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 June 30, 2009

or

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

For the transition period from              to             

Commission File Number: 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 August 6, 2009, 45,384,732 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

INDEX

		Page
PART I.	Financial Information
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Six Months Ended June 30, 2009 and 2008	1
	Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	2
	Consolidated Statements of Cash Flows for the Three and Six Months Ended June 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	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	54
PART II.	Other Information
Item 1A.	Risk Factors	55
Item 4.	Submission of Matters to a Vote of Security Holders.	56
Item 6.	Exhibits	56

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 June 30						Six Months Ended June 30
	2009			2008			2009			2008
Revenues
Natural gas	$	39,830		$	113,212		$	92,651		$	193,725
Crude oil		11,825			14,463			18,153			23,678
Natural gas liquids (NGLs)		4,336			6,538			7,706			8,406
Natural gas midstream		91,655			184,298			186,861			309,346
Coal royalties		29,997			31,641			60,627			55,603
Other		6,274			10,262			17,079			18,791
Total revenues		183,917			360,414			383,077			609,549
Expenses
Cost of midstream gas purchased		71,933			152,986			151,331			252,683
Operating		22,648			22,214			45,350			43,216
Exploration (see Note 10)		17,472			6,739			38,784			11,419
Taxes other than income		4,930			8,259			11,362			15,654
General and administrative		20,355			19,058			38,841			36,717
Depreciation, depletion and amortization		58,218			44,934			115,291			83,503
Impairments		3,279			—			4,475			—
Loss on sale of assets		1,599			—			1,599			—
Total expenses		200,434			254,190			407,033			443,192
Operating income (loss)		(16,517	)		106,224			(23,956	)		166,357
Other income (expense)
Interest expense		(15,046	)		(11,345	)		(27,548	)		(22,092	)
Derivatives		752			(103,618	)		11,007			(129,519	)
Other		353			975			1,926			3,306
Income (loss) before income taxes and noncontrolling interests		(30,458	)		(7,764	)		(38,571	)		18,052
Income tax benefit		14,620			7,163			19,182			4,569
Net income (loss)		(15,838	)		(601	)		(19,389	)		22,621
Less net income attributable to noncontrolling interests		(6,345	)		(3,948	)		(10,003	)		(23,976	)
Loss attributable to Penn Virginia Corporation	$	(22,183	)	$	(4,549	)	$	(29,392	)	$	(1,355	)
Earnings per share - basic and diluted:
Loss per share attributable to Penn Virginia Corporation
Basic	$	(0.52	)	$	(0.11	)	$	(0.69	)	$	(0.03	)
Diluted	$	(0.52	)	$	(0.11	)	$	(0.69	)	$	(0.03	)
Weighted average shares outstanding, basic		42,798			41,740			42,422			41,642
Weighted average shares outstanding, diluted		42,798			41,740			42,422			41,642

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

1

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands, except share data)

	June 30, 2009			December 31, 2008
Assets
Current assets
Cash and cash equivalents	$	18,337		$	18,338
Accounts receivable, net of allowance for doubtful accounts		105,423			149,241
Derivative assets		42,768			67,569
Inventory		15,136			18,468
Other current assets		7,876			9,902
Total current assets		189,540			263,518
Property and equipment
Oil and gas properties (successful efforts method)		2,207,465			2,107,128
Other property and equipment		1,106,237			1,076,471
		3,313,702			3,183,599
Accumulated depreciation, depletion and amortization		(782,255	)		(671,422	)
Net property and equipment		2,531,447			2,512,177
Equity investments		79,512			78,443
Intangibles, net		88,962			92,672
Derivative assets		2,100			4,070
Other assets		65,378			45,685
Total assets	$	2,956,939		$	2,996,565
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	—		$	7,542
Accounts payable and accrued liabilities		118,108			206,902
Derivative liabilities		16,609			15,534
Deferred taxes		8,317			17,598
Income taxes payable		—			18
Total current liabilities		143,034			247,594
Other liabilities		45,384			45,887
Derivative liabilities		6,074			8,721
Deferred income taxes		254,152			258,037
Long-term debt of PVR		597,100			568,100
Revolving credit facility		70,000			332,000
Senior notes		291,115			—
Convertible notes		203,217			199,896
Shareholders’ equity:
Common stock of $0.01 par value – 64,000,000 shares authorized; 45,384,566 and 41,870,893 shares issued and outstanding at June 30, 2009 and December 31, 2008		265			230
Paid-in capital		668,133			599,855
Retained earnings		409,535			443,646
Deferred compensation obligation		2,147			2,237
Accumulated other comprehensive loss		(4,165	)		(4,182	)
Treasury stock – 99,242 and 85,227 shares common stock, at cost, on June 30, 2009 and December 31, 2008		(2,646	)		(2,683	)
Total Penn Virginia Corporation shareholders’ equity		1,073,269			1,039,103
Noncontrolling interests of subsidiaries		273,594			297,227
Total shareholders’ equity		1,346,863			1,336,330
Total liabilities and shareholders’ equity	$	2,956,939		$	2,996,565

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

2

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Cash flows from operating activities
Net income (loss)	$	(15,838	)	$	(601	)	$	(19,389	)	$	22,621
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		58,218			44,934			115,291			83,503
Impairments		3,279			—			4,475			—
Commodity derivative contracts:
Total derivative losses (gains)		668			105,135			(9,133	)		132,144
Cash settlements of derivatives		17,281			(18,032	)		36,429			(26,985	)
Deferred income taxes		(14,166	)		(3,589	)		(18,800	)		(1,447	)
Dry hole and umproved leasehold expense		9,379			5,919			19,883			9,472
Other		9,888			2,222			13,379			1,256
Changes in operating assets and liabilities		(33,751	)		(17,248	)		(4,158	)		(35,672	)
Net cash provided by operating activities		34,958			118,740			137,977			184,892
Cash flows from investing activities
Acquisitions		(3,120	)		(111,367	)		(6,193	)		(116,107	)
Additions to property, plant and equipment		(56,982	)		(120,512	)		(193,195	)		(229,174	)
Other		5,568			334			5,822			739
Net cash used in investing activities		(54,534	)		(231,545	)		(193,566	)		(344,542	)
Cash flows from financing activities
Dividends paid		(2,370	)		(2,342	)		(4,719	)		(4,686	)
Distributions paid to noncontrolling interest holders		(18,455	)		(14,172	)		(36,910	)		(27,912	)
Repayments of bank borrowings		—			—			(7,542	)		—
Net proceeds from (repayments of) PVR borrowings		2,000			(32,600	)		29,000			(30,600	)
Net proceeds from (repayments of) Company borrowings		(320,000	)		29,000			(262,000	)		83,000
Net proceeds from issuance of senior notes		291,009			—			291,009			—
Net proceeds from issuance of PVR partners’ capital		—			138,015			—			138,015
Net proceeds from issuance of equity		64,835			—			64,835			—
Other		(8,827	)		5,504			(18,085	)		10,786
Net cash provided by financing activities		8,192			123,405			55,588			168,603
Net increase (decrease) in cash and cash equivalents		(11,384	)		10,600			(1	)		8,953
Cash and cash equivalents – beginning of period		29,721			32,880			18,338			34,527
Cash and cash equivalents – end of period	$	18,337		$	43,480		$	18,337		$	43,480
Supplemental disclosure:
Cash paid during the periods for:
Interest	$	14,968		$	10,654		$	25,254		$	17,891
Income taxes	$	684		$	934		$	2,953		$	2,179

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

3

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – unaudited

June 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 77% limited partner interest in Penn Virginia GP Holdings, L.P. (“PVG”), a publicly traded limited partnership formed by us in 2006. As of June 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. 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 six months ended June 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009. In preparing the accompanying consolidated financial statements, we have evaluated subsequent events through August 7, 2009.

3. Noncontrolling interests

We adopted Statement of Financial Accounting Standard (“SFAS”) No. 160, Noncontrolling Interests in Consolidated Financial Statements, effective January 1, 2009. SFAS No. 160 requires that the noncontrolling interests in PVG and PVR be classified as a separate component of shareholders’ equity. Net income attributable to the noncontrolling interests in PVG and PVR is separately presented on our consolidated statements of income. Our consolidated financial statements have been retroactively adjusted to reflect this adoption.

4

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

	Penn Virginia Corporation Shareholders			Noncontrolling Interests			Total Shareholders’ Equity			Comprehensive Income (Loss)
Balance at December 31, 2008	$	1,039,103		$	297,227		$	1,336,330
Dividends paid ($0.05625 per share)		(4,719	)		—			(4,719	)
Distributions to noncontrolling interest holders		—			(36,910	)		(36,910	)
Common Stock offering		64,835			—			64,835
Other changes to shareholders’ equity		3,425			2,412			5,837
Comprehensive Income:
Net income (loss)		(29,392	)		10,003			(19,389	)	$	(19,389	)
Hedging unrealized loss, net of tax		257			(353	)		(96	)		(96	)
Hedging reclassification adjustment, net of tax		(240	)		1,215			975			975
Balance at June 30, 2009	$	1,073,269		$	273,594		$	1,346,863		$	(18,510	)
Balance at December 31, 2007	$	835,793		$	174,420		$	1,010,213
Dividends paid ($0.05625 per share)		(4,686	)		—			(4,686	)
Distributions to noncontrolling interest holders		—			(27,912	)		(27,912	)
Issuance of PVR units		—			138,015			138,015
Recognition of SAB 51 gain		39,659			(39,659	)		—
Other changes to shareholders’ equity		11,619			1,712			13,331
Comprehensive Income:
Net income (loss)		(1,355	)		23,976			22,621		$	22,621
Hedging unrealized loss, net of tax		(262	)		(376	)		(638	)		(638	)
Hedging reclassification adjustment, net of tax		186			1,985			2,171			2,171
Balance at June 30, 2008	$	880,954		$	272,161		$	1,153,115		$	24,154

4. Fair Value Measurements

Effective January 1, 2009, SFAS No. 157, Fair Value Measurements, applies 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, 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.

At June 30, 2009, the carrying values of all of these financial instruments, except our convertible senior subordinated notes due 2012 (“Convertible Notes”) portion of our long-term debt, approximated fair value. The fair value of the Convertible Notes portion of our long-term debt at June 30, 2009 was $192.6 million, which was derived from quoted market prices.

5

The following table summarizes the valuation of certain assets and liabilities by category as of June 30, 2009 (in thousands):

Description	Fair Value Measurements, June 30, 2009			Fair Value Measurement at June 30, 2009, Using
				Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Publicly traded equities	$	4,687		$	4,687		$	—		$	—
Deferred compensation liabilities - noncurrent		(5,176	)		(5,176	)		—			—
Interest rate swap assets - noncurrent		900			—			900			—
Interest rate swap liabilities - current		(8,709	)		—			(8,709	)		—
Interest rate swap liabilities - noncurrent		(4,774	)		—			(4,774	)		—
Commodity derivative assets - current		42,768			—			42,768			—
Commodity derivative assets - noncurrent		1,200			—			1,200			—
Commodity derivative liabilities - current		(7,900	)		—			(7,900	)		—
Commodity derivative liabilities - noncurrent		(1,300	)		—			(1,300	)		—
Total	$	21,696		$	(489	)	$	22,185		$	—

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

5. Derivative Instruments

For commodity derivative instruments, we recognize variances in fair values in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (“AOCI”) within shareholders’ equity.

Commodity Derivatives

Oil and Gas

We determine the fair values of our oil and gas derivative agreements based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil forward prices as of June 30, 2009. We compute discounted cash flows using discount rates adjusted for the credit risk of our counterparties for derivatives in an asset position and our own credit risk if the derivative is in a liability position, in accordance with SFAS No. 157.

6

The following table sets forth our commodity derivative positions as of June 30, 2009:

	Average Volume Per Day	Weighted Average Price					Estimated Fair Value at June 30, 2009
		Additional Put Option	Floor			Ceiling
							(in thousands)
Natural Gas Costless Collars	(MMBtu)		($	per MMBtu	)
Third Quarter 2009	15,000			4.25		5.70	$	658
Fourth Quarter 2009	15,000			4.25		5.70		(5	)
First Quarter 2010	35,000			4.96		7.41		(116	)
Second Quarter 2010	30,000			5.33		8.02		878
Third Quarter 2010	30,000			5.33		8.02		459
Fourth Quarter 2010	50,000			5.65		8.77		479
First Quarter 2011	50,000			5.65		8.77		(860	)
Second Quarter 2011	10,000			6.00		8.00		144
Third Quarter 2011	10,000			6.00		8.00		5
Natural Gas Three-way Collars	(MMBtu)		($	per MMBtu	)
Third Quarter 2009	40,000	6.38		8.75		10.79		8,652
Fourth Quarter 2009	30,000	6.83		9.50		13.60		6,711
First Quarter 2010	30,000	6.83		9.50		13.60		5,910
Natural Gas Swaps	(MMBtu)		($	per MMBtu	)
Third Quarter 2009	40,000			4.91				3,609
Fourth Quarter 2009	40,000			4.91				148
First Quarter 2010	15,000			6.19				464
Second Quarter 2010	30,000			6.17				1,066
Third Quarter 2010	30,000			6.17				331
Crude Oil Three-way Collars	(barrels)		($	per barrel	)
Third Quarter 2009	500	80.00		110.00		179.00		1,317
Fourth Quarter 2009	500	80.00		110.00		179.00		1,186
Crude Oil Swaps	(barrels)		($	per barrel	)
Third Quarter 2009	500			59.25				(540	)
Fourth Quarter 2009	500			59.25				(621	)
Crude Oil Costless Collars	(barrels)		($	per barrel	)
First Quarter 2010	500			60.00		74.75		(206	)
Second Quarter 2010	500			60.00		74.75		(249	)
Third Quarter 2010	500			60.00		74.75		(292	)
Fourth Quarter 2010	500			60.00		74.75		(331	)
Settlements to be received in subsequent period								293
Oil and gas segment commodity derivatives - net asset							$	29,090

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

7

PVR Natural Gas Midstream Segment

PVR determines the fair values of its derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities as of June 30, 2009, using discount rates adjusted for the credit risk of the 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 June 30, 2009 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:

			Weighted Average Price Collars
	Average Volume Per Day		Additional Put Option		Put		Call		Fair Value (in thousands)
Crude Oil Three-Way Collar	(in barrels	)				(per gallon)
Third Quarter 2009 through Fourth Quarter 2009	1,000		$	70.00	$	90.00	$	119.25	$	2,634
Frac Spread Collar	(in MMBtu	)				(per MMBtu)
Third Quarter 2009 through Fourth Quarter 2009	6,000				$	9.09	$	13.94		1,235
Crude Oil Collar	(in barrels	)				(per gallon)
First Quarter 2010 through Fourth Quarter 2010	750				$	70.00	$	81.25		28
Settlements to be received in subsequent period										1,781
Natural gas midstream segment commodity derivatives - net asset									$	5,678

At June 30, 2009, PVR reported a derivative asset related to the PVR natural gas midstream segment of $5.7 million. See the Financial Statement Impact of Derivatives section below for the impact of the PVR natural gas midstream commodity derivatives on our consolidated financial statements.

