to commence drilling prior to January 2010, which could result in a refund of some expense. We will also evaluate economic conditions through the remainder of 2009 to determine whether or not to defer additional drilling. Deferring drilling until January 2010 could result in additional exploration expenses of up to $1.7 million for the remainder of 2009.

Legal

We and PVR are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position or results of operations.

Environmental Compliance

As of September 30, 2009 and December 31, 2008, PVR’s environmental liabilities were $1.1 million and $1.2 million, which represents PVR’s best estimate of the liabilities as of those dates related to its coal and natural resource management and natural gas midstream businesses. PVR has reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

Mine Health and Safety Laws

There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since PVR does not operate any mines and does not employ any coal miners, PVR is not subject to such laws and regulations. Accordingly, we have not accrued any related liabilities.

Significant Customer

For the nine months ended September 30, 2009, one PVR natural gas midstream segment customer accounted for $83.0 million, or 14%, of our total consolidated revenues. At September 30, 2009, 8% of our consolidated accounts receivable related to this customer.

14. Segment Information

Our reportable segments are as follows:

•

Oil and Gas—crude oil and natural gas exploration, development and production.

•

PVR Coal and Natural Resource Management—leasing of coal properties in exchange for royalty payments and other land management activities.

•

PVR Natural Gas Midstream—natural gas processing, gathering and other related services.

The other line item primarily represents corporate functions and the elimination of intercompany sales.

The following tables present a summary of certain financial information relating to our segments for the three and nine months ended September 30, 2009 and 2008 and as of September 30, 2009 and December 31, 2008:

	Revenues						Intersegment revenues (1)
	Three Months Ended September 30,						Three Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Oil and gas	$	55,748		$	156,725		$	(256	)	$	(639	)
Coal and natural resource management		35,179			41,660			264			198
Natural gas midstream		120,446			243,616			15,534			57,007
Other		(16,210	)		(56,389	)		(15,542	)		(56,566	)
Consolidated totals	$	195,163		$	385,612		$	-		$	-

	Operating income (loss)						DD&A expenses
	Three Months Ended September 30,						Three Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Oil and gas	$	(114,644	)	$	88,988		$	39,326		$	32,665
Coal and natural resource management		21,225			26,295			7,999			8,794
Natural gas midstream		6,591			13,728			9,852			8,109
Other		(8,003	)		(6,684	)		692			410
Consolidated totals		(94,831	)		122,327		$	57,869		$	49,978
Interest expense		(22,784	)		(13,221	)
Other		348			(4,088	)
Derivatives		(2,529	)		125,132
Income tax benefit (expense)		50,405			(78,921	)
Net income attributable to noncontrolling interests		(10,509	)		(28,276	)
Net income (loss) attributable to Penn Virginia Corporation	$	(79,900	)	$	122,953

	Additions to property and equipment
	Three Months Ended September 30,
	2009			2008
	(in thousands)
Oil and gas	$	18,059		$	213,572
Coal and natural resource management		140			497
Natural gas midstream		39,031			110,606
Other		201			260
Consolidated totals	$	57,431		$	324,935

	Revenues						Intersegment revenues (1)
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Oil and gas	$	176,092		$	383,391		$	(903	)	$	(1,709	)
Coal and natural resource management		108,575			111,010			594			594
Natural gas midstream		353,228			607,585			59,759			108,576
Other		(59,655	)		(106,825	)		(59,450	)		(107,461	)
Consolidated totals	$	578,240		$	995,161		$	-		$	-

	Operating income (loss)						DD&A expenses
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Oil and gas	$	(167,992	)	$	195,058		$	119,242		$	90,849
Coal and natural resource management		66,532			67,860			23,557			22,733
Natural gas midstream		4,604			47,726			28,414			18,589
Other		(21,931	)		(21,960	)		1,947			1,310
Consolidated totals		(118,787	)		288,684		$	173,160		$	133,481
Interest expense		(50,332	)		(35,313	)
Other		2,274			(782	)
Derivatives		8,478			(4,387	)
Income tax benefit (expense)		69,587			(74,352	)
Net income attributable to noncontrolling interests		(20,512	)		(52,252	)
Net income (loss) attributable to Penn Virginia Corporation	$	(109,292	)	$	121,598

	Additions to property and equipment						Total Assets
	Nine Months Ended September 30,						September 30,			December 31,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Oil and gas	$	181,873		$	422,974		$	1,581,656		$	1,728,375
Coal and natural resource management		2,046			25,186			568,829			600,418
Natural gas midstream		71,245			220,997			639,966			618,402
Other		1,655			1,059			110,818			49,370
Consolidated totals	$	256,819		$	670,216		$	2,901,269		$	2,996,565

(1)

Represents (i) gas gathering and processing transactions between the PVR natural gas midstream segment and our oil and gas segment, (ii) agent fees paid by our oil and gas segment to the PVR natural gas midstream segment for marketing certain natural gas production and (iii) rail car rental fees paid by a corporate affiliate to the PVR coal and natural resource management segment.

15. New Accounting Standards

In September 2009, the Financial Accounting Standards Board issued guidance on how to measure the fair value of a liability when a quoted price in an active market for the identical liability is not available. It also includes other clarifications and examples of how to measure the fair value of certain liabilities, including those that have limited or no observable data. We do not expect the guidance to have a material impact on our consolidated financial statements and we will adopt it effective fourth quarter 2009.

16. Suspended Well Costs

An exploratory well that was pending determination of proved reserves as of December 31, 2008 was subsequently determined to be successful during the third quarter 2009. Accordingly, we reclassified $2.5 million of suspended exploratory drilling costs related to this well to proved property and equipment during the nine months ended September 30, 2009.

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

The following discussion and analysis of the financial condition and results of operations of Penn Virginia Corporation and its subsidiaries (“Penn Virginia,” the “Company,” “we,” “us” or “our”) should be read in conjunction with our consolidated financial statements and the accompanying notes in Item 1, “Financial Statements.”

Overview of Business

We are an independent oil and gas company primarily engaged in the development, exploration and production of natural gas and oil in various domestic onshore regions including East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast. We also indirectly own partner interests in Penn Virginia Resource Partners, L.P., or PVR, which is engaged in the coal and natural resource management and natural gas midstream businesses. Our ownership interests in PVR are held principally through our general partner interest and our 51.4% limited partner interest in Penn Virginia GP Holdings, L.P., or PVG. As of September 30, 2009, PVG owned an approximately 37% limited partner interest in PVR and 100% of the general partner of PVR, which holds a 2% general partner interest in PVR and all of the incentive distribution rights.

Although results are consolidated for financial reporting, Penn Virginia, PVG and PVR operate with independent capital structures. As such, cash flow available to us from PVG and PVR is only in the form of cash distributions declared and paid to us on account of our partner interests in those entities. We received cash distributions from PVG and PVR of $34.4 million in the nine months ended September 30, 2009 and $21.5 million for same period of 2008. These distributions were primarily used for oil and gas segment capital expenditures.

The following diagram depicts our ownership of PVG and PVR as of September 30, 2009:

Selected Financial Data—Consolidated

The following table presents summary operating results for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands)
Revenues	$	195,163		$	385,612		$	578,240		$	995,161
Expenses		289,994			(263,285	)		697,027			(706,477	)
Operating income (loss)		(94,831	)		122,327			(118,787	)		288,684
Other income (expense)
Interest expense		(22,784	)		(13,221	)		(50,332	)		(35,313	)
Derivatives		(2,529	)		125,132			8,478			(4,387	)
Other		348			(4,088	)		2,274			(782	)
Income tax benefit (expense)		50,405			(78,921	)		69,587			(74,352	)
Net income (loss)		(69,391	)		151,229			(88,780	)		173,850
Less net income attributable to noncontrolling interests		(10,509	)		(28,276	)		(20,512	)		(52,252	)
Income (loss) attributable to PennVirginia Corporation	$	(79,900	)	$	122,953		$	(109,292	)	$	121,598

We are engaged in three primary business segments as follows:

•

Oil and Gas—crude oil and natural gas exploration, development and production.

•

PVR Coal and Natural Resource Management— leasing of coal properties in exchange for royalty payments and other land management activities.

•

PVR Natural Gas Midstream—natural gas processing, gathering and other related services.

We operate our oil and gas segment and PVR operates the coal and natural resource management and natural gas midstream segments. Other primarily represents corporate functions such as interest expense, income tax expense, oil and gas segment derivatives and elimination of intercompany sales.

The following table presents a summary of certain financial information relating to our segments:

				PVR Coal
				and Natural		PVR Natural
				Resource		Gas		Eliminations
	Oil and Gas			Management		Midstream		and Other			Consolidated
	(in thousands)
For the Nine Months Ended September 30, 2009:
Revenues	$	176,092		$	108,575	$	353,228	$	(59,655	)	$	578,240
Cost of midstream gas purchased		-			-		285,129		(56,550	)		228,579
		176,092			108,575		68,099		(3,105	)		349,661
Operating costs and expenses		128,014			18,486		35,081		16,879			198,460
Impairments		96,828			-		-		-			96,828
Depreciation, depletion and amortization		119,242			23,557		28,414		1,947			173,160
Operating income (loss)	$	(167,992	)	$	66,532	$	4,604	$	(21,931	)	$	(118,787	)

For the Nine Months Ended September 30, 2008:
Revenues	$	383,391		$	111,010	$	607,585	$	(106,825	)	$	995,161
Cost of midstream gas purchased		-			-		513,778		(105,531	)		408,247
		383,391			111,010		93,807		(1,294	)		586,914
Operating costs and expenses		97,484			20,417		27,492		19,356			164,749
Depreciation, depletion and amortization		90,849			22,733		18,589		1,310			133,481
Operating income (loss)	$	195,058		$	67,860	$	47,726	$	(21,960	)	$	288,684

Results of Operations

Oil and Gas Segment

We have a geographically diverse asset base with core regions of operation in the East Texas, Mid-Continent, Appalachian and Mississippi regions of the United States. The growth profile of our oil and gas segment was accomplished primarily by drilling oil and natural gas wells in our operating regions and, to a lesser extent, by making acquisitions of both producing properties and undeveloped leases. In response to significantly lower internal cash flows due to reduced energy commodity prices and the continued weakness in global financial markets, which have adversely impacted our ability to fund a growth oriented capital spending program, we have limited our capital spending in 2009 to more closely mirror internally generated cash flow.

