Ranger Oil (ROCC) 10-Q 2009 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 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 May 7, 2009, 41,883,830 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 Months Ended March 31, 2009 and 2008	1
	Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008	2
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2009 and 2008	3
	Notes to Consolidated Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	55
PART II.	Other Information
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 March 31,
	2009			2008
Revenues
Natural gas	$	52,821		$	80,513
Crude oil		6,328			9,215
Natural gas liquids (NGLs)		3,370			1,868
Natural gas midstream		95,206			125,048
Coal royalties		30,630			23,962
Other		10,805			8,529
Total revenues		199,160			249,135
Expenses
Cost of midstream gas purchased		79,398			99,697
Operating		22,702			21,002
Exploration (see Note 13)		21,312			4,680
Taxes other than income		6,432			7,395
General and administrative		18,486			17,659
Impairments		1,196			—
Depreciation, depletion and amortization		57,073			38,569
Total expenses		206,599			189,002
Operating income (loss)		(7,439	)		60,133
Other income (expense)
Interest expense		(12,502	)		(10,747	)
Other		1,573			2,331
Derivatives		10,255			(25,901	)
Income (loss) before income taxes and noncontrolling interests		(8,113	)		25,816
Income tax benefit (expense)		4,562			(2,594	)
Net income (loss)		(3,551	)		23,222
Less net income attributable to noncontrolling interests		(3,658	)		(20,028	)
Net income (loss) attributable to Penn Virginia Corporation	$	(7,209	)	$	3,194
Earnings per share – basic and diluted (see Note 10):
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, basic	$	(0.17	)	$	0.08
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, diluted	$	(0.17	)	$	0.07
Weighted average shares outstanding, basic		41,922			41,558
Weighted average shares outstanding, diluted		41,922			41,803

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

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS — unaudited

(in thousands, except share data)

	March 31, 2009			December 31, 2008
Assets
Current assets
Cash and cash equivalents	$	29,721		$	18,338
Accounts receivable, net of allowance for doubtful accounts		110,443			149,241
Derivative assets		62,727			67,569
Inventory		17,993			18,468
Other current assets		10,980			9,902
Total current assets		231,864			263,518
Property and equipment
Oil and gas properties (successful efforts method)		2,176,467			2,107,128
Other property and equipment		1,092,922			1,076,471
		3,269,389			3,183,599
Accumulated depreciation, depletion and amortization		(726,585	)		(671,422	)
Net property and equipment		2,542,804			2,512,177
Equity investments		80,003			78,443
Intangibles, net		90,817			92,672
Derivative assets		1,276			4,070
Other assets		53,734			45,685
Total assets	$	3,000,498		$	2,996,565
Liabilities and Shareholders’ Equity
Current liabilities
Short-term borrowings	$	—		$	7,542
Accounts payable and accrued liabilities		157,307			206,902
Derivative liabilities		17,741			15,534
Deferred taxes		15,292			17,598
Income taxes payable		—			18
Total current liabilities		190,340			247,594
Other liabilities		45,011			45,887
Derivative liabilities		7,550			8,721
Deferred income taxes		255,964			258,037
Convertible Notes (see Note 7)		201,545			199,896
Revolving Credit Facility		390,000			332,000
Long-term debt of PVR		595,100			568,100
Shareholders’ equity:
Penn Virginia Corporation Shareholders’ Equity:
Preferred stock of $100 par value – 100,000 shares authorized; none issued		—			—
Common stock of $0.01 par value – 64,000,000 shares authorized; 41,883,695 and 41,870,893 shares issued and outstanding at March 31, 2009 and December 31, 2008		230			230
Paid-in capital		599,984			599,855
Retained earnings		434,087			443,646
Deferred compensation obligation		2,012			2,237
Accumulated other comprehensive loss		(3,931	)		(4,182	)
Treasury stock – 81,257 and 95,378 shares common stock, at cost, on March 31, 2009 and December 31, 2008		(2,459	)		(2,683	)
Total Penn Virginia Corporation shareholders’ equity		1,029,923			1,039,103
Noncontrolling interests of subsidiaries (see Note 4)		285,065			297,227
Total shareholders’ equity		1,314,988			1,336,330
Total liabilities and shareholders’ equity	$	3,000,498		$	2,996,565

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

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS — unaudited

(in thousands)