Interest Rate Swaps

We entered into interest rate swaps (the “Interest Rate Swaps”) with notional amounts of $50.0 million to establish fixed rates on a portion of the outstanding borrowings under our revolving credit facility (the “Revolver”) through December 2010. During the first quarter of 2009, we discontinued cash flow hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps are recognized in the derivative line item of the income statement. At June 30, 2009, a $1.9 million loss, net of income taxes, remained in AOCI related to the discontinued Interest Rate Swap hedges. The $1.9 million loss will be recognized in interest expense through the end of 2010 as the originally forecasted transactions settle.

We reported a (i) net derivative liability of $3.1 million at June 30, 2009 and (ii) loss in AOCI of $1.9 million, net of the income taxes, at June 30, 2009 related to the Interest Rate Swaps. 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 rates on a portion of the outstanding borrowings under its revolving credit facility (the “PVR Revolver”). The following table sets forth PVR’s Interest Rate Swap positions at June 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 cash flow 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 derivative line item of our

8

consolidated statements of income. At June 30, 2009, a $2.5 million loss remained in AOCI related to these discontinued PVR Interest Rate Swap hedges. The $2.5 million loss will be recognized in interest expense through the end of 2011 as the originally forecasted transactions settle.

PVR reported a (i) net derivative liability of $9.5 million at June 30, 2009 and (ii) loss in AOCI of $2.5 million at June 30, 2009 related to the PVR Interest Rate Swaps. 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 consolidated derivative activities, as well as the location of the gains and losses, on our consolidated statements of income for the three and six months ended June 30, 2009 and 2008 (in thousands):

	Location of gain (loss) on derivatives recognized in income	Three Months Ended June 30, 2009			Three Months Ended June 30, 2008
Derivatives de-designated as hedging instruments under SFAS No. 133:
Interest rate contracts (1)	Interest expense	$	(1,420	)	$	(955	)
Decrease in net income resulting from derivatives de-designated as hedging instruments under SFAS No. 133		$	(1,420	)	$	(955	)
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivatives	$	1,633		$	—
Commodity contracts (1)	Natural gas midstream revenues		—			(1,997	)
Commodity contracts (1)	Cost of midstream gas purchased		—			480
Commodity contracts	Derivatives		(881	)		(103,618	)
Increase (decrease) in net income resulting from derivatives not designated as hedging instruments under SFAS No. 133		$	752		$	(105,135	)
Total decrease in net income resulting from derivatives		$	(668	)	$	(106,090	)
Realized and unrealized derivative impact:
Cash received (paid) for commodity and interest rate contract settlements	Derivatives	$	17,281		$	(18,032	)
Cash paid for interest rate contract settlements	Interest expense		—			(955	)
Unrealized derivative gain (2)			(17,949	)		(87,103	)
Total decrease in net income resulting from derivatives		$	(668	)	$	(106,090	)
	Location of gain (loss) on derivatives recognized in income	Six Months Ended June 30, 2009			Six Months Ended June 30, 2008
Derivatives de-designated as hedging instruments under SFAS No. 133:
Interest rate contracts (1)	Interest expense	$	(2,683	)	$	(712	)
Decrease in net income resulting from derivatives de-designated as hedging instruments under SFAS No. 133		$	(2,683	)	$	(712	)
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivatives	$	519		$	—
Commodity contracts (1)	Natural gas midstream revenues		—			(4,248	)
Commodity contracts (1)	Cost of midstream gas purchased		—			1,623
Commodity contracts	Derivatives		10,488			(129,519	)
Increase (decrease) in net income resulting from derivatives not designated as hedging instruments under SFAS No. 133		$	11,007		$	(132,144	)
Total increase (decrease) in net income resulting from derivatives		$	8,324		$	(132,856	)
Realized and unrealized derivative impact:
Cash received (paid) for commodity and interest rate contract settlements	Derivatives	$	36,429		$	(26,985	)
Cash paid for interest rate contract settlements	Interest expense		(808	)		(712	)
Unrealized derivative gain (2)			(27,297	)		(105,159	)
Total increase (decrease) in net income resulting from derivatives		$	8,324		$	(132,856	)

9

(1) This activity represents amounts reclassified out of AOCI and into earnings due to the discontinuance of hedge accounting. At June 30, 2009, a $4.4 million loss remained in AOCI, which consisted of $1.9 million of Interest Rate Swaps and $2.5 million of PVR Interest Rate Swaps.

(2) This activity represents unrealized gains in the natural gas midstream, cost of midstream gas purchased, interest expense and derivatives lines on our consolidated statements of income.

The following table summarizes the fair value of our derivative instruments, as well as the locations of these instruments, on our consolidated balance sheets as of June 30, 2009 and December 31, 2008 (in thousands):

	Balance Sheet Location	Fair values at June 30, 2009				Fair values at December 31, 2008
		Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Derivatives de-designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivative liabilities - current	$	—	$	—	$	—	$	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 under SFAS No. 133:
Interest rate contracts	Derivative assets/liabilities - current	$	—	$	8,709	$	—	$	4,663
Interest rate contracts	Derivative assets/liabilities - noncurrent		900		4,774		—		5,073
Commodity contracts	Derivative assets/liabilities - current		42,768		7,900		67,569		7,694
Commodity contracts	Derivative assets/liabilities - noncurrent		1,200		1,300		4,070		—
Total derivatives not designated as hedging instruments		$	44,868	$	22,683	$	71,639	$	17,430
Total estimated fair value of derivative instruments		$	44,868	$	22,683	$	71,639	$	24,255

See Note 4 – “Fair Value Measurements,” for a description of how the above financial instruments are valued in accordance with SFAS No. 157.

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

	Three Months Ended			Six Months Ended
Source	June 30, 2009
	(in thousands)
Interest on borrowings	$	14,318		$	25,998
Capitalized interest		(690	)		(1,131	)
Interest rate swaps		1,418			2,681
Total interest expense	$	15,046		$	27,548

At June 30, 2009, we reported a commodity derivative asset related to our oil and gas segment of $29.1 million. At June 30, 2009, PVR reported a commodity derivative asset related to the PVR natural gas midstream segment of $5.7 million that is with three counterparties, which are investment grade financial institutions, and is substantially concentrated with one of those counterparties. These concentrations 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 June 30, 2009. No significant uncertainties related to the collectability of amounts owed to us or PVR exist with regard to these counterparties.

The above hedging activity represents cash flow hedges. As of June 30, 2009 neither we nor PVR actively traded derivative instruments or had any fair value hedges. In addition neither we nor PVR owned derivative instruments containing credit risk contingencies as of June 30, 2009.

10

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 our Revolver.

7. Long-Term Debt

In June 2009, the Company sold $300.0 million of unsecured senior notes due on June 15, 2016 (the “Senior Notes”) with an annual interest rate of 10.375% which is payable June 15 and December 15 of each year. 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 approximately $281.6 million, after deducting a discount of $9.0 million and fees and expenses of approximately $9.4 million which is amortizable through June 15, 2016, were used to repay borrowings under our Revolver. We have a call option on the Senior Notes, which we may redeem some or all of the notes at any time on or after June 15, 2013 at the redemption prices set forth in the debt agreement and prior to such date at a “make-whole” redemption price. We may also redeem up to 35% of the notes prior to June 15, 2012 with cash proceeds received from certain equity offerings. If we sell certain assets and do not reinvest the proceeds or repay senior indebtedness or if we experience specific kinds of changes of control, we must offer to repurchase the notes. 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 our 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.

During the second quarter of 2009, the borrowing base of the Revolver was revised from $450.0 million to $367.0 million due to the issuance of our Senior Notes. The financial covenants under the Revolver require us to comply with certain specified financial ratios. The Revolver contains various other covenants that limit our ability to incur additional indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries. As of June 30, 2009, the weighted average interest rate on the Revolver was approximately 2.3%, and we were in compliance with all of our covenants under the Revolver.

In March 2009, PVR increased the size of the PVR Revolver from $700.0 million to $800.0 million. The PVR Revolver is secured with substantially all of PVR’s assets and will mature in December 2011. 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 London Interbank Offered Rate (“LIBOR”) plus an applicable margin ranging from 1.75% to 2.75% if PVR selects the LIBOR-based borrowing option. As of June 30, 2009, the weighted average interest rate on borrowing outstanding under the PVR Revolver was approximately 2.5%, and PVR was in compliance with all of the covenants under the PVR Revolver.

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

	June 30, 2009		December 31, 2008
	(in thousands)
Short-term borrowings	$	—	$	7,542
Revolving credit facility		70,000		332,000
Senior notes, net of discount (1)		291,115		—
Convertible notes, net of discount		203,217		199,896
Total recourse debt of the Company		564,332		539,438
Long-term debt of PVR		597,100		568,100
Total consolidated debt		1,161,432		1,107,538
Less: Short-term borrowings		—		(7,542	)
Total consolidated long-term debt	$	1,161,432	$	1,099,996

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

11

8. Guarantors Subsidiaries

In June 2009, the Company issued our Senior Notes, which 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 regarding financial statements of guarantors and issuers of registered guaranteed securities, according to Rule 3-10 of Regulation S-X of the Securities and Exchange Commission.

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

Balance Sheets

	June 30, 2009
	Penn Virginia Corporation		Guarantor Subsidiaries		Non-guarantor Subsidiaries		Eliminations			Consolidated
	(in thousands)
Assets
Cash and cash equivalents	$	1,319	$	—	$	17,018	$	—		$	18,337
Accounts receivable		22		42,966		62,435		—			105,423
Inventory		—		12,899		2,237		—			15,136
Other current assets		27,321		785		15,779		6,759			50,644
Total current assets		28,662		56,650		97,469		6,759			189,540
Property and equipment, net		7,861		1,659,079		893,059		(28,552	)		2,531,447
Investments in affiliates (equity method)		1,628,055		254,497		—		(1,882,552	)		—
Other assets		29,146		47		233,374		(26,615	)		235,952
Total assets	$	1,693,724	$	1,970,273	$	1,223,902	$	(1,930,960	)	$	2,956,939
Liabilities and shareholders’ equity
Accounts payable and accrued liabilities	$	6,435	$	54,124	$	54,562	$	—		$	115,121
Other current liabilities		5,878		11		15,265		6,759			27,913
Total current liabilities		12,313		54,135		69,827		6,759			143,034
Deferred income taxes		—		280,971		—		(26,819	)		254,152
Long-term debt of PVR		—		—		597,100		—			597,100
Long-term debt of the Company		564,332		—		—		—			564,332
Other long-term liabilities		15,462		7,112		28,884		—			51,458
Penn Virginia Corporation's equity		1,101,617		1,628,055		254,497		(1,910,900	)		1,073,269
Noncontrolling interests in subsidiaries		—		—		273,594		—			273,594
Total liabilities and shareholders’ equity	$	1,693,724	$	1,970,273	$	1,223,902	$	(1,930,960	)	$	2,956,939

Balance Sheets

	December 31, 2008
	Penn Virginia Corporation		Guarantor Subsidiaries		Non-guarantor 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
Penn Virginia Corporation's 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

12

Income Statements

	Three Months Ended June 30, 2009
	Penn Virginia Corporation			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues	$	—		$	55,780		$	149,544		$	(21,407	)	$	183,917
Cost of midstream gas purchased		—			—			92,154			(20,221	)		71,933
Operating		—			14,748			9,084			(1,184	)		22,648
Exploration		—			17,472			—			—			17,472
Taxes other than income		206			3,744			980			—			4,930
General and administrative		5,803			5,713			8,839			—			20,355
Depreciation, depletion and amortization		978			39,917			17,622			(299	)		58,218
Impairments		—			3,279			—			—			3,279
Loss on sale of assets		—			1,599			—			—			1,599
Operating expenses		6,987			86,472			128,679			(21,704	)		200,434
Operating income (loss)		(6,987	)		(30,692	)		20,865			297			(16,517	)
Equity in earnings of subsidiaries		(14,503	)		3,670			—			10,833			—
Interest expense and other		(8,703	)		887			(6,878	)		1			(14,693	)
Derivatives		2,787			—			(2,035	)		—			752
Income (loss) before income taxes and noncontrolling interests		(27,406	)		(26,135	)		11,952			11,131			(30,458	)
Income tax benefit (expense)		4,925			11,632			(1,937	)		—			14,620
Net income (loss)		(22,481	)		(14,503	)		10,015			11,131			(15,838	)
Less net income attributable to noncontrolling interests		—			—			(6,345	)		—			(6,345	)
Net income (loss) attributable to Penn Virginia Corporation	$	(22,481	)	$	(14,503	)	$	3,670		$	11,131		$	(22,183	)

Income Statements

	Three Months Ended June 30, 2008
	Penn Virginia Corporation			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues	$	1		$	134,368		$	276,940		$	(50,895	)	$	360,414
Cost of midstream gas purchased		—			—			202,819			(49,833	)		152,986
Operating		—			14,095			9,181			(1,062	)		22,214
Exploration		—			6,739			—			—			6,739
Taxes other than income		212			7,085			962			—			8,259
General and administrative		6,587			5,163			7,308			—			19,058
Depreciation, depletion and amortization		830			31,568			12,924			(388	)		44,934
Impairments		—			—			—			—			—
Operating expenses		7,629			64,650			233,194			(51,283	)		254,190
Operating income (loss)		(7,628	)		69,718			43,746			388			106,224
Equity in earnings of subsidiaries		48,699			5,523			—			(54,222	)		—
Interest expense and other		(6,560	)		1,062			(4,872	)		—			(10,370	)
Derivatives		(73,676	)		—			(29,942	)		—			(103,618	)
Income (loss) before income taxes and noncontrolling interests		(39,165	)		76,303			8,932			(53,834	)		(7,764	)
Income tax benefit (expense)		34,228			(27,604	)		539			—			7,163
Net income (loss)		(4,937	)		48,699			9,471			(53,834	)		(601	)
Less net income attributable to noncontrolling interests		—			—			(3,948	)		—			(3,948	)
Net income (loss) attributable to Penn Virginia Corporation	$	(4,937	)	$	48,699		$	5,523		$	(53,834	)	$	(4,549	)