Three and Nine Months Ended September 30, 2009 Compared with the

Three and Nine Months Ended September 30, 2008

The following table sets forth a summary of certain financial and other data for our oil and gas segment for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Financial Highlights	2009			2008		2009			2008
Revenues	(in thousands, except as noted)
Natural gas	$	36,654		$	101,911	$	129,305		$	295,636
Crude oil		13,259			13,764		31,412			37,442
NGL		2,847			10,481		10,553			18,887
Other income		2,988			30,569		4,822			31,426
Total revenues		55,748			156,725		176,092			383,391

Expenses
Operating		13,277			15,067		42,788			43,370
Taxes other than income		4,186			6,537		12,756			19,480
General and administrative		5,133			5,122		15,970			14,869
Production costs		22,596			26,726		71,514			77,719
Exploration		16,117			8,346		54,901			19,765
Depreciation, depletion and amortization		39,326			32,665		119,242			90,849
Impairments on assets held for sale		87,900			-		87,900			-
Impairments		4,453			-		8,928			-
Loss on sale of assets		-			-		1,599			-
Total expenses		170,392			67,737		344,084			188,333

Operating income (loss)	$	(114,644	)	$	88,988	$	(167,992	)	$	195,058

Operating Statistics
Natural gas (MMcf)		10,634			10,046		33,858			29,869
Crude oil (MBbl)		202			117		588			331
NGL (MBbl)		94			157		381			300
Total production (MMcfe)		12,410			11,690		39,672			33,655

Production. The following table summarizes total natural gas, crude oil and NGL production by region for the three and nine months ended September 30, 2009 and 2008:

	Natural Gas, Crude Oil and NGL Production
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Region	2009		2008		2009		2008
	(MMcfe)
East Texas		3,034		3,764		10,429		9,986
Appalachia		2,882		2,830		8,715		8,575
Mid-Continent		3,372		1,609		9,684		4,724
Mississippi		1,875		1,837		6,118		5,462
Gulf Coast		1,247		1,650		4,726		4,908
Total		12,410		11,690		39,672		33,655

Total production increased by 0.7 billion cubic feet equivalent (Bcfe), or 6%, from 11.7 Bcfe in the three months ended September 30, 2008 to 12.4 Bcfe in the same period of 2009 primarily due to continued development of the Granite Wash play in the Mid-Continent region, partially offset by production declines in the East Texas and Gulf Coast regions. We had an active drilling program in the East Texas region in the last half of 2008 through the first quarter of 2009, then we deferred drilling in this area until early 2010.

Total production increased by 6.0 Bcfe, or 18%, from 33.7 Bcfe in the nine months ended September 30, 2008 to 39.7 Bcfe in the same period of 2009 primarily due to higher production in the Mid-Continent, East Texas and Mississippi regions. The increase in production was due to continued development of the Granite Wash play in the Mid-Continent region, the horizontal Lower Bossier (Haynesville) Shale play in the East Texas region and the horizontal Selma Chalk play in Mississippi.

Revenues. Our revenues, consisting of natural gas, crude oil, natural gas liquid, or NGL, and other income, decreased by $100.9 million, or 64%, from $156.7 million in the three months ended September 30, 2008 to $55.8 million in the same period of 2009 primarily due to decreases in commodity prices and other income. Our revenues decreased by $207.3 million, or 54%, from $383.4 million in the nine months ended September 30, 2008 to $176.1 million in the same period of 2009 due largely to lower commodity prices, offset by an increase in production. Realized prices are before the impacts of our commodity derivatives, which are further discussed under “Effects of Derivatives” below.

Natural Gas. Natural gas revenues decreased by $65.2 million, or 64%, from $101.9 million in the three months ended September 30, 2008 to $36.7 million in the same period of 2009. Of the $65.2 million decrease, $71.2 million was the result of lower realized prices for natural gas, partially offset by $6.0 million resulting from higher natural gas production from development drilling. Our average realized price received for natural gas decreased by $6.69 per thousand cubic feet (Mcf), or 66%, from $10.14 per Mcf in the three months ended September 30, 2008 to $3.45 per Mcf in the same period of 2009.

Natural gas revenues decreased by $166.3 million, or 56%, from $295.6 million in the nine months ended September 30, 2008 to $129.3 million in the same period of 2009. Of the $166.3 million decrease, $205.8 million was the result of lower realized prices for natural gas, partially offset by $39.5 million resulting from higher natural gas production from development drilling. Our average realized price received for natural gas decreased by $6.08 per Mcf, or 61%, from $9.90 per Mcf in the nine months ended September 30, 2008 to $3.82 per Mcf in the same period of 2009.

Crude Oil. Crude oil revenues decreased by $0.5 million, or 4%, from $13.8 million in the three months ended September 30, 2008 to $13.3 million in the same period of 2009. Of the $0.5 million decrease, $10.0 million was the result of lower realized prices for crude oil, partially offset by an increase of $10.0 million resulting from higher crude oil production related to development drilling. Our average realized price received for crude oil decreased by $52.00 per barrel (Bbl), or 44%, from $117.64 per Bbl in the three months ended September 30, 2008 to $65.64 per Bbl in the same period of 2009.

Crude oil revenues decreased by $6.0 million, or 16%, from $37.4 million in the nine months ended September 30, 2008 to $31.4 million in the same period of 2009. Of the $6.0 million decrease, $35.1 million was the result of lower realized prices for crude oil, partially offset by an increase of $29.1 million resulting from higher crude oil production related to developmental drilling. Our average realized price received for crude oil decreased by $59.70 per Bbl, or 53%, from $113.12 per Bbl in the nine months ended September 30, 2008 to $53.42 per Bbl in the same period of 2009.

NGL. NGL revenues decreased by $7.7 million, or 73%, from $10.5 million in the three months ended September 30, 2008 to $2.8 million in the same period of 2009. Of the $7.7 million decrease, $4.2 million was due to a decline in volume and $3.4 million was the result of lower realized prices for NGLs. Our average realized price received for NGLs decreased by $36.47 per Bbl, or 55%, from $66.76 per Bbl in the three months ended September 30, 2008 to $30.29 per Bbl in the same period of 2009.

NGL revenues decreased by $8.3 million, or 44%, from $18.9 million in the nine months ended September 30, 2008 to $10.6 million in the same period of 2009. Of the $8.3 million decrease, $13.4 million was due to lower realized prices for NGLs, partially offset by an increase of $5.1 million resulting from additional volume, which was attributable to a new processing plant in the East Texas region. Our average realized price received for NGLs decreased by $35.26 per Bbl, or 56%, from $62.96 per Bbl in the nine months ended September 30, 2008 to $27.70 per Bbl in the same period of 2009.

Effects of Derivatives. Our revenues may vary significantly from period to period as a result of variances in commodity prices or production volumes. As part of our risk management strategy, we use derivative financial instruments to hedge natural gas and oil prices. Our commodity derivative contracts do not follow hedge accounting and are not reported as revenues in our consolidated statements of income. For derivatives related to our oil and gas segment, we received $16.4 million and $48.9 million in cash settlements in the three months and nine months ended September 30, 2009, and we paid $5.7 million and $13.5 million in cash settlements in the same periods of 2008.

The following table reconciles natural gas and crude oil revenues to realized prices, as adjusted for derivative activities, for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Natural gas	2009		2008			2009		2008
	(in thousands)
Natural gas revenues before impact of derivatives	$	36,654	$	101,911		$	129,305	$	295,636
Cash settlements on natural gas derivatives (1)		15,466		(4,818	)		45,232		(12,265	)
Natural gas revenues, adjusted for derivatives	$	52,120	$	97,093		$	174,537	$	283,371

	(per Mcf)
Natural gas revenues before impact of derivatives	$	3.45	$	10.14		$	3.82	$	9.90
Cash settlements on natural gas derivatives (1)		1.45		(0.48	)		1.33		(0.41	)
Natural gas revenues, adjusted for derivatives	$	4.90	$	9.66		$	5.15	$	9.49

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Crude oil	2009		2008			2009		2008
	(in thousands)
Crude oil revenues before impact of derivatives	$	13,259	$	13,764		$	31,412	$	37,442
Cash settlements on crude oil derivatives (1)		960		(883	)		3,690		(1,196	)
Crude oil revenues, adjusted for derivatives	$	14,219	$	12,881		$	35,102	$	36,246

	(per barrel)
Crude oil revenues before impact of derivatives	$	65.64	$	117.64		$	53.42	$	113.12
Cash settlements on crude oil derivatives (1)		4.75		(7.55	)		6.28		(3.62	)
Crude oil revenues, adjusted for derivatives	$	70.39	$	110.09		$	59.70	$	109.50

(1)	We adjust our derivative positions to fair value and record the fair market valuation gains or losses in the derivative line on our consolidated statements of income. Cash settlements relate to the realization of final derivative gains or losses.

Other Income. Other income for both the three and nine months ended September 30, 2009 decreased from the comparative periods of 2008 due to a $30.5 million gain on the sale of oil and gas properties in the third quarter of 2008.