	Three Months Ended March 31,
	2009			2008
Cash flows from operating activities
Net income (loss)	$	(3,551	)	$	23,222
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		57,073			38,569
Impairments		1,196			—
Derivative contracts:
Total derivative losses (gains)		(9,801	)		27,009
Cash received (paid) to settle derivatives		19,148			(8,953	)
Deferred income taxes		(4,634	)		2,142
Dry hole and unproved leasehold expense		10,504			3,553
Non-cash interest expense		2,711			1,952
Other		780			(2,918	)
Changes in operating assets and liabilities		29,593			(18,424	)
Net cash provided by operating activities		103,019			66,152
Cash flows from investing activities
Acquisitions		(3,073	)		(4,740	)
Additions to property and equipment		(136,213	)		(108,662	)
Other		254			405
Net cash used in investing activities		(139,032	)		(112,997	)
Cash flows from financing activities
Dividends paid		(2,349	)		(2,344	)
Distributions paid to noncontrolling interests holders		(18,455	)		(13,740	)
Repayments of bank borrowings		(7,542	)		—
Proceeds from Company borrowings		58,000			54,000
Proceeds from borrowings of PVR		27,000			25,000
Repayments of borrowings of PVR		—			(23,000	)
Other		(9,258	)		5,282
Net cash provided by financing activities		47,396			45,198
Net increase (decrease) in cash and cash equivalents		11,383			(1,647	)
Cash and cash equivalents – beginning of period		18,338			34,527
Cash and cash equivalents – end of period	$	29,721		$	32,880
Supplemental disclosures:
Cash paid during the periods for:
Interest (net of amounts capitalized)	$	10,286		$	7,237
Income taxes	$	2,269		$	1,245

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

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — unaudited

March 31, 2009

1. Nature of Operations

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 interests in Penn Virginia GP Holdings, L.P. (“PVG”), a publicly traded limited partnership formed by us in 2006. As of March 31, 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 (“IDRs”).

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. Because PVG controls the general partner of PVR, the financial results of PVR are included in PVG’s consolidated financial statements. Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. However, PVG and PVR function with capital structures that are independent of each other and us, with each having publicly traded common units and PVR having its own debt instruments. PVG does not currently have any debt instruments.

2. Penn Virginia Resource Partners, L.P. and Penn Virginia GP Holdings, L.P.

PVR is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. PVG derives its cash flow solely from cash distributions received from PVR. PVG’s general partner is an indirect wholly owned subsidiary of ours.

PVR’s coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. PVR’s coal reserves are primarily located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. 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.

PVR’s natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. PVR owns and operates natural gas midstream assets located in Oklahoma and Texas. PVR’s natural gas midstream business derives 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 (“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.

3. Summary of Significant Accounting Policies

Our accounting policies are consistent with those described in our Annual Report on Form 10-K for the year ended December 31, 2008. Please refer to such Form 10-K for a further discussion of those policies.

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

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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 months ended March 31, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009.

New Accounting Standards

In April 2009, the Financial Accounting Standards Board (“FASB”) issued FSP FAS 107-1 and APB 28-1,Interim Disclosures About Fair Value of Financial Instruments (“FSP FAS 107-1 and APB 28-1”). This FSP 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 have elected to adopt this FSP for the three months ended March 31, 2009. This FSP does not require disclosures for earlier periods presented for comparative purposes at initial adoption. See Note 5, “Fair Value Measurements” for the disclosure required under FSP FAS 107-1 and APB 28-1.

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 (“FSP FAS 141(R)-1”). This FSP 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, an asset or liability shall be recognized at the acquisition at the amount that would be recognized in accordance with Statement of Financial Accounting Standards (“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. Certain disclosures are also required under this FSP. 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 this FSP. 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.

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4. Noncontrolling Interests

We adopted SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements, effective January 1, 2009. SFAS No. 160 requires that 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 the consolidated statements of income, applied retrospectively for all periods presented.