13

Income Statements

	Six Months Ended June 30, 2009
	Penn Virginia Corporation			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues	$	—		$	120,344		$	306,311		$	(43,578	)	$	383,077
Cost of midstream gas purchased		—			—			192,774			(41,443	)		151,331
Operating		—			29,511			17,974			(2,135	)		45,350
Exploration		—			38,784			—			—			38,784
Taxes other than income		589			8,570			2,203			—			11,362
General and administrative		11,025			10,837			16,979			—			38,841
Depreciation, depletion and amortization		1,849			79,916			34,131			(605	)		115,291
Impairments		—			4,475			—			—			4,475
Loss on sale of assets		—			1,599			—			—			1,599
Operating expenses		13,463			173,692			264,061			(44,183	)		407,033
Operating income		(13,463	)		(53,348	)		42,250			605			(23,956	)
Equity in earnings of subsidiaries		(24,778	)		7,328			—			17,450			—
Interest expense and other		(15,204	)		887			(11,305	)		—			(25,622	)
Derivatives		20,202			—			(9,195	)		—			11,007
Income (loss) before income taxes and noncontrolling interests		(33,243	)		(45,133	)		21,750			18,055			(38,571	)
Income tax benefit (expense)		3,246			20,355			(4,419	)		—			19,182
Net income (loss)		(29,997	)		(24,778	)		17,331			18,055			(19,389	)
Less net income attributable to noncontrolling interests		—			—			(10,003	)		—			(10,003	)
Net income (loss) attributable to Penn Virginia Corporation	$	(29,997	)	$	(24,778	)	$	7,328		$	18,055		$	(29,392	)

Income Statements

	Six Months Ended June 30, 2008
	Penn Virginia Corporation			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues	$	3		$	226,666		$	433,775		$	(50,895	)	$	609,549
Cost of midstream gas purchased		—			—			302,516			(49,833	)		252,683
Operating		—			28,304			15,974			(1,062	)		43,216
Exploration		—			11,419			—			—			11,419
Taxes other than income		676			12,943			2,035			—			15,654
General and administrative		12,521			9,748			14,448			—			36,717
Depreciation, depletion and amortization		1,649			58,184			24,430			(760	)		83,503
Impairments		—			—			—			—			—
Operating expenses		14,846			120,598			359,403			(51,655	)		443,192
Operating income		(14,843	)		106,068			74,372			760			166,357
Equity in earnings of subsidiaries		79,168			14,164			—			(93,332	)		—
Interest expense and other		(11,005	)		1,062			(8,843	)		—			(18,786	)
Derivatives		(107,353	)		—			(22,166	)		—			(129,519	)
Income (loss) before income taxes and noncontrolling interests		(54,033	)		121,294			43,363			(92,572	)		18,052
Income tax benefit (expense)		51,918			(42,126	)		(5,223	)		—			4,569
Net income (loss)		(2,115	)		79,168			38,140			(92,572	)		22,621
Less net income attributable to noncontrolling interests		—			—			(23,976	)		—			(23,976	)
Net income (loss) attributable to Penn Virginia Corporation	$	(2,115	)	$	79,168		$	14,164		$	(92,572	)	$	(1,355	)

14

Statements of Cash Flows

	Three Months Ended June 30, 2009
	Penn Virginia Corporation			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Net cash provided by (used in) operating activities	$	5,587		$	(9,396	)	$	38,767		$	—		$	34,958
Cash flows provided by (used in) investing activities:
Investment in (distributions from) affiliates		(35,844	)		11,531			—			24,313			—
Additions to property and equipment		(1,048	)		(39,240	)		(15,814	)		—			(56,102	)
Proceeds from the sale of assets and other		—			1,261			307			—			1,568
Cash flows provided by (used in) investing activities		(36,892	)		(26,448	)		(15,507	)		24,313			(54,534	)
Cash flows provided by (used in) financing activities:
Distributions paid to noncontrolling interest holders		—			—			(18,455	)		—			(18,455	)
Net proceeds from (repayments of) borrowings		(320,000	)		—			2,000			—			(318,000	)
Net proceeds from issuance of senior notes		291,009			—			—			—			291,009
Net proceeds from issuance of equity		64,835			—			—			—			64,835
Capital contributions from (distributions to) affiliates		—			35,844			(11,531	)		(24,313	)		—
Other		(11,197	)		—			—			—			(11,197	)
Cash flows provided by (used in) financing activities		24,647			35,844			(27,986	)		(24,313	)		8,192
Net decrease in cash and cash equivalents		(6,658	)		—			(4,726	)		—			(11,384	)
Cash and Cash equivalents - beginning of period		7,977			—			21,744			—			29,721
Cash and Cash equivalents - end of period	$	1,319		$	—		$	17,018		$	—		$	18,337

Statements of Cash Flows

	Three Months Ended June 30, 2008
	Penn Virginia Corporation			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Net cash provided by operating activities	$	20		$	74,166		$	44,554		$	—		$	118,740
Cash flows provided by (used in) investing activities:
Investment in (distributions from) affiliates		(29,000	)		11,047			—			17,953			—
Additions to property and equipment		(256	)		(114,213	)		(117,410	)		—			(231,879	)
Proceeds from the sale of assets and other		—			—			334			—			334
Cash flows provided by (used in) investing activities		(29,256	)		(103,166	)		(117,076	)		17,953			(231,545	)
Cash flows provided by (used in) financing activities:
Distributions paid to noncontrolling interest holders		—			—			(14,172	)		—			(14,172	)
Net proceeds from (repayments of) borrowings		29,000			—			(32,600	)		—			(3,600	)
Net proceeds from equity issuance								138,015			—			138,015
Capital contributions from (distributions to) affiliates		—			29,000			(11,047	)		(17,953	)		—
Other		3,782			—			(620	)		—			3,162
Cash flows provided by (used in) financing activities		32,782			29,000			79,576			(17,953	)		123,405
Net increase in cash and cash equivalents		3,546			—			7,054			—			10,600
Cash and Cash equivalents - beginning of period		13,919			—			18,961			—			32,880
Cash and Cash equivalents - end of period	$	17,465		$	—		$	26,015		$	—		$	43,480

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Statements of Cash Flows

	Six Months Ended June 30, 2009
	Penn Virginia Corporation			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Net cash provided by operating activities	$	16,319		$	49,198		$	72,460		$	—		$	137,977
Cash flows provided by (used in) investing activities:
Investment in (distributions from) affiliates		(86,302	)		23,064			—			63,238			—
Additions to property and equipment		(1,454	)		(159,814	)		(34,120	)		—			(195,388	)
Proceeds from the sale of assets and other		—			1,250			572			—			1,822
Cash flows provided by (used in) investing activities		(87,756	)		(135,500	)		(33,548	)		63,238			(193,566	)
Cash flows provided by (used in) financing activities:
Distributions paid to noncontrolling interest holders		—			—			(36,910	)		—			(36,910	)
Net proceeds from (repayments of) borrowings		(269,542	)		—			29,000			—			(240,542	)
Net proceeds from issuance of senior notes		291,009			—			—			—			291,009
Net proceeds from issuance of equity		64,835			—			—			—			64,835
Capital contributions from (distributions to) affiliates		—			86,302			(23,064	)		(63,238	)		—
Other		(13,546	)		—			(9,258	)		—			(22,804	)
Cash flows provided by (used in) financing activities		72,756			86,302			(40,232	)		(63,238	)		55,588
Net increase (decrease) in cash and cash equivalents		1,319			—			(1,320	)		—			(1	)
Cash and Cash equivalents - beginning of period		—			—			18,338			—			18,338
Cash and Cash equivalents - end of period	$	1,319		$	—		$	17,018		$	—		$	18,337

Statements of Cash Flows

	Six Months Ended June 30, 2008
	Penn Virginia Corporation			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)
Net cash provided by operating activities	$	7,509		$	104,859		$	72,524		$	—		$	184,892
Cash flows provided by (used in) investing activities:
Investment in (distributions from) affiliates		(83,000	)		21,479			—			61,521			—
Additions to property and equipment		(799	)		(209,402	)		(135,080	)		—			(345,281	)
Proceeds from the sale of assets and other		—			64			675			—			739
Cash flows provided by (used in) investing activities		(83,799	)		(187,859	)		(134,405	)		61,521			(344,542	)
Cash flows provided by (used in) financing activities:
Distributions paid to noncontrolling interest holders		—			—			(27,912	)		—			(27,912	)
Net proceeds from (repayments of) borrowings		83,000			—			(30,600	)		—			52,400
Net proceeds from equity issuance		—			—			138,015			—			138,015
Capital contributions from (distributions to) affiliates		—			83,000			(21,479	)		(61,521	)		—
Other		6,720			—			(620	)		—			6,100
Cash flows provided by (used in) financing activities		89,720			83,000			57,404			(61,521	)		168,603
Net increase (decrease) in cash and cash equivalents		13,430			—			(4,477	)		—			8,953
Cash and Cash equivalents - beginning of period		4,035			—			30,492			—			34,527
Cash and Cash equivalents - end of period	$	17,465		$	—		$	26,015		$	—		$	43,480

9. Convertible Notes and Adoption of FSP APB 14-1

We adopted Financial Accounting Standards Board (“FASB”) Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement), (“FSP APB 14-1”) effective January 1, 2009. We accounted for the adoption of this standard as a change in accounting principle in accordance with FSP APB 14-1 and SFAS No. 154, Accounting Changes and Error Corrections. FSP APB 14-1 has therefore been applied retroactively to all periods presented. Substantially all of the decrease is attributable to the adoption of FSP APB 14-1.

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As our Convertible Notes can be settled wholly or partly in cash upon conversion into our common stock, FSP APB 14-1 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 November 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 our Convertible Notes as two separate components resulted in a tax basis difference associated with the liability component that represents a temporary difference for purposes of applying SFAS No. 109, Accounting for Income Taxes. Since 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 FSP APB 14-1 on our consolidated statements of income for the three and six months ended June 30, 2008 (in thousands):

	Three Months Ended June 30, 2008
Consolidated Statement of Income	As originally reported			As adjusted			Effects of change
Interest expense - (1)	$	(10,110	)	$	(11,345	)	$	(1,235	)
Income tax expense - (2)		(6,684	)		(7,163	)		(479	)
Net income (loss) - (3)		155			(601	)		(756	)
Net loss attributable to Penn Virginia Corporation		(3,793	)		(4,549	)		(756	)
Loss per share attributable to Penn Virginia Corporation:
Basic	$	(0.09	)	$	(0.11	)	$	(0.02	)
Diluted	$	(0.09	)	$	(0.11	)	$	(0.02	)
	Six Months Ended June 30, 2008
Consolidated Statement of Income	As originally reported			As adjusted			Effects of change
Interest expense - (1)	$	(19,662	)	$	(22,092	)	$	(2,430	)
Income tax expense - (2)		(3,627	)		(4,569	)		(942	)
Net income - (3)		24,109			22,621			(1,488	)
Net income (loss) attributable to Penn Virginia Corporation		133			(1,355	)		(1,488	)
Loss per share attributable to Penn Virginia Corporation:
Basic	$	—		$	(0.03	)	$	(0.03	)
Diluted	$	—		$	(0.03	)	$	(0.03	)

(1) Amounts represent the additional interest expense that would have been incurred from the debt discount had FSP APB 14-1 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 expense is based on our effective tax rates.

(3) Net income includes noncontrolling interests.

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The following tables reflect the effects of adopting FSP APB 14-1 on our consolidated balance sheet at December 31, 2008 (in thousands):

	December 31, 2008
Consolidated Balance Sheet	As originally reported		As adjusted		Effects of change
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 FSP APB 14-1 been in place when the Convertible Notes were issued.

The following tables reflect the effects of adopting FSP APB 14-1 on our consolidated statements of cash flows for the three and six months ended June 30, 2008 (in thousands):

	Three Months Ended June 30, 2008
Consolidated Statement of Cash Flows	As originally reported			As adjusted			Effects of change
Cash flows from operating activities
Net income (loss)	$	155		$	(601	)	$	(756	)
Deferred income taxes		(3,110	)		(3,589	)		(479	)
Other		987			2,222			1,235
Total impact on the statement of cash flows	$	(1,968	)	$	(1,968	)	$	—

	Six Months Ended June 30, 2008
Consolidated Statement of Cash Flows	As originally reported			As adjusted			Effects of change
Cash flows from operating activities
Net income	$	24,109		$	22,621		$	(1,488	)
Deferred income taxes		(505	)		(1,447	)		(942	)
Other		(1,174	)		1,256			2,430
Total impact on the statement of cash flows	$	22,430		$	22,430		$	—

The net carrying amount of the liability component is reported as long-term debt of the Company in our consolidated balance sheets. The carrying amount of the equity component is reported in paid-in capital in our consolidated balance sheets. The discount amortization is recorded in interest expense in our consolidated statements of income.

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The following table reflects the carrying amounts of the liability and equity components of the Convertible Notes (in thousands):

	June 30, 2009			December 31, 2008
Principal	$	230,000		$	230,000
Unamortized discount		(26,783	)		(30,104	)
Net carrying amount of liability component	$	203,217		$	199,896
Carrying amount of equity component	$	36,850		$	36,850

The discount will be amortized through the end of 2012. The effective interest rate on the liability component for the three and six months ended June 30, 2009 and 2008 was 8.5%. For the three and six months ended June 30, 2009, we recognized $2.6 million and $5.2 million of interest expense related to the contractual coupon rate on the Convertible Notes, and $1.7 million and $3.3 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 and Other

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 six months ended June 30, 2009, we recorded impairment charges related to our oil and gas segment properties and tubular inventories of $4.5 million. Of this $4.5 million, $1.2 million related to market declines in the spot and future oil and gas prices and $3.3 million related to our tubular inventory valuation.

Since the end of 2008, economic situations have impacted our future drilling plans thereby increasing the amount of expected lease expirations and unproved leasehold expenses. We continue to periodically evaluate capitalized costs related to unproved properties as to recoverability based on changes brought about by economic factors and potential shifts in our business strategy. Effective January 1, 2009, we changed our accounting process 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. We recorded additional unproved leasehold amortization in exploration expense on our consolidated statements of income of $12.6 million in the six months ended June 30, 2009. The impact to net income for the six months ended June 30, 2009 was a decrease of $7.7 million, net of income taxes.