Operating Expenses. Operating expenses decreased by $1.8 million, or 12%, from $15.1 million in the three months ended September 30, 2008 to $13.3 million in the same period of 2009 primarily due to lower repair and maintenance costs and lower water disposal fees, which decreased primarily because of the addition of water disposal facilities. On a per thousand cubic feet equivalent (Mcfe) basis, operating expenses decreased from $1.29 per Mcfe for the three months ended September 30, 2008 to $1.07 per Mcfe in the same period of 2009 due lower costs and higher production.

Operating expenses decreased by $0.6 million, or 1%, from $43.4 million in the nine months ended September 30, 2008 to $42.8 million in the same period of 2009 primarily due to higher gathering and processing fees resulting from higher production in several regions, partially offset by lower repair and maintenance costs and lower water disposal fees. On a per Mcfe basis, operating expenses decreased from $1.29 per Mcfe for the nine months ended September 30, 2008 to $1.08 per Mcfe in the same period of 2009 primarily due to higher production.

Taxes Other Than Income. Taxes other than income decreased by $2.3 million, or 35%, from $6.5 million in the three months ended September 30, 2008 to $4.2 million in the same period of 2009. Taxes other than income decreased by $6.7 million, or 34%, from $19.5 million in the nine months ended September 30, 2008 to $12.8 million in the same period of 2009. The decreases for both periods were primarily due to timing of refunds and lower severance taxes resulting from lower commodity prices, partially offset by higher production.

General and Administrative Expenses. General and administrative expenses remained constant at $5.1 million for the three months ended September 30, 2009 and 2008. General and administrative expenses increased by $1.1 million, or 7%, from $14.9 million in the nine months ended September 30, 2008 to $16.0 million in the same period of 2009 primarily due to higher payroll and employee benefit costs.

Exploration Expenses. Exploration expenses increased by $7.8 million, or 94%, from $8.3 million in the three months ended September 30, 2008 to $16.1 million in the same period in 2009 and increased by $35.1 million, or 177%, from $19.8 million in the nine months ended September 30, 2008 to $54.9 million in the same period in 2009. The following table summarizes the components of exploration expenses for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
	(in thousands)
Dry hole costs	$	52	$	959	$	1,389	$	3,790
Geological and geophysical		116		1,668		1,195		2,697
Unproved leasehold		10,257		4,562		28,803		11,202
Standby rig charges		3,713		-		20,316		-
Other		1,979		1,157		3,198		2,076
Total	$	16,117	$	8,346	$	54,901	$	19,765

Unproved leasehold expenses increased by $5.7 million, or 124%, from $4.6 million in the three months ended September 30, 2008 to $10.3 million in the same period of 2009 and increased by $17.6 million, or 157%, from $11.2 million in the nine months ended September 30, 2008 to $28.8 million in the same period of 2009. These increases were primarily due to a change we made to our accounting process effective January 1, 2009 to amortize additional insignificant unproved properties over the average estimated life of the leases rather than amortizing some leases and assessing other leases on an occurrence basis.

Standby rig charges totaled $3.7 million and $20.3 million in the three and nine months ended September 30, 2009 compared to zero in the comparative 2008 periods. In the first quarter of 2009, we reduced our drilling program in our oil and gas segment due to unfavorable economic conditions. In conjunction with the drilling program reduction, we amended certain drilling rig contracts to delay commencement of drilling until January 2010. As a result, we recognized standby rig charges for cancellation fees, minimum daily standby fees and demobilization fees as exploration expense in our consolidated statements of income. Based on the timing of remobilizing the drilling rigs, we could incur additional exploration expenses of up to $0.6 million for the remainder of 2009.

Impairment on Assets Held for Sale. For the three and nine months ended September 30, 2009, we recorded $87.9 million of impairments. As of September 30, 2009, certain oil and gas properties located in Texas, Louisiana and North Dakota were classified as current assets held for sale on our consolidated balance sheet. We completed the sale of the North Dakota properties in October 2009 and expect to complete the sale of the Louisiana and Texas properties in the fourth quarter of 2009. As a result of classifying these assets as held for sale, we incurred an impairment charge of $87.9 million to record the assets at fair value less costs to sell.

Other Impairments. For the three and nine months ended September 30, 2009, we recorded $4.5 million and $8.9 million of impairments. The impairment charge of $4.5 million included $0.8 million of inventory re-evaluation and $3.7 million of other impairments. The impairment charges of $8.9 million included $4.1 million of re-evaluation related to our tubular inventory due to decline in market value and $4.8 million of other impairments.

Depreciation, Depletion and Amortization Expenses. Depreciation, depletion and amortization expenses increased by $6.6 million, or 20%, from $32.7 million in the three months ended September 30, 2008 to $39.3 million in the same period of 2009. Depreciation, depletion and amortization expenses increased by $28.4 million, or 31%, from $90.8 million in the nine months ended September 30, 2008 to $119.2 million in the same period of 2009. The increases for both periods were due to an increase in equivalent production and higher depletion rates, which were caused by higher cost wells being drilled.

PVR Coal and Natural Resource Management Segment

As of December 31, 2008, PVR owned or controlled approximately 827 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. PVR enters into long-term leases with experienced, third-party mine operators, providing them the right to mine PVR’s coal reserves in exchange for royalty payments. PVR actively works with its lessees to develop efficient methods to exploit its reserves and to maximize production from its properties. PVR does not operate any mines. In the nine months ended September 30, 2009, PVR’s lessees produced 25.9 million tons of coal from PVR’s properties and paid to PVR coal royalties revenues of $90.4 million, for an average royalty per ton of $3.50 ($3.33 per ton net of coal royalties expenses). Approximately 82% of PVR’s coal royalties revenues in the nine months ended September 30, 2009 was derived from coal mined on PVR’s properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of PVR’s coal royalties revenues for the respective periods was derived from coal mined on PVR’s properties under leases containing fixed royalty rates that escalate annually.

PVR also earns revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees.

The deterioration of the global economy, including financial and credit markets, has reduced worldwide demand for coal with resultant price declines. Depending on the longevity and ultimate severity of the deterioration, demand for coal may continue to decline, which could adversely affect production and pricing for coal mined by PVR’s lessees, and, consequently, adversely affect the royalty income received by PVR and PVR’s ability to make cash distributions to its partners. The deterioration of the global economy has also adversely affected credit availability and PVR’s access to new capital. This limited access to capital and credit availability has and could continue to hamper PVR’s ability to fund acquisitions, potentially restricting future growth potential.

Three and Nine Months Ended September 30, 2009 Compared with the

Three and Nine Months Ended September 30, 2008

The following table sets forth a summary of certain financial and other data for the PVR coal and natural resource management segment for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Financial Highlights	(in thousands, except as noted)
Revenues
Coal royalties	$	29,821		$	33,308		$	90,448		$	88,911
Coal services		1,869			1,815			5,502			5,518
Timber		1,582			1,911			4,355			5,328
Oil and gas royalty		535			1,940			1,783			4,730
Other		1,372			2,686			6,487			6,523
Total revenues		35,179			41,660			108,575			111,010

Expenses
Coal royalties		1,587			2,125			4,380			8,034
Other operating		559			752			2,200			1,488
Taxes other than income		421			373			1,146			1,115
General and administrative		3,388			3,321			10,760			9,780
Depreciation, depletion and amortization		7,999			8,794			23,557			22,733
Total expenses		13,954			15,365			42,043			43,150

Operating income	$	21,225		$	26,295		$	66,532		$	67,860

Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,387			8,496			25,874			24,975
Coal royalties revenues, net of coal royalties expenses	$	28,234		$	31,183		$	86,068		$	80,877

Average coal royalties revenues per ton ($/ton)	$	3.56		$	3.92		$	3.50		$	3.56
Less coal royalties expenses per ton ($/ton)		(0.19	)		(0.25	)		(0.17	)		(0.32	)
Average net coal royalties per ton ($/ton)	$	3.37		$	3.67		$	3.33		$	3.24

The following tables summarize coal production, coal royalties revenues and coal royalties per ton by region for the three and nine months ended September 30, 2009 and 2008:

	Coal Production				Coal Royalties Revenues						Coal Royalties Per Ton
	Three Months Ended September 30,				Three Months Ended September 30,						Three Months Ended September 30,
Region	2009		2008		2009			2008			2009			2008
	(tons in thousands)				(in thousands)						($/ton)
Central Appalachia		4,594		4,815	$	21,089		$	25,184		$	4.59		$	5.23
Northern Appalachia		563		983		1,065			1,931			1.89			1.96
Illinois Basin		1,333		1,110		3,644			2,923			2.73			2.63
San Juan Basin		1,897		1,588		4,023			3,270			2.12			2.06
Total		8,387		8,496	$	29,821		$	33,308		$	3.56		$	3.92
Less coal royalties expenses (1)						(1,587	)		(2,125	)		(0.19	)		(0.25	)
Net coal royalties revenues					$	28,234		$	31,183		$	3.37		$	3.67

	Coal Production				Coal Royalties Revenues						Coal Royalties Per Ton
	Nine Months Ended September 30,				Nine Months Ended September 30,						Nine Months Ended September 30,
Region	2009		2008		2009			2008			2009			2008
	(tons in thousands)				(in thousands)						($/ton)
Central Appalachia		13,902		14,770	$	63,964		$	68,213		$	4.60		$	4.62
Northern Appalachia		2,680		2,767		4,965			4,922			1.85			1.78
Illinois Basin		3,739		3,262		9,747			7,173			2.61			2.20
San Juan Basin		5,553		4,176		11,772			8,603			2.12			2.06
Total		25,874		24,975	$	90,448		$	88,911		$	3.50		$	3.56
Less coal royalties expenses (1)						(4,380	)		(8,034	)		(0.17	)		(0.32	)
Net coal royalties revenues					$	86,068		$	80,877		$	3.33		$	3.24

(1)	PVR’s coal royalties expenses are incurred primarily in the Central Appalachian region.

Production. Coal production decreased by 0.1 million tons, or 1%, from 8.5 million tons in the three months ended September 30, 2008 to 8.4 million tons in the same period of 2009. This decrease was primarily driven by decreased longwall production in the Northern Appalachian region resulting from adverse geological conditions hampering production and recovery. Additionally, there were decreases in the Central Appalachia region primarily attributable to production cutbacks due to a depressed coal market. 2009 production in the Central Appalachian region also decreased due to cutbacks in longwall mining operations that were prevalent during 2008. Production from one of PVR’s lessees ceased in the third quarter of 2008 as its operations moved onto adjacent reserves. These production decreases were partially offset by production increases in both the Illinois and San Juan Basins. The Illinois Basin production increased primarily due to the recognition of royalties and tonnages for previously mined reserves held in escrow pending property ownership research. The San Juan Basin benefited from the start up of a second mine and improved mining conditions in the region.

Coal production increased by 0.9 million tons, or 4%, from 25.0 million tons in the nine months ended September 30, 2008 to 25.9 million tons in the same period of 2009. The year to date increase in production primarily resulted from the start up of a second mine and improved mining conditions in the San Juan Basin, as well as the third quarter 2009 royalty and tonnage adjustment in the Illinois Basin for previously mined reserves temporarily held in escrow as ownership research was conducted. Partially offsetting these increases was the decline of 2009 production in the Central Appalachian region primarily in response to a depressed coal market, most notably in the metallurgical market where coal demand has fallen drastically since the third quarter of 2008. Also contributing to the production decrease in the Central Appalachia region was the reduction in longwall mining activity compared to the same period in 2008.

Revenues. Net coal royalties revenues decreased by $3.0 million, or 10%, from $31.2 million in the three months ended September 30, 2008 to $28.2 million in the same period of 2009. This decrease was primarily attributable to lower coal sales prices in Central Appalachia which in turn resulted in lower royalty revenues, and, to a lesser extent, to lower coal volumes sold from PVR’s properties. The average net coal royalty per ton, which represents the average coal royalties revenues per ton net of coal royalties expenses per ton, decreased by $0.30 per ton, or 8%, from $3.67 per ton in the three months ended September 30, 2008 to $3.37 per ton in the same period of 2009. This decrease was attributable to a $0.36 per ton decrease in average coal royalties revenues per ton, partially offset by a $0.06 per ton decrease in coal royalties expenses. Average coal royalties revenues per ton decreased the most in the Central Appalachian region primarily due to significantly reduced demand for metallurgical coal in the international coal markets.

Coal services revenues remained relatively constant from the three months ended September 30, 2008 to the same period of 2009. Timber revenues decreased by $0.3 million, or 16%, from $1.9 million in the three months ended September 30, 2008 to $1.6 million in the same period of 2009 primarily due to lower sales prices resulting from weakened market conditions for furniture-grade wood products. Oil and gas royalties revenues decreased by $1.4 million, or 74%, from $1.9 million in the three months ended September 30, 2008 to $0.5 million in the same period of 2009 primarily due to lower natural gas prices. Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fees, decreased by $1.3 million, or 48%, from $2.7 million in the three months ended September 30, 2008 to $1.4 million in the same period of 2009 primarily due to lower wheelage income.

Net coal royalties revenues increased by $5.2 million, or 6%, from $80.9 million in the nine months ended September 30, 2008 to $86.1 million in the same period of 2009. This increase was attributable to increases in both production and average net coal sales prices received by PVR’s lessees. The average net coal royalty per ton increased by $0.09 per ton, or 3%, from $3.24 per ton in the nine months ended September 30, 2008 to $3.33 per ton in the same period of 2009. This increase was attributable to both an increase in the average coal royalties revenues per ton for most regions, especially in the Illinois Basin, where new contract pricing has generated higher gross sales prices for tonnages in that region, and lower coal royalties expenses caused by lower production from certain subleased properties.

Coal services revenues remained relatively constant from the nine months ended September 30, 2008 to the same period of 2009. Timber revenues decreased by $0.9 million, or 17%, from $5.3 million in the nine months ended September 30, 2008 to $4.4 million in the same period of 2009 primarily due to lower sales prices resulting from weakened market conditions for furniture-grade wood products. Oil and gas royalties revenues decreased by $2.9 million, or 62%, from $4.7 million in the nine months ended September 30, 2008 to $1.8 million in the same period of 2009 primarily due to lower natural gas prices. Other revenues remained relatively constant from the nine months ended September 30, 2008 to the same period of 2009.

Expenses. Other operating expenses decreased by $0.2 million, or 25%, from $0.8 million in the three months ended September 30, 2008 to $0.6 million in the same period of 2009 primarily due to lower expenses related to core drilling and mine maintenance costs for which PVR is contractually obligated. Taxes other than income and general and administrative expenses remained relatively constant from the three months ended September 30, 2008 to the same period of 2009. Depreciation, depletion and amortization expenses decreased by $0.8 million, or 9%, from $8.8 million in the three months ended September 30, 2008 to $8.0 million in the same period of 2009 primarily due to lower depletion expenses for PVR’s mining and timber operations.

Other operating expenses increased by $0.7 million, or 47%, from $1.5 million in the nine months ended September 30, 2008 to $2.2 million in the same period of 2009 primarily due to higher expenses related to PVR’s timber operations and costs incurred under PVR’s contractual obligations for mine maintenance. Taxes other than income remained relatively constant from the nine months ended September 30, 2008 to the same period of 2009. General and administrative costs increased by $1.0 million, or 10%, from $9.8 million in the nine months ended September 30, 2008 to $10.8 million in the same period of 2009 primarily due to higher staffing and related employee benefit costs. Depreciation, depletion and amortization expenses increased by $0.9 million, or 4%, from $22.7 million in the nine months ended September 30, 2008 to $23.6 million in the same period of 2009 primarily due to higher depletion expenses for PVR’s mining and timber operations.

PVR Natural Gas Midstream Segment

The PVR natural gas midstream segment provides natural gas processing, gathering and other related services. As of September 30, 2009, PVR owned and operated natural gas midstream assets located in Oklahoma and Texas, including six natural gas processing facilities having 400 million cubic feet per day (MMcfd) of total capacity and approximately 4,069 miles of natural gas gathering pipelines. The PVR natural gas midstream business earns revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, PVR owns a 25% member interest in Thunder Creek Gas Services, LLC, or Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

During the three months ended September 30, 2009, PVR completed a 40 MMcfd plant expansion in its Beaver/Spearman complex, or the Panhandle System, in Texas and Oklahoma in July and acquired an additional 60 MMcfd plant in Oklahoma that began accepting gas on September 1, 2009. This additional processing capacity allows PVR to process all of its Panhandle natural gas through PVR’s own facilities and eliminate fees paid to third parties for processing services. PVR also acquired a 50% member interest in a residue pipeline connected to its east Texas processing plant.

For the nine months ended September 30, 2009, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 93.4 billion cubic feet (Bcf), or approximately 342 MMcfd. For the nine months ended September 30, 2009, 23% of the PVR natural gas midstream segment’s revenues and 14% of our total consolidated revenues were derived from one of the PVR natural gas midstream segment’s customers, Conoco, Inc.

PVR continually seeks new supplies of natural gas to offset the natural declines in production from the wells currently connected to its systems and to increase system throughput volumes. New natural gas supplies are obtained for all of PVR’s systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors’ systems. In the nine months ended September 30, 2009, the PVR natural gas midstream segment made aggregate capital expenditures of $72.0 million, primarily related to PVR’s Panhandle System in Texas and Oklahoma.

Revenues, profitability and the future rate of growth of the PVR natural gas midstream segment are highly dependent on market demand and prevailing natural gas liquid, or NGL, and natural gas prices. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market demand. The deterioration of the global economy has resulted in a decrease in demand for natural gas and NGLs. Depending on the longevity and ultimate severity of the deterioration, NGL production from its processing plants could decrease and adversely affect PVR’s natural gas midstream processing income and PVR’s ability to make cash distributions. The deterioration of the global economy has also adversely affected credit availability and PVR’s access to new capital. This limited access to capital and credit availability has and could continue to hamper PVR’s ability to fund acquisitions, potentially restricting future growth potential.