11. Earnings per Share

We adopted FASB Staff Position No. Emerging Issues Task Force (“EITF”) 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities” (“EITF 03-6-1”) on January 1, 2009. Under EITF 03-6-1, 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 determined that our unvested restricted shares of common stock and phantom stock awards contain non-forfeitable rights to dividends and, therefore, are participating securities as defined in EITF 03-6-1. We applied EITF 03-6-1 retroactively to all periods presented as required. See Note 9 – “Convertible Notes and Adoption of FSP APB 14-1.”

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The following tables set forth the effect of the retroactive application of EITF 03-6-1 and FSP APB 14-1 as of January 1, 2009 for the three and six months ended June 30, 2009 and 2008:

	Three Months Ended June 30, (in thousands, except per share data)
	2009			2008
				As originally reported			As Adjusted (1)			Effects of changes
Loss attributable to common shareholders	$	(22,183	)	$	(3,793	)	$	(4,549	)	$	(756	)
Portion of subsidiary net income allocated to undistributed share-based compensation awards (net of tax)		(21	)		(18	)		(18	)		—
	$	(22,204	)		(3,811	)	$	(4,567	)	$	(756	)
Weighted average shares, basic		42,798			41,740			41,740			—
Effect of dilutive securities (2)		—			—			—			—
Weighted average shares, diluted		42,798			41,740			41,740			—
Loss per common share, basic	$	(0.52	)	$	(0.09	)	$	(0.11	)	$	(0.02	)
Loss per common share, diluted	$	(0.52	)	$	(0.09	)	$	(0.11	)	$	(0.02	)

(1) Represents the impact of the adoption of FSP APB 14-1 and EITF 03-6-1 as of January 1, 2009.

(2) For the three months ended June 30, 2009 and 2008, 0.1 million and 0.4 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.

	Six Months Ended June 30, (in thousands, except per share data)
	2009			2008
				As originally reported			As Adjusted (1)			Effects of changes
Net income (loss) attributable to Penn Virginia Corporation common shareholders	$	(29,392	)	$	133		$	(1,355	)	$	(1,488	)
Portion of subsidiary net income allocated to undistributed share-based compensation awards (net of tax)		(34	)		(121	)		(121	)		—
	$	(29,426	)	$	12		$	(1,476	)	$	(1,488	)
Weighted average shares, basic		42,422			41,642			41,642			—
Effect of dilutive securities (2)		—			274			—			(274	)
Weighted average shares, diluted		42,422			41,916			41,642			(274	)
Loss per common share, basic	$	(0.69	)	$	0.00		$	(0.03	)	$	(0.03	)
Loss per common share, diluted	$	(0.69	)	$	0.00		$	(0.03	)	$	(0.03	)

(1) Represents the impact of the adoption of FSP APB 14-1 and EITF 03-6-1 as of January 1, 2009.

(2) For the six months ended June 30, 2009 and 2008, 0.1 million and 0.3 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.

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12. Share-Based Compensation

Stock Compensation Plans

We recognized compensation expense related to the granting of common stock and deferred common stock units, the vesting of stock options and restricted stock and phantom stock granted under our stock compensation plans. For the three and six months ended June 30, 2009, we recognized a total of $3.7 million and $7.7 million of compensation expense related to our stock compensation plans. Compensation expense is recorded in the general and administrative expense line on our consolidated statements of income, on a straight-line basis over the respective vesting periods.

Stock Options. In February 2009, we granted 1,147,472 stock options with a weighted average exercise price of $15.06 and a weighted average grant date fair value of $5.57 per option. The options vest over a three-year period, with one-third vesting in each year.

Phantom Stock. In February 2009, we granted 104,449 shares of phantom stock to our employees with a weighted average grant date fair value of $15.06 per share. The phantom stock vests over a three-year period, with one-third vesting in each year. Phantom stock entitles the grantee to receive the common stock upon vesting of the phantom stock, or in the discretion of the Compensation and Benefits Committee of the board of directors, the cash equivalent of the value of the common stock.

Deferred Common Stock Units. In February 2009, we granted 7,966 deferred common stock units to non-employee directors with a weighted average grant date fair value of $19.76 per share. The deferred common stock units vest immediately.

PVR Long-Term Incentive Plan

PVR recognized a total of $1.3 million and $0.7 million of compensation expense related to the granting of common units and deferred common units and the vesting of restricted units and phantom units granted under its long-term incentive plan for the three months ended June 30, 2009 and 2008 and $2.7 million and $1.5 million for the six months ended June 30, 2009 and 2008. During the six months ended June 30, 2009, PVR’s general partner granted 354,792 phantom units with a weighted average grant date fair value of $11.59 per unit to employees of Penn Virginia and its affiliates. The phantom units granted in 2009 vest over a three-year period, with one-third vesting in each year. PVR recognizes compensation expense on a straight-line basis over the vesting period.

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 six months ended June 30, 2009, we recognized charges of $16.6 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 defer additional drilling, which could result in additional exploration expenses of up to approximately $7.2 million for the remainder of 2009.

Legal

We 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.

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Environmental Compliance

As of June 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 region 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 six months ended June 30, 2009, one of PVR’s natural gas midstream segment customers accounted for $56.3 million, or 15%, of our total consolidated revenues. At June 30, 2009, 9% 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—management and leasing of coal properties and subsequent collection of royalties; other land management activities such as selling standing timber; leasing of fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants; collection of oil and gas royalties; and coal transportation, or wheelage, fees.

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

Other items primarily represent corporate functions and elimination of intercompany sales.

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The following tables present a summary of certain financial information relating to our segments as of and for the three and six months ended June 30, 2009 and 2008 (in thousands):

	Revenues						Intersegment revenues (1)
	Three Months Ended June 30,						Three Months Ended June 30,
	2009			2008			2009			2008
Oil and gas	$	55,779		$	134,367		$	(301	)	$	(597	)
Coal and natural resource management		35,144			39,056			(132	)		(198	)
Natural gas midstream		114,275			237,449			21,705			51,096
Other		(21,281	)		(50,458	)		(21,272	)		(50,301	)
Consolidated totals	$	183,917		$	360,414		$	—		$	—
	Operating income						DD&A expense
	Three Months Ended June 30,						Three Months Ended June 30,
	2009			2008			2009			2008
Oil and gas	$	(30,693	)	$	69,718		$	39,917		$	31,568
Coal and natural resource management		20,333			23,983			8,164			7,526
Natural gas midstream		1,060			20,346			9,453			5,393
Other		(7,217	)		(7,823	)		684			447
Consolidated totals		(16,517	)		106,224		$	58,218		$	44,934
Interest expense		(15,046	)		(11,345	)
Other		353			975
Derivatives		752			(103,618	)
Income tax benefit		14,620			7,163
Net income attributable to noncontrolling interests		(6,345	)		(3,948	)
Loss attributable to Penn Virginia Corporation	$	(22,183	)	$	(4,549	)
	Additions to property and equipment
	Three Months Ended June 30,
	2009			2008
Oil and gas	$	39,240		$	114,213
Coal and natural resource management		606			24,641
Natural gas midstream		15,208			92,769
Other		1,048			256
Consolidated totals	$	56,102		$	231,879

(1) Intersegment revenues represent gas gathering and processing transactions between the PVR natural gas midstream segment and the oil and gas segment. Intersegment revenues also represent agent fees paid by the oil and gas segment to the PVR natural gas midstream segment for marketing certain natural gas production and rail car rental fees paid by a corporate affiliate to the PVR coal and natural resource management segment.

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	Revenues						Intersegment revenues (1)
	Six Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Oil and gas	$	120,344		$	226,666		$	(647	)	$	(1,070	)
Coal and natural resource management		73,396			69,350			(330	)		(396	)
Natural gas midstream		232,782			363,969			44,225			51,569
Other		(43,445	)		(50,436	)		(43,248	)		(50,103	)
Consolidated totals	$	383,077		$	609,549		$	—		$	—
	Operating income						DD&A expense
	Six Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Oil and gas	$	(53,348	)	$	106,070		$	79,916		$	58,184
Coal and natural resource management		45,307			41,565			15,558			13,939
Natural gas midstream		(1,987	)		33,998			18,562			10,480
Other		(13,928	)		(15,276	)		1,255			900
Consolidated totals		(23,956	)		166,357		$	115,291		$	83,503
Interest expense		(27,548	)		(22,092	)
Other		1,926			3,306
Derivatives		11,007			(129,519	)
Income tax benefit		19,182			4,569
Net income attributable to noncontrolling interests		(10,003	)		(23,976	)
Loss attributable to Penn Virginia Corporation	$	(29,392	)	$	(1,355	)
	Additions to property and equipment
	Six Months Ended June 30,						Total Assets at
	2009			2008			June 30, 2009			December 31, 2008
Oil and gas	$	163,814		$	209,402		$	1,715,776		$	1,728,375
Coal and natural resource management		1,906			24,689			594,491			600,418
Natural gas midstream		32,214			110,391			595,653			618,402
Other		1,454			799			51,019			49,370
Consolidated totals	$	199,388		$	345,281		$	2,956,939		$	2,996,565

(1) Intersegment revenues represent gas gathering and processing transactions between the PVR natural gas midstream segment and the oil and gas segment. Intersegment revenues also represent agent fees paid by the oil and gas segment to the PVR natural gas midstream segment for marketing certain natural gas production and rail car rental fees paid by a corporate affiliate to the PVR coal and natural resource management segment.

15. New Accounting Standards

In June 2008, the FASB issued Staff Position EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. EITF 03-6-1 provides that unvested share-based payment awards that contain non-forfeitable rights to dividends, or dividends equivalents, whether paid or unpaid, are participating securities and, therefore, are included in the computation of both basic and diluted earnings per share. EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early application was not permitted. We adopted EITF 03-6-1 effective January 1, 2009, and there was no material impact on our financial statements as a result of this adoption.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures About Fair Value of Financial Instruments, which requires disclosures about the fair value of financial instruments whenever we issue financial statements. The disclosures outlined in FSP FAS 107-1 and APB 28-1 are required for interim and annual periods ending after June 15, 2009. Early adoption is permitted for periods ending after March 15, 2009, and we adopted FSP FAS 107-1 and APB 28-1 as of March 31, 2009. Disclosures for earlier periods presented for comparative purposes at initial adoption are not required.

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In April 2009, the FASB issued FSP FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies, which requires us to recognize assets acquired or liabilities assumed in a business combination that arise from a contingency if the acquisition-date fair value of that asset or liability can be determined during the measurement period. If the acquisition-date fair value of an asset acquired or a liability assumed in a business combination that arises from a contingency cannot be determined during the measurement period, we are required to recognize an asset or liability at the time of the acquisition at the amount that would be recognized in accordance with SFAS No. 5, Accounting for Contingencies and FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss—an interpretation of FASB Statement No. 5. FSP FAS 141(R)-1 is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after December 15, 2008. We have had no material acquisitions since our adoption of FSP FAS 141(R)-1. For each acquisition that includes assets acquired or liabilities assumed arising from contingencies, we will determine the fair value of the assets or liabilities and will make the appropriate disclosures.

In April 2009, the FASB issued FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, which provides additional guidance for estimating fair value in accordance with FASB Statement No. 157, Fair Value Measurements, when the volume and activity level for an asset or liability have significantly decreased and when transactions are not orderly (i.e. distressed or forced), since quoted prices may not be determinative of fair value. In such cases, FSP FAS 157-4 requires further analysis of the transactions or quoted prices to determine whether a significant adjustment to the transactions or quoted prices, using a valuation technique other than the quoted price, is necessary to estimate fair value in accordance with Statement No. 157. FSP FAS 157-4 amends Statement No. 157 and requires disclosure in interim and annual periods of the inputs and valuation techniques used, a discussion of changes in valuation techniques and related inputs, if any, and definition of major categories for equity securities and debt securities. We adopted FSP FAS 157-4 effective June 30, 2009, and there was no impact on our financial statements as a result of this adoption. Further, we do not expect the standard to have a material impact on our financial statements unless future fair value measurements are affected by inactive markets.

In May 2009, the FASB issued Statement No. 165, Subsequent Events, which establishes recognition and disclosure requirements for events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Statement No. 165 requires entities to disclose the date through which subsequent events have been evaluated, as well as whether that date is the date the financial statements were issued or the date the financial statements were available to be issued. We adopted Statement No. 165 effective June 30, 2009, and there was no material impact on our financial statements as a result of this adoption.

In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification^TM and the Hierarchy of Generally Accepted Accounting Principles, which replaces SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 168 will become the source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities and is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We do not anticipate any material impact on our financial statements as a result of adopting SFAS No. 168, other than changes in reference from specific accounting standards to accounting standards codification references, and will adopt it effective September 30, 2009.

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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,” “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 77% limited partner interest in Penn Virginia GP Holdings, L.P., or PVG. As of June 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 Penn Virginia from PVG and PVR is only in the form of cash distributions declared and paid to us for our partner interests in those entities. Penn Virginia received cash distributions from PVG and PVR of $23.1 million in the six months ended June 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 June 30, 2009:

We are engaged in three primary business segments as follows:

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

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• PVR Coal and Natural Resource Management—management and leasing of coal properties and subsequent collection of royalties; other land management activities such as selling standing timber; leasing of fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants; collection of oil and gas royalties; and coal transportation, or wheelage, fees.

• 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:

	Oil and Gas			PVR Coal and Natural Resource Management		PVR Natural Gas Midstream			Elimination & Other			Consolidated
	(in thousands)
For the Six Months Ended June 30, 2009:
Revenues	$	120,344		$	73,396	$	232,782		$	(43,445	)	$	383,077
Operating costs and expenses		89,301			12,531		216,207			(30,772	)		287,267
Impairments		4,475			—		—			—			4,475
Depreciation, depletion and amortization		79,916			15,558		18,562			1,255			115,291
Operating income (loss)	$	(53,348	)	$	45,307	$	(1,987	)	$	(13,928	)	$	(23,956	)
For the Six Months Ended June 30, 2008:
Revenues	$	226,666		$	69,350	$	363,969		$	(50,436	)	$	609,549
Operating costs and expenses		62,412			13,846		319,491			(36,060	)		359,689
Impairments		—			—		—			—			—
Depreciation, depletion and amortization		58,184			13,939		10,480			900			83,503
Operating income	$	106,070		$	41,565	$	33,998		$	(15,276	)	$	166,357

Results of Operations

Selected Financial Data—Consolidated

Summary operating results for the three and six months ended June 30, 2009 and 2008 were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)
Revenues	$	183,917		$	360,414		$	383,077		$	609,549
Expenses		200,434			254,190			407,033			443,192
Operating income (loss)		(16,517	)		106,224			(23,956	)		166,357
Other expense		(13,941	)		(113,988	)		(14,615	)		(148,305	)
Income (loss) before income taxes and noncontrolling interests		(30,458	)		(7,764	)		(38,571	)		18,052
Income tax benefit		14,620			7,163			19,182			4,569
Net income (loss)		(15,838	)		(601	)		(19,389	)		22,621
Less net income attributable to noncontrolling interests		(6,345	)		(3,948	)		(10,003	)		(23,976	)
Loss attributable to Penn Virginia Corporation	$	(22,183	)	$	(4,549	)	$	(29,392	)	$	(1,355	)

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 in our oil and gas segment was previously 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.