Three and Nine Months Ended September 30, 2009 Compared with the

Three and Nine Months Ended September 30, 2008

The following table sets forth a summary of certain financial and other data for the PVR natural gas midstream segment for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009		2008
Financial Highlights
Revenues
Residue gas	$	62,801	$	158,709		$	211,165	$	373,913
Natural gas liquids		48,147		72,349			117,670		199,053
Condensate		4,659		7,202			11,507		21,870
Gathering, processing and transportation fees		2,836		3,022			8,540		6,291
Total natural gas midstream revenues (1)		118,443		241,282			348,882		601,127
Equity earnings in equity investment		1,597		981			3,345		1,537
Producer services		406		1,353			1,001		4,921
Total revenues		120,446		243,616			353,228		607,585

Expenses
Cost of midstream gas purchased (1)		92,355		211,262			285,129		513,778
Operating		6,884		6,164			20,358		15,031
Taxes other than income		584		596			2,062		1,902
General and administrative		4,180		3,757			12,661		10,559
Depreciation and amortization		9,852		8,109			28,414		18,589
Total operating expenses		113,855		229,888			348,624		559,859

Operating income	$	6,591	$	13,728		$	4,604	$	47,726

Operating Statistics
System throughput volumes (MMcf)		29,811		27,744			93,433		68,915
Daily throughput volumes (MMcfd)		324		302			342		252

Gross margin	$	26,088	$	30,020		$	63,753	$	87,349
Cash impact of derivatives		1,993		(12,551	)		9,162		(29,151	)
Gross margin, adjusted for impact of derivatives	$	28,081	$	17,469		$	72,915	$	58,198

Gross margin ($/Mcf)	$	0.88	$	1.08		$	0.68	$	1.27
Cash impact of derivatives ($/Mcf)		0.06		(0.45	)		0.10		(0.42	)
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.94	$	0.63		$	0.78	$	0.85

(1)

In the three months ended September 30, 2009, PVR recorded $15.1 million of natural gas midstream revenues and $15.1 million for the cost of midstream gas purchased related to the purchase of natural gas from Penn Virginia Oil & Gas, L.P., or PVOG LP, and the subsequent sale of that gas to third parties. In the nine months ended September 30, 2009, PVR recorded $56.4 million of natural gas midstream revenues and $56.4 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP and the subsequent sale of that gas to third parties. PVR takes title to the gas prior to transporting it to third parties.

Gross Margin. PVR’s gross margin is the difference between PVR’s natural gas midstream revenues and PVR’s cost of midstream gas purchased. Natural gas midstream revenues include residue gas sold from processing plants after NGLs are removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to PVR’s gas processing plants. Cost of midstream gas purchased consists of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts.

The 13% gross margin decrease in the three months ended September 30, 2009 as compared to the same period of 2008 was primarily due to lower commodity pricing and frac spreads. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per million British thermal unit (MMBtu) basis. The gross margin decrease was partially offset by margins earned from higher system throughput volumes.

System throughput volumes increased by 22 MMcfd, or 7%, from 302 MMcfd in the three months ended September 30, 2008 to 324 MMcfd in the same period of 2009 primarily due to the continued successful development by producers operating in the vicinity of the Panhandle System, as well as PVR’s success in contracting and connecting new supply.

During the three months ended September 30, 2009, PVR generated a majority of its gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of its risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See Note 5, “Derivative Instruments,” in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements,” for a description of PVR’s derivatives program. Adjusted for the cash impact of PVR’s commodity derivative instruments, PVR’s gross margin increased by $10.6 million, or 61%, from $17.5 million in the three months ended September 30, 2008 to $28.1 million in the same period of 2009. On a per Mcf basis, adjusted for the cash impact of PVR’s commodity derivatives, PVR’s gross margin increased by $0.31 per Mcf, or 49%, from $0.63 per Mcf in the three months ended September 30, 2008 to $0.94 per Mcf in the same period of 2009. This increase was primarily attributable to changes in commodity prices and the mix of PVR’s commodity derivatives.

The 27% gross margin decrease in the nine months ended September 30, 2009 as compared to the same period of 2008 was a result of lower commodity pricing and frac spreads, partially offset by margins earned from higher system throughput volumes.

System throughput volumes increased by 90 MMcfd, or 36%, from 252 MMcfd in the nine months ended September 30, 2008 to 342 MMcfd in the same period of 2009 primarily due to the continued successful development by producers operating in the vicinity of the Panhandle System, as well as PVR’s success in contracting and connecting new supply. The Crossroads plant in East Texas, which became fully operational in April 2008, and the acquisition of PVR’s North Texas gathering system, which was consummated in the third quarter of 2008, also contributed to the volume increase.

Adjusted for the cash impact of PVR’s commodity derivative instruments, PVR’s gross margin increased by $14.7 million, or 25%, from $58.2 million in the nine months ended September 30, 2008 to $72.9 million in the same period of 2009. On a per Mcf basis, adjusted for the cash impact of PVR’s commodity derivatives, PVR’s gross margin decreased by $0.07 per Mcf, or 8%, from $0.85 per Mcf in the nine months ended September 30, 2008 to $0.78 per Mcf in the same period of 2009. This decrease was primarily attributable to the addition of lower margin fixed fee volumes at the Crossroads plant and from PVR’s recently acquired North Texas gathering system.

Equity Earnings in Equity Investment. PVR’s equity earnings increased in both the three and nine months ended September 30, 2009 as compared to the same periods of 2008 primarily as a result of revenues generated from PVR’s 25% member interest in the Thunder Creek joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. In 2009, revenues from this joint venture have grown primarily due to mainline volume increases despite the reduction in drilling in the Powder River Basin.

Producer Services Revenues. Producer services revenues decreased by $1.0 million, or 71%, from $1.4 million in the three months ended September 30, 2008 to $0.4 million in the same period of 2009 primarily due to a negative relative change in the natural gas indices on which PVR’s purchases and sales of natural gas are based and a decrease in marketing fees resulting from lower commodity prices.

Producer services revenues decreased by $3.9 million, or 80%, from $4.9 million in the nine months ended September 30, 2008 to $1.0 million in the same period of 2009 primarily due to a negative relative change in the natural gas indices on which PVR’s purchases and sales of natural gas are based and a decrease in marketing fees resulting from lower commodity prices.

Expenses. Operating expenses increased by $0.7 million, or 11%, from $6.2 million in the three months ended September 30, 2008 to $6.9 million in the same period of 2009 primarily due to higher costs for compressor rentals related to PVR’s expanding footprint in the Texas and Oklahoma panhandle. General and administrative expenses increased by $0.4 million, or 11%, from $3.8 million in the three months ended September 30, 2008 to $4.2 million in the same period of 2009 primarily due to higher staffing and related employee benefit costs. Depreciation and amortization expenses increased by $1.8 million, or 22%, from $8.1 million in the three months ended September 30, 2008 to $9.9 million in the same period of 2009 primarily due to capital spending on expansion projects, such as the Spearman and Crossroads plants, and PVR’s recent acquisitions.

Operating expenses increased by $5.4 million, or 36%, from $15.0 million in the nine months ended September 30, 2008 to $20.4 million in the same period of 2009 primarily due to higher costs for compressor rentals, employee costs and general supplies needed to operate assets in the Texas and Oklahoma panhandle. General and administrative expenses increased by $2.1 million, or 20%, from $10.6 million in the nine months ended September 30, 2008 to $12.7 million in the same period of 2009 primarily due to higher staffing and related employee benefit costs. Depreciation and amortization expenses increased by $9.8 million, or 53%, from $18.6 million in the nine months ended September 30, 2008 to $28.4 million in the same period of 2009 primarily due to capital spending on expansion projects, such as the Spearman and Crossroads plants, and PVR’s recent acquisitions.

Other

The following table sets forth a summary of certain financial data and our other results for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands)
Operating income (loss)	$	(94,831	)	$	122,327		$	(118,787	)	$	288,684
Other income (expense)
Interest expense		(22,784	)		(13,221	)		(50,332	)		(35,313	)
Derivatives		(2,529	)		125,132			8,478			(4,387	)
Other		348			(4,088	)		2,274			(782	)
Income tax benefit (expense)		50,405			(78,921	)		69,587			(74,352	)
Net income (loss)		(69,391	)		151,229			(88,780	)		173,850
Less net income attributable to noncontrolling interests		(10,509	)		(28,276	)		(20,512	)		(52,252	)
Net income (loss) attributable to Penn Virginia Corporation	$	(79,900	)	$	122,953		$	(109,292	)	$	121,598

Operating Income. Our operating income decreased by $217.1 million, or 178%, from $122.3 million of operating income in the three months ended September 30, 2008 to $94.8 million of operating loss in the same period of 2009. Our operating income decreased by $407.5 million, or 141%, from $288.7 million of operating income in the nine months ended September 30, 2008 to $118.8 million of operating loss in the same period of 2009. The decreases in both periods were due primarily to lower revenues and the impairment on assets held for sale.

Interest Expense. Our consolidated interest expense increased by $9.6 million, or 72%, from $13.2 million in the three months ended September 30, 2008 to $22.8 million in the same period of 2009. Of the $9.6 million increase, $10.1 million related to an increase in our interest expense, partially offset by $0.5 million decrease in PVR’s interest expense. Our consolidated interest expense increased by $15.0 million, or 42%, from $35.3 million in the nine months ended September 30, 2008 to $50.3 million in the same period of 2009. Of the $15.0 million increase, $13.9 million related to an increase in our interest expense and $1.1 million related to an increase in PVR’s interest expense.

Our consolidated interest expense for the three and nine months ended September 30, 2009 and 2008 is comprised of the following:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Source	2009			2008			2009			2008
	(in thousands)
Interest on Penn Virginia borrowings	$	14,357		$	6,328		$	29,891		$	18,824
Penn Virginia capitalized interest		(566	)		(492	)		(1,471	)		(1,555	)
Penn Virginia interest rate swaps		2,488			325			3,426			678
Penn Virginia interest expense		16,279			6,161			31,846			17,947

Interest on PVR borrowings		5,648			6,206			16,112			16,828
PVR capitalized interest		-			-			(226	)		(675	)
PVR interest rate swaps		857			854			2,600			1,213
PVR interest expense		6,505			7,060			18,486			17,366

Total interest expense	$	22,784		$	13,221		$	50,332		$	35,313

Our interest expense for both the three and nine months ended September 30, 2009 increased from the comparative periods in 2008 due to increased borrowings as a result of our oil and gas capital expenditures program and the issuance of our 10.375% Senior Notes due 2016, or the Senior Notes, in June 2009.

PVR’s interest expense for three months ended September 30, 2009 decreased by 8% from the comparative period of 2008 primarily due to lower interest rates. PVR’s interest expense for the nine months ended September 30, 2009 increased by 6% from the comparative period in 2008 due to an increase in PVR’s weighted average debt balance. This increase was due to PVR’s past capital spending program, including acquisitions, and an increase in non-cash interest expense related to debt issuance costs, partially offset by lower interest rates.

Derivatives. Consolidated derivative losses were $2.5 million in the three months ended September 30, 2009 compared to consolidated derivative gains of $125.1 million in the same period of 2008. Consolidated derivative gains were $8.5 million in the nine months ended September 30, 2009 compared to consolidated derivative losses of $4.4 million in the same period of 2008. These gains and losses were due primarily to volatility in natural gas, NGL and crude oil prices. We determine the fair values of our commodity derivative agreements using quoted forward prices for these commodities. Cash received for settlements in the three months ended September 30, 2009 was $16.4 million and cash paid for settlements was $5.7 million in the same period of 2008. Cash received for settlements in the nine months ended September 30, 2009 was $48.9 million and cash paid for settlements was $13.5 million in the same period of 2008.

The components of our consolidated derivative activity for the three and nine months ended September 30, 2009 and 2008 were as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands)
Oil and gas unrealized derivative gain (loss)	$	(15,725	)	$	115,091		$	(27,842	)	$	15,498
Oil and gas realized gain (loss)		16,426			(5,701	)		48,922			(13,461	)
Interest rate swap unrealized gain		185			-			524			-
Interest rate swap realized loss		(605	)		-			(1,121	)		-
PVR midstream unrealized derivative gain (loss)		(856	)		29,796			(17,916	)		26,855
PVR midstream realized gain (loss)		1,993			(14,054	)		9,162			(33,279	)
PVR interest rate swap unrealized gain (loss)		(1,640	)		-			1,776			-
PVR interest rate swap realized loss		(2,307	)		-			(5,027	)		-

Total derivative gains (losses)	$	(2,529	)	$	125,132		$	8,478		$	(4,387	)

Other. Other income primarily consists of interest income and gains on sales of securities.

Income Tax Benefit. We recognized an income tax benefit of $50.4 million and $69.6 million for the three and nine months ended September 30, 2009 compared to an income tax expense of $78.9 million and $74.4 million for the same periods in 2008. The 2009 income tax benefit is a result of a net loss before income taxes for the three and nine months ended September 30, 2009. We expect to realize any income tax benefits created in 2009 by amending prior year tax returns and carrying forward any excess income tax benefits.

Noncontrolling Interests. Noncontrolling interests represent net income allocated to the limited partner units of PVG owned by the public. See Note 3, “Noncontrolling Interests,” in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements,” for a description of the noncontrolling interests in PVG. In the three months ended September 30, 2009 and 2008, the noncontrolling interests in PVG increased our consolidated net loss by $10.5 million and $28.3 million. The decrease in the noncontrolling interests in PVG was primarily due to the decrease in PVG’s net income, from $44.0 million in the three months ended September 30, 2008 to $18.0 million in the same period of 2009. In the nine months ended September 30, 2009 and 2008, the noncontrolling interests in PVG increased our consolidated net loss by $20.5 million and $52.3 million. The decrease in the noncontrolling interests in PVG was primarily due to the decrease in PVG’s net income, from $87.0 million in the nine months ended September 30, 2008 to $39.7 million in the same period of 2009. In September 2009, we sold 10.0 million of our PVG common units, which decreased our ownership in PVG from 77.0% to 51.4%.

Liquidity and Capital Resources

Overview

Although results are consolidated for financial reporting, Penn Virginia, PVG and PVR operate with independent capital structures. As such, cash flow available to Penn Virginia from PVG and PVR is only in the form of cash distributions declared and paid to us on account of our partner interests in those entities, which totaled $34.4 million for the nine months ended September 30, 2009. The cash needs of each entity continue to be met independently with a combination of operating cash flows, credit facility borrowings and equity proceeds.

We generally satisfy our working capital requirements, debt service obligations and dividend payments and fund our capital expenditures using cash flow generated from our operations, cash distributions received from PVG and PVR, borrowings of long-term debt and sales of non-core assets. As noted above, we have $47.1 million of assets held for sale which we expect to sell in the fourth quarter of 2009. As discussed in more detail in “Long-Term Debt” below, as of September 30, 2009, we had availability of $366.3 million on our $367.0 million revolving credit facility, or the Revolver. We continually review drilling and other capital expenditure plans and may change the amount we spend in any region. We believe our cash flow from operating activities, distributions received from PVG and PVR and availability under our Revolver are sufficient to fund our remaining 2009 planned oil and gas capital expenditure program.

On an ongoing basis, PVR generally satisfies its working capital requirements and funds its capital expenditures using cash generated from its operations, borrowings under its $800.0 million revolving credit facility, or the PVR Revolver, and proceeds from PVR equity offerings. As discussed in more detail in “—Long-Term Debt” below, as of September 30, 2009, PVR had availability of $170.3 million on the PVR Revolver. PVR funds its debt service obligations and distributions to unitholders solely using cash generated from its operations. PVR believes that the cash generated from its operations and its borrowing capacity will be sufficient to meet its working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), interest payments on amounts outstanding under the PVR Revolver and its distribution payments for the remainder of 2009. However, PVR’s ability to meet these requirements in the future will depend upon PVR’s future operating performance, which will be affected by prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond PVR’s control.

Cash Flows

The following table summarizes our statements of cash flows for the nine months ended September 30, 2009 and 2008:

	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 2008
	Oil and Gas									Oil and Gas
	& Other			PVG			Consolidated			& Other			PVG			Consolidated
	(in thousands)
Net cash provided by operating activities	$	105,598		$	116,425		$	222,023		$	181,920		$	94,767		$	276,687

Net cash flows from investing activities:
Additions to property and equipment and acquisitions		(183,528	)		(73,291	)		(256,819	)		(329,986	)		(306,276	)		(636,262	)
Other		7,826			872			8,698			-			-			-
Net cash used in investing activities		(175,702	)		(72,419	)		(248,121	)		(329,986	)		(306,276	)		(636,262	)

Net cash provided by financing activities:
Distributions received (paid)		30,323			(92,966	)		(62,643	)		34,370			(80,199	)		(45,829	)
Debt borrowings, net		(48,533	)		60,000			11,467			104,431			146,000			250,431
Net proceeds from equity issuance		64,835			-			64,835			(2,943	)		140,958			138,015
Sale of PVG units		118,080			-			118,080			-			-			-
Other		(18,945	)		-			(18,945	)		5,512			(4,074	)		1,438
Net cash provided by (used in) financing activities		145,760			(32,966	)		112,794			141,370			202,685			344,055
Net increase (decrease) in cash	$	75,656		$	11,040		$	86,696		$	(6,696	)	$	(8,824	)	$	(15,520	)

On a consolidated basis, we had $105.0 million and $18.3 million in cash and cash equivalents as of September 30, 2009 and December 31, 2008.

Operating Activities. Cash provided by operating activities was $222.0 million for the nine months ended September 30, 2009 compared to $276.7 million for the nine months ended September 30, 2008. This decrease was primarily due to our net loss of $88.8 million in the nine months ending September 30, 2009.

Investing Activities. Cash used in investing activities was $248.1 million for the nine months ended September 30, 2009 compared to $636.3 million for the nine months ended September 30, 2008. This decrease was due to the lower oil and gas segment capital expenditures as a result of weakened economic conditions and lower commodity prices and reduced acquisition activity by PVR. For the remainder of 2009, we anticipate making oil and gas segment capital expenditures of $64.8 million to $78.5 million and PVR anticipates making coal and natural resource management and natural gas midstream segment capital expenditures of $2.5 million to $11.0 million.

Financing Activities. Cash provided by financing activities was $112.8 million and $344.1 million for the nine months ended September 30, 2009 and 2008. For the nine months ended September 30, 2009, net proceeds from the issuance of the Senior Notes were $281.6 million; net proceeds from the issuance of 3.5 million shares of our common stock were $64.8 million and net proceeds from the sale of PVG units that we owned were $118.1 million. The majority of the proceeds from these issuances were used to repay our borrowings under the Revolver and other liabilities. See the Notes to Consolidated Financial Statements in Item 1, “Financial Statements,” for an additional discussion of these issuances. We received cash distributions from PVG and PVR of $34.4 million and $32.2 million in the nine months ended September 30, 2009 and 2008. For the nine months ended September 30, 2009, PVR’s net debt borrowings were $60.0 million, offset by $93.0 million of distributions paid.

Long-Term Debt

The following table summarizes our long-term debt as of September 30, 2009 and December 31, 2008:

	September 30,		December 31,
	2009		2008
	(in thousands)
Short-term borrowings	$	-	$	7,542
Revolving credit facility		-		332,000
Senior notes, net of discount (1)		291,432		-
Convertible notes, net of discount		204,935		199,896
Total recourse debt of the Company		496,367		539,438
Long-term debt of PVR		628,100		568,100
Total consolidated debt		1,124,467		1,107,538
Less: Short-term borrowings		-		(7,542	)
Total consolidated long-term debt	$	1,124,467	$	1,099,996

(1)	Includes original issue discount of $9.0 million, which is amortizable through June 15, 2016.