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Three Months Ended June 30, 2009 Compared With the Three Months Ended June 30, 2008

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

	Three Months Ended June 30,							Three Months Ended June 30,
	2009			2008		% Change		2009			2008
	(in thousands, except as noted)							(per Mcfe) (1)
Financial Highlights
Revenues
Natural gas	$	39,830		$	113,212	(65	)%	$	3.49		$	11.24
Crude oil		11,825			14,463	(18	)%		55.00			121.54
NGL		4,336			6,538	(34	)%		30.97			59.98
Other income		(212	)		154	(238	)%		(0.02	)		0.01
Total revenues		55,779			134,367	(58	)%		4.12			11.74
Expenses
Operating		14,748			14,094	5	%		1.09			1.23
Taxes other than income		3,744			7,085	(47	)%		0.28			0.62
General and administrative		5,713			5,163	11	%		0.42			0.45
Production costs		24,205			26,342	(8	)%		1.79			2.30
Exploration		17,472			6,739	159	%		1.29			0.59
Depreciation, depletion and amortization		39,917			31,568	26	%		2.94			2.76
Impairments		3,279			—	—			0.24			—
Loss on sale of assets		1,599			—	—			0.12			—
Total expenses		86,472			64,649	34	%		6.38			5.65
Operating income (loss)	$	(30,693	)	$	69,718	(144	)%	$	(2.26	)	$	6.09
Production
Natural gas (MMcf)		11,422			10,075	13	%
Crude oil (MBbl)		215			119	81	%
NGL (MBbl)		140			109	28	%
Total production (MMcfe)		13,552			11,443	18	%

(1) Natural gas revenues are shown per Mcf, crude oil and NGL revenues are shown per Bbl and all other amounts are shown per Mcfe.

Operating Statistics

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

	Natural Gas, Crude Oil and NGL Production				Natural Gas, Crude Oil and NGL Revenues
	Three Months Ended June 30,				Three Months Ended June 30,
Region	2009	2008	% Change		2009		2008
	(MMcfe)				(in thousands)
East Texas	3,721	3,468	7	%	$	14,893	$	42,272
Appalachia	2,934	2,905	1	%		10,604		33,012
Mid-Continent	3,455	1,651	109	%		15,876		17,637
Mississippi	2,149	1,820	18	%		8,059		20,937
Gulf Coast	1,293	1,599	(19	)%		6,559		20,355
Total	13,552	11,443	18	%	$	55,991	$	134,213

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Production. Natural gas accounted for approximately 84% and 88% of our total production in the three months ended June 30, 2009 and 2008. Total production increased by 2.2 Bcfe, or 18%, from 11.4 Bcfe in the three months ended June 30, 2008 to 13.6 Bcfe in the same period of 2009. 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 the Mississippi region. Gulf Coast production for the comparable periods decreased due to natural gas production decline.

Revenues. Our revenues consisting of natural gas, crude oil, natural gas liquid, or NGL, and other income decreased by $78.6 million, or 58%, from $134.4 million in the three months ended June 30, 2008 to $55.8 million in the same period of 2009 primarily due to decreased commodity prices, which more than offset the 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 $73.4 million, or 65%, from $113.2 million in the three months ended June 30, 2008 to $39.8 million in the same period of 2009. Of the $73.4 million decrease, $88.0 million was the result of lower realized prices for natural gas, partially offset by $14.6 million resulting from increased natural gas production from development drilling. Our average realized price received for natural gas decreased by $7.75 per Mcf, or 69%, from $11.24 per Mcf in the three months ended June 30, 2008 to $3.49 per Mcf in the same period of 2009.

Crude Oil. Crude oil revenues decreased by $2.7 million, or 18%, from $14.5 million in the three months ended June 30, 2008 to $11.8 million in the same period of 2009. Of the $2.7 million decrease, $14.5 million was the result of lower realized prices for crude oil, partially offset by an increase of $11.8 million resulting from increased crude oil production related to development drilling. Our average realized price received for crude oil decreased by $66.54 per Bbl, or 55%, from $121.54 per Bbl in the three months ended June 30, 2008 to $55.00 per Bbl in the same period of 2009.

NGL. NGL revenues decreased by $2.2 million, or 34%, from $6.5 million in the three months ended June 30, 2008 to $4.3 million in the same period of 2009. Of the $2.2 million decrease, $4.0 million was due to lower realized prices for NGLs, partially offset by a $1.8 million increase in revenues 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 $29.01 per Bbl, or 48%, from $59.98 per Bbl in the three months ended June 30, 2008 to $30.97 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. Settlements of our derivative contracts that do not follow hedge accounting are not reported as revenues in our statements of income.

For the derivatives related to the oil and gas segment, we received $16.2 million in cash settlements in the three months ended June 30, 2009 and paid $8.3 million in cash settlements in the same period of 2008.

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

	Three Months Ended June 30,					Three Months Ended June 30,
	2009		2008			2009		2008
	(in thousands)					(per Mcf)
Natural gas revenues before impact of derivatives	$	39,830	$	113,212		$	3.49	$	11.24
Cash settlements on natural gas derivatives (1)		14,804		(8,016	)		1.29		(0.80	)
Natural gas revenues, adjusted for derivatives	$	54,634	$	105,196		$	4.78	$	10.44
	(in thousands)					(per Bbl)
Crude oil revenues before impact of derivatives	$	11,825	$	14,463		$	55.00	$	121.54
Cash settlements on crude oil derivatives (1)		1,380		(313	)		6.42		(2.63	)
Crude oil revenues, adjusted for derivatives	$	13,205	$	14,150		$	61.42	$	118.91

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

Operating Expenses. Operating expenses increased by $0.6 million, or 5%, from $14.1 million in the three months ended June 30, 2008 to $14.7 million in the same period of 2009 due to increased compressor rentals, gathering fees and processing fees, primarily driven by increased production in several regions. On a Mcfe basis, operating expenses decreased from $1.23 per Mcfe for the three months ended June 30, 2008 to $1.09 per Mcfe in the same period of 2009 due to the production increase.

Taxes Other Than Income. Taxes other than income decreased by $3.4 million, or 47%, from $7.1 million in the three months ended June 30, 2008 to $3.7 million in the same period of 2009 primarily due to decreased severance taxes resulting from significantly lower commodity prices.

General and Administrative Expenses. General and administrative expenses increased by $0.5 million, or 11%, from $5.2 million in the three months ended June 30, 2008 to $5.7 million in the same period of 2009 due to increased staffing and employee benefit costs.

Exploration Expenses. Exploration expenses increased by $10.8 million, or 159%, from $6.7 million in the three months ended June 30, 2008 to $17.5 million in the same period in 2009 primarily due to a significant increase in unproved leasehold expenses and standby rig charges, partially offset by a decrease in dry hole costs as follows:

	Three Months Ended June 30,
	2009		2008
	(in thousands)
Dry hole costs	$	—	$	2,113
Geological and geophysical		341		349
Unproved leasehold		9,844		3,806
Standby rig charges		6,739		—
Other		548		471
Total	$	17,472	$	6,739

Unproved leasehold expenses increased by $6.0 million, or 158%, from $3.8 million in the three months ended June 30, 2008 to $9.8 million in the same period of 2009. This increase was 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.

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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 three months ended June 30, 2009, we recognized standby rig charges of $6.7 million for cancellation fees, minimum daily standby fees and demobilization fees as exploration expense in our consolidated statements of income. We will continue to evaluate economic conditions through the remainder of 2009 to determine whether or not to defer additional drilling. This could result in additional exploration expenses of up to approximately $7.2 million for the remainder of 2009.

Impairments. For the three months ended June 30, 2009, we recorded $3.3 million of impairment charges related to our tubular inventory resulting from a decline in market value.

Depreciation, Depletion and Amortization Expenses. Depreciation, depletion and amortization expenses increased by $8.3 million, or 26%, from $31.6 million in the three months ended June 30, 2008 to $39.9 million in the same period of 2009 primarily due to an 18% increase in equivalent production and higher depletion rates in 2009 when compared to 2008. Our average depletion rate increased by $0.18 per Mcfe, or 7%, from $2.76 per Mcfe in the three months ended June 30, 2008 to $2.94 per Mcfe in the same period of 2009 primarily due to higher cost wells being drilled.

Six Months Ended June 30, 2009 Compared With the Six Months Ended June 30, 2008

The following table sets forth a summary of certain financial and other data for our oil and gas segment and the percentage change for the six months ended June 30, 2009 and 2008:

	Six Months Ended June 30,							Six Months Ended June 30,
	2009			2008		% Change		2009			2008
	(in thousands, except as noted)							(per Mcfe) (1)
Financial Highlights
Revenues
Natural gas	$	92,651		$	193,725	(52	)%	$	3.99		$	9.77
Crude oil		18,153			23,678	(23	)%		47.03			110.64
NGL		7,706			8,406	(8	)%		26.85			58.78
Other income		1,834			857	114	%		0.07			0.04
Total revenues		120,344			226,666	(47	)%		4.41			10.32
Expenses
Operating		29,511			28,303	4	%		1.08			1.29
Taxes other than income		8,570			12,943	(34	)%		0.31			0.59
General and administrative		10,837			9,747	11	%		0.40			0.44
Production costs		48,918			50,993	(4	)%		1.79			2.32
Exploration		38,784			11,419	240	%		1.42			0.52
Depreciation, depletion and amortization		79,916			58,184	37	%		2.94			2.65
Impairments		4,475			—	—			0.16			—
Loss on sale of assets		1,599			—	—			0.06			—
Total expenses		173,692			120,596	44	%		6.37			5.49
Operating income (loss)	$	(53,348	)	$	106,070	(150	)%	$	(1.96	)	$	4.83
Production
Natural gas (MMcf)		23,224			19,823	17	%
Crude oil (MBbl)		386			214	80	%
NGL (MBbl)		287			143	101	%
Total production (MMcfe)		27,262			21,965	24	%

(1) Natural gas revenues are shown per Mcf, crude oil and NGL revenues are shown per Bbl and all other amounts are shown per Mcfe.

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Operating Statistics

The following table summarizes total natural gas, crude oil and NGL production and revenues by region for the six months ended June 30, 2009 and 2008:

	Natural Gas, Crude Oil and NGL Production				Natural Gas, Crude Oil and NGL Revenues
	Six Months Ended June 30,				Six Months Ended June 30,
Region	2009	2008	% Change		2009		2008
	(MMcfe)				(in thousands)
East Texas	7,396	6,223	19	%	$	30,812	$	67,797
Appalachia	5,833	5,745	2	%		25,604		55,974
Mid-Continent	6,311	3,114	103	%		25,821		29,421
Mississippi	4,243	3,625	17	%		18,529		36,219
Gulf Coast	3,479	3,258	7	%		17,744		36,398
Total	27,262	21,965	24	%	$	118,510	$	225,809

Production. Total production increased by 5.3 Bcfe, or 24%, from 22.0 Bcfe in the six months ended June 30, 2008 to 27.3 Bcfe in the same period of 2009 primarily due to increased 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. Gulf Coast production for the comparable periods decreased due to natural gas production decline.

Revenues. Our revenues decreased by $106.4 million, or 47%, from $226.7 million in the six months ended June 30, 2008 to $120.3 million in the same period of 2009 due largely to lower commodity prices, offset by an increase in production. Realized prices are before the impact of our commodity derivatives, which are further discussed under “Effects of Derivatives” below.

Natural Gas. Natural gas revenues decreased by $101.0 million, or 52%, from $193.7 million in the six months ended June 30, 2008 to $92.7 million in the same period of 2009. Of the $101.0 million decrease, $134.2 million was the result of lower realized prices for natural gas, partially offset by $33.2 million resulting from increased natural gas production from development drilling. Our average realized price received for natural gas decreased by $5.78 per Mcf, or 59%, from $9.77 per Mcf in the six months ended June 30, 2008 to $3.99 per Mcf in the same period of 2009.

Crude Oil. Crude oil revenues decreased by $5.5 million, or 23%, from $23.7 million in the six months ended June 30, 2008 to $18.2 million in the same period of 2009. Of the $5.5 million decrease, $24.6 million was the result of lower realized prices for crude oil, partially offset by an increase of $19.1 million resulting from increased crude oil production related to developmental drilling. Our average realized price received for crude oil decreased by $63.61 per Bbl, or 57%, from $110.64 per Bbl in the six months ended June 30, 2008 to $47.03 per Bbl in the same period of 2009.

NGL. NGL revenues decreased by $0.7 million, or 8%, from $8.4 million in the six months ended June 30, 2008 to $7.7 million in the same period of 2009. Of the $0.7 million decrease, $9.1 million was due to lower realized prices for NGLs, partially offset by an $8.4 million increase in revenues 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 $31.93 per Bbl, or 54%, from $58.78 per Bbl in the six months ended June 30, 2008 to $26.85 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. Settlements of our derivative contracts that do not follow hedge accounting are not reported as revenues in our statements of income.

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For the derivatives related to the oil and gas segment, we received $32.5 million in cash settlements in the six months ended June 30, 2009 and paid $7.8 million in cash settlements in the same period of 2008. The following table reconciles natural gas and crude oil revenues to realized prices, as adjusted for derivative activities for the six months ended June 30, 2009 and 2008:

	Six Months Ended June 30,
	2009		2008			2009		2008
	(in thousands)					(per Mcf)
Natural gas revenues before impact of derivatives	$	92,651	$	193,725		$	3.99	$	9.77
Cash settlements on natural gas derivatives (1)		29,766		(7,447	)		1.28		(0.38	)
Natural gas revenues, adjusted for derivatives	$	122,417	$	186,278		$	5.27	$	9.39
	(in thousands)					(per Bbl)
Crude oil revenues before impact of derivatives	$	18,153	$	23,678		$	47.03	$	110.64
Cash settlements on crude oil derivatives (1)		2,730		(313	)		7.07		(1.46	)
Crude oil revenues, adjusted for derivatives	$	20,883	$	23,365		$	54.10	$	109.18

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

Other Income. Other income increased by $0.9 million, or 114%, from $0.9 million in the six months ended June 30, 2008 to $1.8 million in the same period of 2009. The increase was primarily due to a royalty recovery from a lessee in the Appalachian region.

Operating Expenses. Operating expenses increased by $1.2 million, or 4%, from $28.3 million in the six months ended June 30, 2008 to $29.5 million in the same period of 2009 due to increased compressor rentals and increased processing fees primarily driven by increased production in several regions. On a Mcfe basis, operating expenses decreased from $1.29 per Mcfe for the six months ended June 30, 2008 to $1.08 per Mcfe in the same period of 2009 primarily due to the production increase.

Taxes Other than Income. Taxes other than income decreased by $4.3 million, or 34%, from $12.9 million in the six months ended June 30, 2008 to $8.6 million in the same period of 2009 primarily due to lower commodity prices, partially offset by an increase in production.

General and Administrative Expenses. General and administrative expenses increased by $1.1 million, or 11%, from $9.7 million in the six months ended June 30, 2008 to $10.8 million in the same period of 2009 primarily due to increased staffing and employee benefit costs.

Exploration Expenses. Exploration expenses increased by $27.4 million, or 240%, from $11.4 million in the six months ended June 30, 2008 to $38.8 million in the same period of 2009 primarily due to a significant increase in unproved leasehold expenses and standby rig charges, partially offset by a decrease in dry hole costs.

	Six Months Ended June 30,
	2009		2008
	(in thousands)
Dry hole costs	$	1,337	$	2,831
Geological and geophysical		1,079		1,029
Unproved leasehold		18,546		6,640
Standby rig charges		16,603		—
Other		1,219		919
Total	$	38,784	$	11,419

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See the three month discussion above for the explanations of the larger increases in exploration expenses.

Impairments. For the six months ended June 30, 2009 we recorded $4.5 million of impairment charges related to a $1.2 million decline in the value of Mid-Continent and Appalachian producing properties and $3.3 million related to our tubular inventory resulting from a decline in market value.

Depreciation, Depletion and Amortization Expenses. Depreciation, depletion and amortization expenses increased by $21.7 million, or 37%, from $58.2 million in the six months ended June 30, 2008 to $79.9 million in the same period of 2009 primarily due to increase in equivalent production and higher depletion rates. Our average depletion rate increased by $0.29 per Mcfe, or 11%, from $2.65 per Mcfe in the six months ended June 30, 2008 to $2.94 per Mcfe in the same period of 2009 primarily due to 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 PVR’s properties. PVR does not operate any mines. In the six months ended June 30, 2009, PVR’s lessees produced 17.5 million tons of coal from its properties and paid to PVR coal royalties revenues of $60.6 million, for an average royalty per ton of $3.47 ($3.31 per ton net of coal royalties expense). Approximately 82% of PVR’s coal royalties revenues in the six months ended June 30, 2009 were derived from coal mined on its 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.

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Three Months Ended June 30, 2009 Compared With the Three Months Ended June 30, 2008

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

	Three Months Ended June 30,
	2009			2008			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	29,997		$	31,641		(5	)%
Coal services		1,745			1,841		(5	)%
Timber		1,456			1,833		(21	)%
Oil and gas royalty		545			1,556		(65	)%
Other		1,401			2,185		(36	)%
Total revenues		35,144			39,056		(10	)%
Expenses
Coal royalties		1,569			3,397		(54	)%
Other operating		758			505		50	%
Taxes other than income		300			371		(19	)%
General and administrative		4,020			3,274		23	%
Depreciation, depletion and amortization		8,164			7,526		8	%
Total expenses		14,811			15,073		(2	)%
Operating income	$	20,333		$	23,983		(15	)%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,739			8,839		(1	)%
Coal royalties revenue, net of coal royalties expense	$	28,428		$	28,244		1	%
Average coal royalties revenues per ton ($/ton)	$	3.43		$	3.58		(4	)%
Less coal royalties expense per ton ($/ton)		(0.18	)		(0.38	)	(53	)%
Average net coal royalties per ton ($/ton)	$	3.25		$	3.20		2	%

The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the three months ended June 30, 2009 and 2008:

	Coal Production		Coal Royalties Revenues						Coal Royalties Per Ton
	Three Months Ended June 30,		Three Months Ended June 30,						Three Months Ended June 30,
Region	2009	2008	2009			2008			2009			2008
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	4,650	5,144	$	21,192		$	24,450		$	4.56		$	4.75
Northern Appalachia	1,060	1,110		1,949			1,857			1.84			1.67
Illinois Basin	1,145	1,119		2,862			2,312			2.50			2.07
San Juan Basin	1,884	1,466		3,994			3,022			2.12			2.06
Total	8,739	8,839	$	29,997		$	31,641		$	3.43		$	3.58
Less coal royalties expense (1)				(1,569	)		(3,397	)		(0.18	)		(0.38	)
Net coal royalties revenues			$	28,428		$	28,244		$	3.25		$	3.20

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

Production. Coal production in the Northern Appalachian and Illinois Basin regions remained relatively constant from the three months ended June 30, 2008 to the same period of 2009. Coal production in the Central Appalachian region decreased by 0.4 million tons, or 10%, from 5.1 million tons in the three months ended June 30, 2008 to 4.7 million tons in the same period of 2009. While the

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decrease in production primarily resulted from production cut backs due to a depressed coal market, the impact of the decreased coal production on net coal royalties revenue was not significant since a large part of the decrease was from subleased properties in Central Appalachia, from which PVR makes lower net average royalties per ton produced than it makes in other regions where coal production increased or did not decrease. Coal production in the San Juan Basin region increased by 0.4 million tons, or 29%, from 1.5 million tons in the three months ended June 30, 2008 to 1.9 million tons in the same period of 2009. This increase was primarily due to the start up of a new mine in the later part of 2008.

Revenues. Net coal royalties revenues increased slightly from $28.2 million in the three months ended June 30, 2008 to $28.4 million in the same period of 2009, driven by a $0.05 per ton increase in average coal royalties per ton, offset by a slight volume decrease. The average net coal royalty per ton, which represents the average coal royalties revenue per ton net of coal royalties expense, increased slightly from $3.20 per ton in the three months ended June 30, 2008 to $3.25 per ton in the same period of 2009.

Coal services revenues remained relatively constant from the three months ended June 30, 2008 to the same period of 2009. Timber revenues decreased by $0.3 million, or 21%, from $1.8 million in the three months ended June 30, 2008 to $1.5 million in the same period of 2009 primarily due to decreased sales prices resulting from weakened market conditions for furniture-grade wood products. Oil and gas royalties revenues decreased by $1.1 million, or 65%, from $1.6 million in the three months ended June 30, 2008 to $0.5 million in the same period of 2009 primarily due to decreased natural gas prices. Other revenues decreased by $0.8 million, or 36%, from $2.2 million in the three months ended June 30, 2008 to $1.4 million in the same period of 2009 primarily due to decreased wheelage income.

Expenses. Other operating expenses increased by $0.3 million, or 50%, from $0.5 million in the three months ended June 30, 2008 to $0.8 million in the same period of 2009 primarily due to an increase in expenses related to PVR’s timber operations and costs incurred under PVR’s contractual obligations for mine maintenance. Taxes other than income and depreciation, depletion and amortization expenses remained relatively constant from the three months ended June 30, 2008 to the same period of 2009. General and administrative costs increased by $0.7 million, or 23%, from $3.3 million in the three months ended June 30, 2008 to $4.0 million in the same period of 2009 primarily due to PVR’s increased staffing and related employee benefit costs.

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Six Months Ended June 30, 2009 Compared With the Six Months Ended June 30, 2008

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

	Six Months Ended June 30,
	2009			2008			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	60,627		$	55,603		9	%
Coal services		3,633			3,703		(2	)%
Timber		2,773			3,417		(19	)%
Oil and gas royalty		1,248			2,790		(55	)%
Other		5,115			3,837		33	%
Total revenues		73,396			69,350		6	%
Expenses
Coal royalties		2,793			5,909		(53	)%
Other operating		1,641			736		123	%
Taxes other than income		725			742		(2	)%
General and administrative		7,372			6,459		14	%
Depreciation, depletion and amortization		15,558			13,939		12	%
Total expenses		28,089			27,785		1	%
Operating income	$	45,307		$	41,565		9	%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		17,487			16,479		6	%
Coal royalties revenue, net of coal royalties expense	$	57,834		$	49,694		16	%
Average coal royalties revenues per ton ($/ton)	$	3.47		$	3.37		3	%
Less coal royalties expense per ton ($/ton)		(0.16	)		(0.36	)	(56	)%
Average net coal royalties per ton ($/ton)	$	3.31		$	3.01		10	%

The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the six months ended June 30, 2009 and 2008:

	Coal Production		Coal Royalties Revenues						Coal Royalties Per Ton
	Six Months Ended June 30,		Six Months Ended June 30,						Six Months Ended June 30,
Region	2009	2008	2009			2008			2009			2008
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	9,308	9,955	$	42,875		$	43,029		$	4.61		$	4.32
Northern Appalachia	2,117	1,784		3,900			2,991			1.84			1.68
Illinois Basin	2,406	2,152		6,103			4,250			2.54			1.97
San Juan Basin	3,656	2,588		7,749			5,333			2.12			2.06
Total	17,487	16,479	$	60,627		$	55,603		$	3.47		$	3.37
Less coal royalties expense (1)				(2,793	)		(5,909	)		(0.16	)		(0.36	)
Net coal royalties revenues			$	57,834		$	49,694		$	3.31		$	3.01

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

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Production. Coal production in the Central Appalachian region decreased by 0.7 million tons, or 7%, from 10.0 million tons in the six months ended June 30, 2008 to 9.3 million tons in the same period of 2009. This decrease in production primarily resulted from depleted reserve areas and production cut backs due to a depressed coal market. Most of this reduction occurred on subleased properties in Central Appalachia, from which PVR makes lower margins per ton produced than it does in other regions. Coal production in the Northern Appalachian region increased by 0.3 million tons, or 19%, from 1.8 million tons in the six months ended June 30, 2008 to 2.1 million tons in the same period of 2009. This increase was primarily due to increased longwall production from one of PVR’s lessees who encountered adverse mining conditions in the first half of 2008. Coal production in the Illinois Basin region increased by 0.2 million tons, or 12%, from 2.2 million tons in the six months ended June 30, 2008 to 2.4 million tons in the same period of 2009. This increase was primarily due to improved mining conditions encountered by PVR’s lessee in southern Illinois. Coal production in the San Juan region increased by 1.1 million tons, or 41%, from 2.6 million tons in the six months ended June 30, 2008 to 3.7 million tons in the same period of 2009. This increase was primarily due to the start up of a new mine in the later part of 2008.

Revenues. Net coal royalties revenues increased by $8.1 million, or 16%, from $49.7 million in the six months ended June 30, 2008 to $57.8 million in the same period of 2009. This increase was attributable to increases in both production and average coal sales prices. The average net coal royalty per ton, which represents the average coal royalties revenue per ton net of coal royalties expense, increased by $0.30 per ton, or 10%, from $3.01 per ton in the six months ended June 30, 2008 to $3.31 per ton in the same period of 2009 and is attributable to both the increase in the average coal royalties revenue per ton for all regions and decreased royalties expense caused by decreased production from certain subleased properties.

Coal services revenues remained relatively constant from the six months ended June 30, 2008 to the same period of 2009. Timber revenues decreased by $0.6 million, or 19%, from $3.4 million in the six months ended June 30, 2008 to $2.8 million in the same period of 2009 primarily due to decreased sales prices resulting from weakened market conditions for furniture-grade wood products. Oil and gas royalties revenues decreased by $1.6 million, or 55%, from $2.8 million in the six months ended June 30, 2008 to $1.2 million in the same period of 2009 primarily due to decreased natural gas prices. Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fee income, increased by $1.3 million, or 33%, from $3.8 million in the six months ended June 30, 2008 to $5.1 million in the same period of 2009 primarily due to increased wheelage income.

Expenses. Other operating expenses increased by $0.9 million, or 123%, from $0.7 million in the six months ended June 30, 2008 to $1.6 million in the same period of 2009 primarily due an increase in 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 six months ended June 30, 2008 to the same period of 2009. General and administrative costs increased by $0.9 million, or 14%, from $6.5 million in the six months ended June 30, 2008 to $7.4 million in the same period of 2009 primarily due to PVR’s increased staffing and related employee benefit costs. Depreciation, depletion and amortization expenses increased by $1.7 million, or 12%, from $13.9 million in the six months ended June 30, 2008 to $15.6 million in the same period of 2009 primarily due to increased 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 June 30, 2009, PVR owned and operated natural gas midstream assets located in Oklahoma and Texas, including five natural gas processing facilities having 300 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.

For the six months ended June 30, 2009, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 63.6 Bcf, or approximately 352 MMcfd. For the six months ended June 30, 2009, 24% and 15% of the PVR natural gas midstream segment’s revenues and 18% and 12% of PVR’s total consolidated revenues were derived from two of the PVR natural gas midstream segment’s customers, Conoco, Inc. and Tenaska Marketing Ventures.

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Three Months Ended June 30, 2009 Compared With the Three Months Ended June 30, 2008

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

	Three Months Ended June 30,
	2009		2008			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	67,170	$	153,537		(56	)%
Natural gas liquids		38,917		70,507		(45	)%
Condensate		3,945		8,452		(53	)%
Gathering, processing and transportation fees		3,028		2,301		32	%
Total natural gas midstream revenues (1)		113,060		234,797		(52	)%
Equity earnings in equity investment		629		556		13	%
Producer services		586		2,096		(72	)%
Total revenues		114,275		237,449		(52	)%
Expenses
Cost of midstream gas purchased (1)		92,154		202,819		(55	)%
Operating		6,691		4,817		39	%
Taxes other than income		680		605		12	%
General and administrative		4,237		3,469		22	%
Depreciation and amortization		9,453		5,393		75	%
Total operating expenses		113,215		217,103		(48	)%
Operating income	$	1,060	$	20,346		(95	)%
Operating Statistics
System throughput volumes (MMcf)		31,342		23,884		31	%
Daily throughput volumes (MMcfd)		344		262		31	%
Gross margin	$	20,906	$	31,978		(35	)%
Cash impact of derivatives		3,377		(8,186	)	141	%
Gross margin, adjusted for impact of derivatives	$	24,283	$	23,792		2	%
Gross margin ($/Mcf)	$	0.67	$	1.34		(50	)%
Cash impact of derivatives ($/Mcf)		0.10		(0.34	)	129	%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.77	$	1.00		(23	)%

(1) In the three months ended June 30, 2009, PVR recorded $20.0 million of natural gas midstream revenue and $20.0 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. PVR takes title to the gas prior to transporting it to third parties. These transactions do not impact PVR’s gross margin.