Revolver. In June 2009, the borrowing base under the Revolver was revised from $450.0 million to $367.0 million due to the issuance of the Senior Notes. As of September 30, 2009, we had no borrowing outstanding under the Revolver. As of September 30, 2009, we had remaining borrowing capacity of to $366.3 million on the Revolver, net of outstanding letters of credit of $0.7 million. The Revolver, which matures in December 2010, is secured by a portion of our proved oil and gas reserves. The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10.0 million sublimit for the issuance of letters of credit. Interest is payable at a base rate plus an applicable margin of ranging from 1.125% to 2.125% if we select the base rate borrowing option under the Revolver, or at a rate derived from the London Interbank Offered Rate, or LIBOR, plus an applicable margin ranging from 2.00% to 3.00% if we select the LIBOR-based borrowing option. As December 31, 2008, the weighted average interest rate on borrowings outstanding under the Revolver was approximately 2.5%. In 2006, we entered into interest rate swaps, or the Interest Rate Swaps, with notional amounts of $50.0 million to establish fixed interest rates on a portion of the then outstanding borrowings under the Revolver through December 2010. See Item 3, “Quantitative and Qualitative Disclosures About Market Risk —Interest Rate Risk,” for a discussion of the Interest Rate Swaps. As of September 30, 2009, we were in compliance with all of our covenants under the Revolver.

Senior Notes. In June 2009, we issued and sold $300.0 million of Senior Notes. The Senior Notes mature on June 15, 2015 and bear interest at an annual rate of 10.375%. The Senior Notes were sold at 97% of par, equating to an effective yield to maturity of approximately 11%. The net proceeds from the sale of the Senior Notes of $281.6 million were used to repay borrowings under the Revolver. As of September 30, 2009, the carrying value of the Senior Notes was $291.4 million. The Senior Notes are senior to our existing and future subordinated indebtedness, including the Convertible Notes, and are effectively subordinated to all of our secured indebtedness including the Revolver to the extent of the collateral securing that indebtedness. The obligations under the Senior Notes are fully and unconditionally guaranteed by our oil and gas subsidiaries, which are also guarantors under our Revolver.

Convertible Notes. In December 2007, we issued and sold $230.0 million of Convertible Notes. As of September 30, 2009, the carrying value of the Convertible Notes was $204.9 million. The Convertible Notes bear interest at an annual rate of 4.50%. The Convertible Notes are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.316 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment, and, if not converted or repurchased earlier, will mature on November 15, 2012.

PVR Revolver. In March 2009, PVR increased the size of the PVR Revolver from $700.0 million to $800.0 million, which resulted in $9.3 million of debt issuance costs. The PVR Revolver is secured with substantially all of PVR’s assets. As of September 30, 2009, PVR had remaining borrowing capacity of $170.3 million on the PVR Revolver, net of outstanding borrowings of $628.1 million and letters of credit of $1.6 million. The PVR Revolver matures in December 2011 and is available to PVR for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10.0 million sublimit for the issuance of letters of credit. Interest is payable at a base rate plus an applicable margin of up to 1.25% if PVR selects the base rate borrowing option or at a rate derived from LIBOR plus an applicable margin ranging from 1.75% to 2.75% if PVR selects the LIBOR-based borrowing option. At September 30, 2009, the base rate applicable margin was 0.75% and the LIBOR-based rate applicable margin was 2.25%. At September 30, 2009, the weighted average interest rate on borrowings outstanding under the PVR Revolver was approximately 2.5%. PVR entered into interest rate swaps, or the PVR Interest Rate Swaps, to establish fixed interest rates on a portion of the outstanding borrowings under the PVR Revolver. See Item 3, “Quantitative and Qualitative Disclosures About Market Risk —Interest Rate Risk,” for a discussion of the PVR Interest Rate Swaps. As of September 30, 2009, PVR was in compliance with all of its covenants under the PVR Revolver. Debt outstanding under the PVR Revolver is non-recourse to us and PVG.

Future Capital Needs and Commitments

Subject to commodity prices and the availability of capital, we expect to expand our oil and gas operations over the next several years by continuing to execute a program dominated by development drilling and, to a lesser extent, exploration drilling, supplemented periodically with property and reserve acquisitions.

We believe our portfolio of assets provides us with opportunities for organic growth which could require capital in excess of our internal sources. We continue to assess funding needs for our capital program in the context of our presently available debt capacity. To fund our growth, we expect to use a combination of cash flow from operating activities, borrowings under the Revolver, issuances of additional debt and equity securities and sales of non-core assets. We cannot be certain that we will be able to issue our debt or equity securities or sell our non-core assets on terms or in the amounts that we anticipate, and we may be unable to refinance the Revolver when it expires in 2010. In addition, we may be unable to obtain adequate funding under the Revolver because our lending counterparties may be unwilling or unable to meet their funding obligations.

For the remainder of 2009, we anticipate making oil and gas segment capital expenditures of approximately $72.0 to $84.0 million. In addition to these capital expenditures, we could incur up to $1.7 million of additional cost for rig delay and standby charges, which would be recorded as exploration as incurred. These capital and other rig delay-related expenditures are also expected to be funded primarily from internally generated sources of cash, including cash distributions received from PVG and PVR, supplemented by borrowings on the Revolver as needed.

PVR believes that short-term cash requirements for operating expenses and quarterly distributions to its general partner and unitholders will be funded through operating cash flows. PVR believes that its remaining borrowing capacity will be sufficient for its capital needs and commitments for the remainder of 2009. Subject to commodity prices and the availability of capital, PVR is committed to the growth of both of its business segments through a combination of organic projects and acquisitions of new properties and assets. For the remainder of 2009, PVR anticipates making capital expenditures of approximately $11.0 to $19.0 million. The majority of PVR’s 2009 capital expenditures are expected to be incurred in the PVR natural gas midstream segment.

Long-term cash requirements for PVR’s acquisitions and other capital expenditures are expected to be funded by several sources, including cash flows from PVR’s operating activities, borrowings under the PVR Revolver and the issuance of additional PVR debt and equity securities if available on commercially acceptable terms. However, disruptions in the global financial and commodities markets and the general economic climate have made access to equity and debt capital markets very difficult since late in 2008. While signs of improvement in these markets have occurred, if PVR is unable to access the capital markets for an extended period, PVR’s ability to make acquisitions and other capital expenditures, as well as PVR’s ability to increase or sustain cash distributions to its partners will likely become impaired. If additional financing is required, there are no assurances that it will be available or, if available, that it can be obtained on terms favorable to PVR.

The ability of each entity in the long-term to independently satisfy its obligations and planned expenditures will depend on its future operating performance, which will be affected by, among other things, prevailing economic conditions, some of which are beyond our control. In addition, depending on the longevity and ultimate severity of the deterioration of the global economy, including financial and credit markets, our and PVR’s ability in the future to grow organically or through acquisitions may be adversely affected, as may PVR’s ability to make cash distributions to its limited partners and to PVG, the owner of its general partner.

Environmental Matters

Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition or results of operations. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations.

PVR’s operations and those of its coal lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of PVR’s coal property leases impose liability on the relevant lessees for all environmental and reclamation liabilities arising under those laws and regulations. The lessees are bonded and have indemnified PVR against any and all future environmental liabilities. PVR regularly visits its coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. PVR’s management believes that its operations and those of its lessees comply with existing laws and regulations and does not expect any environment-related material adverse impact on its financial condition or results of operations.

Summary of Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Our most critical accounting policies which involve the judgment of our management were fully disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008 and remained unchanged as of September 30, 2009.

Recent Accounting Pronouncements

See Note 15, “New Accounting Standards,” in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements,” for a description of recent accounting pronouncements.

Forward-Looking Statements

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following:

•

the volatility of commodity prices for natural gas, NGLs, crude oil and coal;

•

our ability to access external sources of capital;

•

uncertainties relating to the occurrence and success of capital-raising transactions, including securities offerings and asset sales;

•

reductions in the borrowing base under our Revolver;

•

our ability to develop and replace oil and gas reserves and the price for which such reserves can be acquired;

•

any impairment write-downs of our reserves or assets;

•

reductions in our anticipated capital expenditures;

•

the relationship between natural gas, NGL, crude oil and coal prices;

•

the projected demand for and supply of natural gas, NGLs, crude oil and coal;

•

the availability and costs of required drilling rigs, production equipment and materials;

•

our ability to obtain adequate pipeline transportation capacity for our oil and gas production;

•

competition among producers in the oil and natural gas and coal industries generally and among natural gas midstream companies;

•

the extent to which the amount and quality of actual production of our oil and natural gas or PVR’s coal differ from estimated proved oil and gas reserves and recoverable coal reserves;

•

PVR’s ability to generate sufficient cash from its businesses to maintain and pay the quarterly distribution to its general partner and its unitholders;

•

the experience and financial condition of PVR’s coal lessees and natural gas midstream customers, including the lessees’ ability to satisfy their royalty, environmental, reclamation and other obligations to PVR and others;

•

operating risks, including unanticipated geological problems, incidental to our business and to PVR’s coal or natural gas midstream businesses;

•

PVR’s ability to acquire new coal reserves or natural gas midstream assets and new sources of natural gas supply and connections to third-party pipelines on satisfactory terms;

•

PVR’s ability to retain existing or acquire new natural gas midstream customers and coal lessees;

•

the ability of PVR’s lessees to produce sufficient quantities of coal on an economic basis from PVR’s reserves and obtain favorable contracts for such production;

•

the occurrence of unusual weather or operating conditions including force majeure events;

•

delays in anticipated start-up dates of our oil and natural gas production, of PVR’s lessees’ mining operations and related coal infrastructure projects and new processing plants in PVR’s natural gas midstream business;

•

environmental risks affecting the drilling and producing of oil and gas wells, the mining of coal reserves or the production, gathering and processing of natural gas;

•

the timing of receipt of necessary governmental permits by us and by PVR or PVR’s lessees;

•

hedging results;

•

accidents;

•

changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning power generators;

•

uncertainties relating to the outcome of current and future litigation regarding mine permitting;

•

risks and uncertainties relating to general domestic and international economic (including inflation, interest rates and financial and credit markets) and political conditions (including the impact of potential terrorist attacks);

•

PVG’s ability to generate sufficient cash from its interests in PVR to maintain and pay the quarterly distribution to its unitholders;

•

uncertainties relating to our continued ownership of interests in PVG and PVR; and

•

other risks set forth in our Annual Report on Form 10-K for the year ended December 31, 2008.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2008. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

Item 3 Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we and PVR are exposed are as follows:

•

Price Risk

•

Interest Rate Risk

As a result of our and PVR’s risk management activities as discussed below, we are also exposed to counterparty risk with financial institutions with whom we and PVR enter into these risk management positions. Sensitivity to these risks has heightened due to the deterioration of the global economy, including financial and credit markets.