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

39

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.

PVR’s 35% gross margin decrease in the three months ended June 30, 2009 as compared to the same period of 2008 was primarily due to decreased 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 MMBtu basis. The gross margin decrease was partially offset by margins earned from increased system throughput volume production. The increased volumes were from regions exposed to both commodity prices and fixed fees.

System throughput volumes increased by 82 MMcfd, or 31%, from 262 MMcfd in the three months ended June 30, 2008 to 344 MMcfd in the same period of 2009. This increase in throughput volumes was 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 Lone Star Gathering L.P., or Lone Star, which was consummated in the third quarter of 2008, also contributed to the volume increase.

During the three months ended June 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 PVR’s 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 $0.5 million, or 2%, from $23.8 million in the three months ended June 30, 2008 to $24.3 million in the same period of 2009. On a per Mcf basis, adjusted for the cash impact of PVR’s commodity derivatives, the gross margin decreased by $0.23 Mcf, or 23%, from $1.00 per Mcf in the three months ended June 30, 2008 to $0.77 in the same period of 2009. These changes were primarily due to the contribution of fixed fee volumes at the Crossroads plant and from the Lone Star acquisition.

Producer Services Revenues. Producer services revenues decreased by $1.5 million, or 72%, from $2.1 million to $0.6 million in the three months ended June 30, 2008 compared to the same period of 2009. This decrease was primarily due to the relative changes in natural gas indices from the purchasing and selling of natural gas as well as a decrease in fees earned from marketing.

Expenses. Operating expenses increased by $1.9 million, or 39%, from $4.8 million in the three months ended June 30, 2008 to $6.7 million in the same period of 2009. This increase in operating expenses was primarily due to increased costs for compressor rentals, related to PVR’s expanding footprint in the Texas and Oklahoma panhandle, expansion projects and recent acquisitions. Taxes other than income remained relatively constant from the three months ended June 30, 2008 to the same period of 2009. General and administrative expenses increased by $0.7 million, or 22%, from $3.5 million in the three months ended June 30, 2008 to $4.2 million in the same period of 2009 primarily due to increased staffing and related employee benefit costs. Depreciation and amortization expenses increased by $4.1 million, or 75%, from $5.4 million in the three months ended June 30, 2008 to $9.5 million in the same period of 2009. The increase in depreciation and amortization expense was primarily due to capital spending on expansion projects, such as the Spearman and Crossroads plants and PVR’s 2008 acquisitions.

40

The following table sets forth a summary of certain financial and other data for PVR’s natural gas midstream segment and the percentage change for the six months ended June 30, 2009 and 2008:

	Six Months Ended June 30,
	2009			2008			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	148,364		$	215,204		(31	)%
Natural gas liquids		69,523			126,704		(45	)%
Condensate		6,848			14,668		(53	)%
Gathering, processing and transportation fees		5,704			3,269		74	%
Total natural gas midstream revenues (1)		230,439			359,845		(36	)%
Equity earnings in equity investment		1,748			556		214	%
Producer services		595			3,568		(83	)%
Total revenues		232,782			363,969		(36	)%
Expenses
Cost of midstream gas purchased (1)		192,774			302,516		(36	)%
Operating		13,474			8,867		52	%
Taxes other than income		1,478			1,306		13	%
General and administrative		8,481			6,802		25	%
Depreciation and amortization		18,562			10,480		77	%
Total operating expenses		234,769			329,971		(29	)%
Operating income (loss)	$	(1,987	)	$	33,998		(106	)%
Operating Statistics
System throughput volumes (MMcf)		63,622			41,171		55	%
Daily throughput volumes (MMcfd)		352			226		56	%
Gross margin	$	37,665		$	57,329		(34	)%
Cash impact of derivatives		7,169			(16,600	)	143	%
Gross margin, adjusted for impact of derivatives	$	44,834		$	40,729		10	%
Gross margin ($/Mcf)	$	0.59		$	1.39		(58	)%
Cash impact of derivatives ($/Mcf)		0.11			(0.40	)	128	%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.70		$	0.99		(29	)%

(1) In the six months ended June 30, 2009, PVR recorded $41.2 million of natural gas midstream revenue and $41.2 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. These transactions do not impact PVR’s gross margin.

Gross Margin. PVR’s 34% gross margin decrease in the six months ended June 30, 2009 as compared to the same period of 2008 was a result of decreased commodity pricing and frac spreads, partially offset by margins earned from increased system throughput volume production.

System throughput volumes increased by 126 MMcfd, or 56%, from 226 MMcfd in the six months ended June 30, 2008 to 352 MMcfd in the same period of 2009. This increase in throughput volumes was 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 Lone Star, which was consummated in the third quarter of 2008, also contributed to the volume increase.

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During the six months ended June 30, 2009, PVR generated a majority of its gross margin from contractual arrangements under which gross margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of PVR’s 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 $4.1 million, or 10%, from $40.7 million in the six months ended June 30, 2008 to $44.8 million in the same period of 2009. On a per Mcf basis, adjusted for the cash impact of PVR’s commodity derivatives, the gross margin decreased by $0.29 Mcf, or 29%, from $0.99 per Mcf in the six months ended June 30, 2008 to $0.70 in the same period of 2009. These changes were primarily due to the contribution of fixed fee volumes at the Crossroads plant and from the Lone Star acquisition.

Equity Earnings in Equity Investment. PVR’s equity earnings increased $1.1 million, or 214%, from $0.6 million in the six months ended June 30, 2008 to $1.7 million in the same period of 2009. This increase was due to PVR’s 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. PVR acquired this member interest in the second quarter of 2008.

Producer Services Revenues. Producer services revenues decreased by $3.0 million, or 83%, from $3.6 million to $0.6 million in the six months ended June 30, 2009 compared to the same period of 2008. This decrease was primarily due to the relative changes in natural gas indices from the purchasing and selling of natural gas as well as a decrease in the fees earned from marketing.

Expenses. Operating expenses increased by $4.6 million, or 52%, from $8.9 million in the six months ended June 30, 2008 to $13.5 million in the same period of 2009. This increase in operating expenses was primarily due to increased costs for compressor rentals related to PVR’s expanding footprint in areas of operation, including the addition of the Spearman and Crossroads plants. Taxes other than income increased by $0.2 million, or 13%, from $1.3 million in the six months ended June 30, 2008 to $1.5 million in the same period of 2009 primarily due to increased property taxes resulting from the construction of the Spearman and Crossroads plants. General and administrative expenses increased by $1.7 million, or 25%, from $6.8 million in the six months ended June 30, 2008 to $8.5 million in the same period of 2009 primarily due to increased staffing and related employee benefit costs. Depreciation and amortization expenses increased by $8.1 million, or 77%, from $10.5 million in the six months ended June 30, 2008 to $18.6 million in the same period of 2009. This increase in depreciation and amortization expense was primarily due to capital spending on expansion projects, such as the Spearman and Crossroads plants and PVR’s 2008 acquisitions.

Eliminations and Other – Operating Income Loss

Eliminations and other primarily represent eliminations of intercompany sales and purchases, which are fully eliminated, our corporate general and administrative expenses and PVG’s general and administrative expenses. The majority of operating losses for the three and six months ended 2009 and 2008 consisted of our general and administrative expenses for corporate functions.

The operating loss decreased by $0.6 million, or 8%, from $7.8 million in the three months ended June 30, 2008 to $7.2 million in the same period of 2009. The operating loss decreased by $1.4 million, or 9%, from $15.3 million in the six months ended June 30, 2008 to $13.9 million in the same period of 2009. Our general and administrative expense for both the three and the six months ended June 30, 2009 decreased from the same periods in 2008 primarily due to higher accounting system conversion costs related in 2008, which was implemented in the last half of 2007.

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Other Income (Expense), Income Taxes and Noncontrolling Interests – Consolidated

The following table sets forth a consolidated summary of other income (expense), income taxes and noncontrolling interests for the three and six months ended June 30, 2009 and 2008 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Operating income (loss)	$	(16,517	)	$	106,224		$	(23,956	)	$	166,357
Other income (expense)
Interest expense		(15,046	)		(11,345	)		(27,548	)		(22,092	)
Derivatives		752			(103,618	)		11,007			(129,519	)
Other		353			975			1,926			3,306
Income tax benefit		14,620			7,163			19,182			4,569
Net income (loss)		(15,838	)		(601	)		(19,389	)		22,621
Less income of noncontrolling interests		(6,345	)		(3,948	)		(10,003	)		(23,976	)
Loss attributable to PennVirginia Corporation	$	(22,183	)	$	(4,549	)	$	(29,392	)	$	(1,355	)

Interest Expense. Our consolidated interest expense increased by $3.7 million, or 33% from $11.3 million in the three months ended June 30, 2008 to $15.0 million in the same period of 2009. Of the $3.7 million increase, approximately $2.7 million related to our interest expense and $1.0 million related to PVR’s interest expense.

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

	Three Months Ended June 30,								Six Months Ended June 30,
Source	2009			2008			% Change		2009			2008			% Change
	(in thousands)								(in thousands)
Penn Virginia borrowings	$	8,723		$	6,151				$	15,535		$	12,496
Penn Virginia capitalized interest		(541	)		(509	)				(905	)		(1,063	)
Penn Virginia interest rate swaps		500			329					938			353
Penn Virginia interest expense		8,682			5,971		45	%		15,568			11,786		32	%
PVR borrowings		5,595			4,935					10,463			10,622
PVR capitalized interest		(149	)		(187	)				(226	)		(675	)
PVR interest rate swaps		918			626					1,743			359
PVR interest expense		6,364			5,374		18	%		11,980			10,306		16	%
Total interest expense	$	15,046		$	11,345		33	%	$	27,548		$	22,092		25	%

Our interest expense for both the three and six months ended June 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 unsecured senior notes, or Senior Notes, in June 2009.

PVR’s interest expense for both the three and six months ended June 30, 2009 increased from the comparative periods in 2008 due to an increase in PVR’s weighted average debt balance. This increase was due to its past capital spending program including acquisitions and an increase in non-cash interest expense related to debt issuance costs, partially offset by an interest rate decrease.

Derivatives. Consolidated derivative gains were $0.8 million in the three months ended June 30, 2009 compared to consolidated derivative losses of $103.6 million in the same period of 2008. These gains and losses were due primarily to volatility in commodity markets of NGL, crude oil and natural gas prices. We determine the fair values of our commodity derivative agreements based on discounted cash flows based on quoted forward prices for these commodities. Cash received for settlements in the three months ended June 30, 2009 was $17.3 million and cash paid for settlements was $18.0 million in the same period of 2008.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Oil and gas unrealized derivative loss	$	(13,220	)	$	(65,347	)	$	(12,117	)	$	(99,593	)
Oil and gas realized gain (loss)		16,184			(8,329	)		32,496			(7,760	)
Interest rate swap unrealized gain		339			—			339			—
Interest rate swap realized loss		(516	)		—			(516	)		—
PVR midstream segment unrealized derivative loss		(7,222	)		(20,239	)		(17,060	)		(2,941	)
PVR midstream segment realized gain (loss)		3,377			(9,703	)		7,169			(19,225	)
PVR interest rate swap unrealized gain		3,574			—			3,416			—
PVR interest rate swap realized loss		(1,764	)		—			(2,720	)		—
Total derivative gains (losses)	$	752		$	(103,618	)	$	11,007		$	(129,519	)

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

Income Taxes - Consolidated

Income Tax Benefit. We recognized an income tax benefit of $14.6 million and $19.2 million for the three and six months ended June 30, 2009, as compared to an income tax benefit of $7.2 million and $4.6 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 six months ended June 30, 2009. We expect to recognize any income tax operating loss tax benefits created in 2009 by amending prior year tax returns and carrying forward any excess operating loss tax benefits.

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 for our partner interests in those entities, which totaled $23.1 million for the six months ended June 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. An important indicator of liquidity for each entity is the availability of borrowing capacity. As discussed in more detail in “Long-Term Debt” below, as of June 30, 2009, we had availability of $296.3 million on our $367.0 million revolving credit facility, or the Revolver, which could be limited by cash flow covenants related to total debt and interest expense coverage. In addition, our borrowing base could be adversely affected by a reduction in our oil and gas reserve base or other sources of debt. PVR had availability of $201.3 million on its recently expanded $800.0 million revolving credit facility, or the PVR Revolver.

With respect to Penn Virginia, we have and believe we will continue to satisfy our working capital requirements, debt service obligations, 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. 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.

PVR generally satisfies its working capital requirements, debt service obligations, distributions and funds its capital expenditures using cash generated from its operations and borrowings under the PVR Revolver. 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, scheduled debt payments under the PVR Revolver and distribution payments for the remainder of 2009.

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Cash Flows

The following presents a comparative cash flow summary for the six months ended June 30, 2009 and 2008 (in thousands):

For the Six Months Ended June 30, 2009:	Oil and Gas & Other			PVG			Consolidated
Net cash provided by operating activities	$	65,442		$	72,535		$	137,977
Net cash flows from investing activities:
Additions to property and equipment		(165,268	)		(34,120	)		(199,388	)
Other		5,250			572			5,822
Net cash used in investing activities		(160,018	)		(33,548	)		(193,566	)
Net cash provided by financing activities:
Distributions received (paid)		23,064			(59,974	)		(36,910	)
Debt borrowings, net		21,467			29,000			50,467
Net proceeds from equity issuance		64,835			—			64,835
Other		(13,546	)		(9,258	)		(22,804	)
Net cash provided by (used in) financing activities		95,820			(40,232	)		55,588
Net increase (decrease) in cash	$	1,244		$	(1,245	)	$	(1	)
For the Six Months Ended June 30, 2008:	Oil and Gas & Other			PVG			Consolidated
Net cash provided by operating activities	$	112,451		$	72,441		$	184,892
Net cash flows from investing activities:
Additions to property and equipment		(210,201	)		(135,080	)		(345,281	)
Other		64			675			739
Net cash used in investing activities		(210,137	)		(134,405	)		(344,542	)
Net cash provided by financing activities:
Distributions received (paid)		21,480			(49,392	)		(27,912	)
Debt borrowings, net		83,000			(30,600	)		52,400
Net proceeds from equity issuance		—			138,015			138,015
Other		6,720			(620	)		6,100
Net cash provided by financing activities		111,200			57,403			168,603
Net increase (decrease) in cash	$	13,514		$	(4,561	)	$	8,953

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

Operating Activities. Cash provided by operating activities for the six months ended June 30, 2009 was approximately $138.0 million, compared to cash provided by operating activities of $184.9 million for the six months ended June 30, 2008. This decrease was primarily due to decreases in commodity prices. For the remainder of 2009, we anticipate making oil and gas segment capital expenditures of approximately $36.5 million to $51.5 million and PVR anticipates making coal and natural resource management and natural gas midstream segment capital expenditures of approximately $61.3 to $66.3 million.