Price Risk

Our and PVR’s price risk management programs permit the utilization of derivative financial instruments (such as swaps, costless collars and three-way collars) to seek to mitigate the price risks associated with fluctuations in natural gas, NGL and crude oil prices as they relate to our anticipated production and PVR’s natural gas midstream business. The derivative financial instruments are placed with major financial institutions that we believe are of acceptable credit risk. The fair values of our and PVR’s derivative financial instruments are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

In the nine months ended September 30, 2009, we reported consolidated net derivative gains of $8.5 million. Because we and PVR no longer use hedge accounting for commodity derivatives, we recognize changes in fair value in earnings currently in the derivatives line item on our consolidated statements of income. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our and PVR’s commodity derivative contracts. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in natural gas, NGL and crude oil prices. These fluctuations could be significant in a volatile pricing environment. See Note 5, “Derivative Instruments,” in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements,” for a further description of our and PVR’s derivatives programs.

Oil and Gas Segment

The following table lists our commodity derivative agreements and their fair values as of September 30, 2009:

	Average		Weighted Average Price						Fair Value at
	Volume		Additional						September 30,
	Per Day		Put Option		Floor		Ceiling		2009
									(in thousands)
Natural Gas Costless Collars	(MMBtu)		($ per MMBtu)
Fourth Quarter 2009		15,000				4.25		5.70	$	64
First Quarter 2010		35,000				4.96		7.41		(325	)
Second Quarter 2010		30,000				5.33		8.02		539
Third Quarter 2010		30,000				5.33		8.02		204
Fourth Quarter 2010		50,000				5.65		8.77		201
First Quarter 2011		50,000				5.65		8.77		(1,266	)
Second Quarter 2011		30,000				5.67		7.58		(188	)
Third Quarter 2011		30,000				5.67		7.58		(498	)

Natural Gas Three-Way Collars	(MMBtu)		($ per MMBtu)
Fourth Quarter 2009		30,000		6.83		9.50		13.60		7,084
First Quarter 2010		30,000		6.83		9.50		13.60		6,055

Natural Gas Swaps	(MMBtu)		($ per MMBtu)
Fourth Quarter 2009		40,000				4.91				579
First Quarter 2010		15,000				6.19				297
Second Quarter 2010		30,000				6.17				554
Third Quarter 2010		30,000				6.17				(31	)

Crude Oil Three-Way Collars	(barrels)		($ per barrel)
Fourth Quarter 2009		500		80.00		110.00		179.00		1,315

Crude Oil Swaps	(barrels)		($ per barrel)
Fourth Quarter 2009		500				59.25				(541	)

Crude Oil Costless Collars	(barrels)		($ per barrel)
First Quarter 2010		500				60.00		74.75		(159	)
Second Quarter 2010		500				60.00		74.75		(227	)
Third Quarter 2010		500				60.00		74.75		(271	)
Fourth Quarter 2010		500				60.00		74.75		(317	)

Settlements to be paid in subsequent period										297

Oil and gas segment commodity derivatives - net asset									$	13,366

We estimate that a $1.00 per MMBtu increase in the natural gas purchase price would decrease the fair value of our natural gas derivatives by $25.8 million. We estimate that a $1.00 MMBtu decrease in the natural gas purchase price would increase the fair value of our natural gas derivatives by $24.9 million. In addition, we estimate that a $5.00 per barrel increase in the crude oil price would decrease the fair value of our crude oil derivatives by $1.0 million. We estimate that a $5.00 per barrel decrease in the crude oil price would increase the fair value of our crude oil derivatives by $1.0 million.

We estimate that, excluding the effects of our derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, oil and gas segment operating income for the remainder of 2009 would increase or decrease by $8.8 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, oil and gas segment operating income for the remainder of 2009 would increase or decrease by $1.0 million. This assumes that natural gas prices, crude oil prices and production volumes remain constant at anticipated levels. These estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.

PVR Natural Gas Midstream Segment

The following table lists PVR’s commodity derivative agreements and their fair values as of September 30, 2009:

	Average				Weighted Average Price						Fair Value at
	Volume		Swap		Additional						September 30,
	Per Day		Price		Put Option		Put		Call		2009
											(in thousands)
Crude Oil Three-Way Collar	(barrels)						($ per barrel)
Fourth Quarter 2009		1,000				70.00		90.00		119.25	$	1,433

Frac Spread Collar	(MMBtu)						($ per MMBtu)
Fourth Quarter 2009		6,000						9.09		13.94		864

Crude Oil Collar	(barrels)						($ per barrel)
First Quarter 2010 through Fourth Quarter 2010		750						70.00		81.25		228

Crude Oil Collar	(barrels)						($ per barrel)
First Quarter 2010 through Fourth Quarter 2010		1,000						68.00		80.00		(155	)

Natural Gas Purchase Swap	(MMBtu)		($ per MMbtu)
First Quarter 2010 through Fourth Quarter 2010		5,000		5.815								709

Settlements to be received in subsequent period												1,742

Natural gas midstream segment commodity derivatives - net asset											$	4,821

PVR estimates that a $5.00 per barrel increase in the crude oil price would decrease the fair value of PVR’s crude oil collars by $0.8 million. PVR estimates that a $5.00 per barrel decrease in the crude oil price would increase the fair value of PVR’s crude oil collars by $4.8 million. PVR estimates that a $1.00 per MMBtu increase in the natural gas price would increase the fair value of PVR’s natural gas purchase swap by $2.5 million. PVR estimates that a $1.00 per MMBtu decrease in the natural gas price would decrease the fair value of PVR’s natural gas purchase swap by $1.1 million.

In addition, PVR estimates that a $1.00 per MMBtu increase in the natural gas purchase price and a $4.65 per barrel increase in the natural gasoline (a natural gas liquid) sales price would increase the fair value of PVR’s frac spread collar by $2.0 million. PVR estimates that a $1.00 per MMBtu decrease in the natural gas purchase price and a $4.65 per barrel decrease in the natural gasoline sales price would increase the fair value of PVR’s frac spread collar by $2.1 million. These estimated changes exclude potential cash receipts or payments in settling PVR’s derivative positions.

PVR estimates that, excluding the effects of derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, PVR’s natural gas midstream gross margin and operating income for the remainder of 2009 would increase or decrease by $1.3 million. In addition, PVR estimates that for every $5.00 per barrel increase or decrease in the crude oil price, PVR’s natural gas midstream gross margin and operating income for the remainder of 2009 would increase or decrease by $1.2 million. This assumes that natural gas prices, crude oil prices and inlet volumes remain constant at anticipated levels. These estimated changes in PVR’s gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of September 30, 2009, we had no outstanding indebtedness under the Revolver.

As of September 30, 2009, PVR had $628.1 million of outstanding indebtedness under the PVR Revolver, which carries a variable interest rate throughout its term. PVR entered into the PVR Interest Rate Swaps to establish fixed interest rates on a portion of the outstanding borrowings under the PVR Revolver. Until March 2010, the notional amounts of the Interest Rate Swaps total $310.0 million, or 49.4% of PVR outstanding indebtedness under the PVR Revolver as of September 30, 2009, with PVR paying a weighted average fixed rate of 3.54% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From March 2010 to December 2011, the notional amounts of the PVR Interest Rate Swaps total $250.0 million, or 39.8% of the outstanding indebtedness under the PVR Revolver as of September 30, 2009, with PVR paying a weighted average fixed rate of 3.37% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From December 2011 to December 2012, the notional amounts of the PVR Interest Rate Swaps total $100.0 million, or 15.9% of the outstanding indebtedness under the PVR Revolver as of September 30, 2009,with PVR paying a weighted average fixed rate of 2.09% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. The PVR Interest Rate Swaps extend one year past the current maturity of the PVR Revolver. A 1% increase in short-term interest rates on the floating rate debt outstanding under the PVR Revolver (net of amounts fixed through the PVR Interest Rate Swaps) as of September 30, 2009 would cost PVR approximately $3.2 million in additional interest expense per year.

During the first quarter of 2009, both we and PVR discontinued hedge accounting for all of the Interest Rate Swaps and PVR Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for both the Interest Rate Swaps and the PVR Interest Rate Swaps are recognized in earnings currently. Therefore, our results of operations are affected by the volatility of changes in fair value, which fluctuates with changes in interest rates. These fluctuations could be significant. See Note 5, “Derivative Instruments” in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements,” for a further description of our and PVR’s derivatives program.

Item 4 Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of September 30, 2009. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of September 30, 2009, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

No changes were made in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 6

Exhibits

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.

31.1		Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

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

	PENN VIRGINIA CORPORATION

Date: November 6, 2009	By:	/s/ Frank A. Pici
		Frank A. Pici
		Executive Vice President and Chief Financial Officer

Date: November 6, 2009	By:	/s/ Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Good

Ranger Oil (ROCC) 10-Q2009 Q3 Quarterly report

Content analysis