Investing Activities. Cash used in investing activities was approximately $193.6 million for the six months ended June 30, 2009, compared to $344.5 million for the six months ended June 30, 2008. This decrease was due to the decreased planned oil and gas segment capital expenditures during the six months ended June 30, 2009, compared to the same period of the prior year, as a result of weakened economic conditions and lower commodity prices and reduced acquisition activity by PVR.

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Financing Activities. Cash provided by financing activities was approximately $55.6 million and $168.6 million for the six months ended June 30, 2009 and 2008. For the six months ended June 30, 2009, proceeds from the issuance of the Senior Notes, net of discount and debt issuance fees, were $281.6 million and net proceeds from the issuance of 3.5 million shares of Penn Virginia’s common stock was $64.8 million. The majority of proceeds from these issuances were used to repay our borrowings under the Revolver. See Note 7 – “ Long-Term Debt” and Note 6 – “Common Stock Offering” in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements,” for an additional discussion of these issuances. As a result of our ownership in PVG and PVR, we received cash distributions of $23.1 million in the six months ended June 30, 2009 and $21.5 million for the same period of 2008.

Long-Term Debt

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

	June 30, 2009		December 31, 2008
	(in thousands)
Short-term borrowings	$	—	$	7,542
Revolving credit facility		70,000		332,000
Senior notes, net of discount (1)		291,115		—
Convertible notes, net of discount		203,217		199,896
Total recourse debt of the Company	$	564,332	$	539,438
Long-term debt of PVR		597,100		568,100
Total consolidated debt		1,161,432		1,107,538
Less: Short-term borrowings		—		(7,542	)
Total consolidated long-term debt	$	1,161,432	$	1,099,996

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

Revolver. As of June 30, 2009, we had $70.0 million outstanding under the Revolver, which is senior to our senior subordinated convertible notes, or Convertible Notes, and Senior Notes. At our current $367.0 million limit on the Revolver, we could borrow up to $296.3 million at June 30, 2009, which could also be limited by covenants related to debt and interest expense coverage. As of June 30, 2009, we were in compliance with all of the covenants under the Revolver. 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. We have the option to elect interest at (i) the London Interbank Offered Rate, or LIBOR, plus a margin ranging from 2.00% to 3.00%, based on the ratio of our outstanding borrowings to the borrowing base or (ii) the greater of the prime rate or federal funds rate plus a margin of up to 2.125%. At June 30, 2009, the weighted average interest rate on borrowings outstanding under the Revolver was approximately 2.3%. We entered into interest rate swaps, or Interest Rate Swaps, with notional amounts of $50.0 million to establish fixed rates on a portion of the outstanding borrowings under the Revolver through December 2010.

Senior Notes. In June 2009, we sold $300.0 million of Senior Notes due on June 15, 2016 at 97% of par value. The Senior Notes bear interest at an annual rate of 10.375%, which is payable on June 15 and December 15 of each year. The Senior Notes proceeds, net of discount and debt issuance costs, were $281.6 million and were used to repay borrowings under our Revolver. 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 our Revolver to the extent of the collateral securing that indebtedness. The obligations under the Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under our Revolver.

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Convertible Notes, Note Hedges and Warrants. As of June 30, 2009, we had $230.0 million (excluding the discount of $26.8 million) of Convertible Notes outstanding. The Convertible Notes are due on November 15, 2012 and bear interest at a coupon rate of 4.50% per year payable semiannually in arrears on May 15 and November 15 of each year.

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 June 30, 2009, PVR had remaining borrowing capacity of $201.3 million on the PVR Revolver net of outstanding borrowings of $597.1 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. As of June 30, 2009, the weighted average interest rate on borrowings outstanding under the PVR Revolver was approximately 2.5%, and PVR was in compliance with all of its covenants under the PVR Revolver. PVR has entered into interest rate swaps, or PVR Interest Rate Swaps, to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver.

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, sales of non-core assets and the sale of part or all of our equity securities in PVG. However, if the disruptions in the worldwide credit, capital and commodities markets continue into the future, our ability to grow will likely be impaired. We cannot be certain that we will be able to issue our debt or equity securities, sell our non-core assets or sell our interests in PVG 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 $36.5 million to $51.5 million. In addition to these capital expenditures, we could incur up to $7.2 million of additional cost for rig delay and standby charges, which would also 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 its short-term cash requirements for operating expenses and quarterly distributions to its limited partners and PVG, as the owner of PVR’s general partner, will be funded through operating cash flows. PVR also 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 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 $61.3 to $66.3 million. The majority of PVR’s 2009 capital expenditures are expected to be incurred in the natural gas midstream segment, including the July 2009 acquisition of gas processing and residue pipeline facilities in western Oklahoma from Atlas Pipeline Partners, L.P. for approximately $22.6 million, which was funded by borrowings under the PVR Revolver. PVR’s long-term cash requirements for acquisitions and other capital expenditures are expected to be funded by several sources, including cash flows from operating activities, borrowings under the PVR Revolver and the issuances of additional debt and equity securities if available under commercially acceptable terms.

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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.

As of June 30, 2009 and December 31, 2008, PVR’s environmental liabilities included $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.

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 June 30, 2009.

Recent Accounting Pronouncements

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

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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 writedowns 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 business;

• 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;

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• 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 general partner and 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 SEC, 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.

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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.

At June 30, 2009, PVR reported a commodity derivative asset related to the PVR natural gas midstream segment of $5.7 million with three investment grade financial institution counterparties that is substantially concentrated with one of those counterparties. See Note 5 – “Derivative Instruments” in the Notes to the Consolidated Financial Statements in Item 1, “Financial Statements.” 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 nor received collateral with respect to our derivative positions. No significant uncertainties related to the collectability of amounts owed to us or PVR exists with regard to these counterparties.

Price Risk

We produce and sell natural gas, NGLs, crude oil and coal. Our price risk management program permits 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 price risk management activities and our financial results are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil. Such effects can be significant.

In the six months ended June 30, 2009, we reported consolidated net derivative gains of $11.0 million. As we no longer apply hedge accounting for commodity derivatives, including the Interest Rate Swaps and PVR Interest Rate Swaps, we recognize changes in fair value in earnings currently in the derivatives line 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 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 and commodity derivative positions as of June 30, 2009.

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Oil and Gas Segment

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

	Average Volume Per Day		Weighted Average Price				Estimated Fair Value at June 30, 2009
			Additional Put Option	Floor		Ceiling
							(in thousands)
Natural Gas Costless Collars	(MMBtu	)		($ per MMBtu	)
Third Quarter 2009	15,000			4.25		5.70	$	658
Fourth Quarter 2009	15,000			4.25		5.70		(5	)
First Quarter 2010	35,000			4.96		7.41		(116	)
Second Quarter 2010	30,000			5.33		8.02		878
Third Quarter 2010	30,000			5.33		8.02		459
Fourth Quarter 2010	50,000			5.65		8.77		479
First Quarter 2011	50,000			5.65		8.77		(860	)
Second Quarter 2011	10,000			6.00		8.00		144
Third Quarter 2011	10,000			6.00		8.00		5
Natural Gas Three-way Collars	(MMBtu	)		($ per MMBtu	)
Third Quarter 2009	40,000		6.38	8.75		10.79		8,652
Fourth Quarter 2009	30,000		6.83	9.50		13.60		6,711
First Quarter 2010	30,000		6.83	9.50		13.60		5,910
Natural Gas Swaps	(MMBtu	)		($ per MMBtu	)
Third Quarter 2009	40,000			4.91				3,609
Fourth Quarter 2009	40,000			4.91				148
First Quarter 2010	15,000			6.19				464
Second Quarter 2010	30,000			6.17				1,066
Third Quarter 2010	30,000			6.17				331
Crude Oil Three-way Collars	(barrels	)		($ per barrel	)
Third Quarter 2009	500		80.00	110.00		179.00		1,317
Fourth Quarter 2009	500		80.00	110.00		179.00		1,186
Crude Oil Swaps	(barrels	)		($ per barrel	)
Third Quarter 2009	500			59.25				(540	)
Fourth Quarter 2009	500			59.25				(621	)
Crude Oil Costless Collars	(barrels	)		($ per barrel	)
First Quarter 2010	500			60.00		74.75		(206	)
Second Quarter 2010	500			60.00		74.75		(249	)
Third Quarter 2010	500			60.00		74.75		(292	)
Fourth Quarter 2010	500			60.00		74.75		(331	)
Settlements to be received in subsequent period								293
Oil and gas segment commodity derivatives - net asset							$	29,090

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 decrease or increase by approximately $17.4 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 approximately $1.8 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at anticipated levels. These estimated changes in gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

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We estimate that a $1.00 per MMBtu increase in the natural gas purchase price would decrease the fair value of the natural gas derivatives by $28.3 million. We estimate that a $1.00 MMBtu decrease in the natural gas purchase price would increase the fair value of the natural gas derivatives by $27.9 million. We estimate that for a $5.00 per barrel increase in the crude oil price, the fair value of the crude oil derivatives would decrease by $1.4 million. We estimate that a $5.00 per barrel decrease in the crude oil price, the fair value of the crude oil derivatives would decrease by $1.2 million.

PVR Natural Gas Midstream Segment

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

	Average Volume Per Day		Weighted Average Price	Weighted Average Price Collars
				Additional Put Option		Put		Call		Fair Value (in thousands)
Crude Oil Three-Way Collar	(in barrels	)					(per gallon)
Third Quarter 2009 through Fourth Quarter 2009	1,000			$	70.00	$	90.00	$	119.25	$	2,634
Frac Spread Collar	(in MMBtu	)					(per MMBtu)
Third Quarter 2009 through Fourth Quarter 2009	6,000					$	9.09	$	13.94		1,235
Crude Oil Collar	(in barrels	)					(per gallon)
First Quarter 2010 through Fourth Quarter 2010	750					$	70.00	$	81.25		28
Settlements to be received in subsequent period											1,781
Natural gas midstream segment commodity derivatives - net asset										$	5,678

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 decrease or increase by approximately $2.5 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 second half of 2009 would increase or decrease by approximately $2.4 million. This assumes that natural gas prices, crude oil prices and inlet volumes remain constant at anticipated levels. These estimated changes in gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

PVR estimates that a $5.00 per barrel increase in the crude oil price would decrease the fair value of the crude oil collars by $1.6 million. PVR estimates that a $5.00 per barrel decrease in the crude oil price would increase the fair value of the crude oil collars by $1.5 million. In addition, PVR estimates that a $1.00 per MMBtu increase or decrease in the natural gas purchase price and a $4.65 per barrel (the estimated equivalent of $5.00 per barrel of crude oil) increase or decrease in the NGL sales price would affect the fair value of the frac spread collar by $0.1 million. These estimated changes exclude potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of June 30, 2009, we had $70.0 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. A 1% increase in short-term interest rates on the floating rate debt outstanding under the Revolver (net of amounts fixed through hedging transactions) as of June 30, 2009 would cost us approximately $0.2 million in additional interest expense.

As of June 30, 2009, PVR had $597.1 million of outstanding indebtedness under the PVR Revolver, which carries a variable interest rate throughout its term. A 1% increase in short-term interest rates on the floating rate debt outstanding under the PVR Revolver (net of amounts fixed through hedging transactions) as of June 30, 2009 would cost PVR approximately $2.9 million in additional interest expense.

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In the first quarter of 2009, both we and PVR discontinued hedge accounting for all of the Interest Rate Swaps and PVR Interest Rate Swaps and accordingly, subsequent fair value gains and losses for both are recognized in earnings currently. 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 June 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 June 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 that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1A Risk Factors

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation,” or ACESA. The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or GHGs, in the United States. GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas.

The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law. President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills currently pending before the U.S. Senate and U.S. House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

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Item 4 Submission of Matters to a Vote of Security Holders

Our Annual Meeting of Shareholders was held on May 6, 2009. At such meeting, the following matters were voted upon by the shareholders, receiving the number of affirmative, negative and withheld votes, as well as abstentions and broker non-votes, set forth below for each matter:

(1) The vote of the common shareholders for the election of eight directors, each to serve until the next Annual Meeting of Shareholders, and until their respective successors are duly elected and qualified:

NAME	FOR	WITHHOLD
Edward B. Cloues, II	37,428,996	2,185,355
A. James Dearlove	38,904,043	710,308
Robert Garrett	38,873,272	741,079
Keith D. Horton	38,907,066	707,285
Marsha Reines Perelman	37,444,572	2,169,779
Philippe van Marcke de Lummen	39,324,024	290,327
William H. Shea, Jr.	39,308,768	305,583
Gary K. Wright	37,266,311	2,348,040

(2) The approval by the common shareholders of the amendment and restatement of the Penn Virginia Corporation Fifth Amended and Restated 1999 Employee Stock Incentive Plan:

FOR	AGAINST	ABSTAIN	BROKER NON-VOTES
27,442,209	9,165,000	109,710	2,897,432

Item 6 Exhibits

10.1	Amendment Number 1 to the Penn Virginia Corporation Sixth Amended and Restated 1999 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on April 28, 2009).
10.2	Thirteenth Amendment to Amended and Restated Credit Agreement dated as of June 2, 2009 among Penn Virginia Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on June 3, 2009).
10.3	Underwriting Agreement, dated May 18, 2009, among Penn Virginia Corporation and the underwriters listed therein (incorporated by reference to Exhibit 1.1 to Registrant’s Current Report on Form 8-K filed on May 20, 2009).
10.4	Underwriting Agreement, dated June 10, 2009, among Penn Virginia Corporation, the subsidiary guarantors named therein and the representative of the several underwriters named therein relating to the 10.375% Senior Notes due 2016 (incorporated by reference to Exhibit 1.1 to Registrant’s Current Report on Form 8-K filed on June 12, 2009).
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.

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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:	August 7, 2009	By:	/s/ Frank A. Pici
			Frank A. Pici
			Executive Vice President and Chief Financial Officer
Date:	August 7, 2009	By:	/s/ Forrest W. McNair
			Forrest W. McNair
			Vice President and Controller