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)
	(in thousands)
Balance at December 31, 2008	$	1,039,103		$	297,227		$	1,336,330
Dividends paid ($0.05625 per share)		(2,349	)		—			(2,349	)
Distributions to noncontrolling interest holders		—			(18,455	)		(18,455	)
Other changes to shareholders’ equity		127			2,412			2,539
Comprehensive Income:
Net income (loss)		(7,209	)		3,658			(3,551	)		(3,551	)
Hedging unrealized loss, net of tax of ($205)		(28	)		(353	)		(381	)		(381	)
Hedging reclassification adjustment, net of tax of $442		244			576			820			820
Other, net of tax of $19		35			—			35			35
Balance at March 31, 2009	$	1,029,923		$	285,065		$	1,314,988		$	(3,077	)
Balance at December 31, 2007	$	835,793		$	174,420		$	1,010,213
Dividends paid ($0.05625 per share)		(2,344	)		—			(2,344	)
Distributions to noncontrolling interest holders		—			(13,740	)		(13,740	)
Other changes to shareholders’ equity		3,510			1,703			5,213
Comprehensive Income:
Net income		3,194			20,028			23,222			23,222
Hedging unrealized loss, net of tax of ($2,343)		(1,060	)		(3,291	)		(4,351	)		(4,351	)
Hedging reclassification adjustment, net of tax of $303		24			538			562			562
Other, net of tax of $22		41			—			41			41
Balance at March 31, 2008	$	839,158		$	179,658		$	1,018,816		$	19,474

5. Fair Value Measurements

We adopted SFAS No. 157,Fair Value Measurements, effective January 1, 2008, for financial assets and liabilities measured on a recurring basis. FASB Staff Position FAS 157-2,Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”), delayed the application of SFAS No. 157 for nonfinancial assets and liabilities to fiscal years and interim periods beginning after November 15, 2008. Prior to the adoption of FSP FAS 157-2, we only applied fair value measurements to our financial assets and liabilities. Effective January 1, 2009, SFAS No. 157 now applies to both financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis.

Our financial instruments consist of cash and cash equivalents, receivables, accounts payable, derivative instruments and long-term debt. At March 31, 2009, the carrying values of all of these financial instruments, except the convertible senior subordinated notes (“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 March 31, 2009 was $137.4 million, which was derived from quoted market prices.

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SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 requires fair value measurements to be classified and disclosed in one of the following three categories:

• Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value.

• Level 2: Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

• Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).

The following table summarizes the valuation of certain assets and liabilities by the above SFAS No. 157 categories as of March 31, 2009 (in thousands):

				Fair Value Measurement at March 31, 2009, Using
Description	Fair Value Measurements, March 31, 2009			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Marketable securities – noncurrent asset	$	4,559		$	4,559		$	—		$	—
Deferred compensation – noncurrent liability		(4,769	)		(4,769	)		—			—
Oil and gas properties – current		4,394						—			4,394
Interest rate swap liability – current		(8,947	)		—			(8,947	)		—
Interest rate swap liability – noncurrent		(7,550	)		—			(7,550	)		—
Commodity derivative assets – current		62,727			—			62,727			—
Commodity derivative assets – noncurrent		1,276			—			1,276			—
Commodity derivative liability – current		8,794			—			8,794			—
Total	$	60,484		$	(210	)	$	56,300		$	4,394

See Note 6 – “Derivative Instruments,” for the effects of derivative instruments on our consolidated financial statements.

We use the following methods and assumptions to estimate the fair values in the above table:

• Marketable securities: Our marketable securities consist of various publicly traded equities. The fair values are based on quoted market prices, which are Level 1 inputs.

• Deferred compensation: The fair values for deferred compensation are based on quoted market prices of the underlying securities, which are Level 1 inputs.

• Oil and gas segment properties: In accordance with the provisions of SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, oil and gas properties of $5.6 million were written down to their fair value of $4.4 million, resulting in impairment. See Note 9, “Impairments and Unproved Leasehold Expense” for a further description of the impairment charge. The fair value of the oil and gas properties is estimated to be the present value of future net cash flows from the underlying reserves, using a forward strip commodity price discounted at a rate commensurate with the risk and remaining life of the asset. This is a Level 3 input.

• Commodity derivative instruments: Both our oil and gas commodity derivatives and PVR’s natural gas midstream segment commodity derivatives utilize collar derivative contracts, commodity price swaps and three-way collar derivative contracts. PVR also utilizes a combination of collar derivative contracts and commodity price swaps to hedge against the variability in its frac spread. 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 March 31, 2009. PVR determines the fair values of its commodity derivative

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agreements based on discounted cash flows based on quoted forward prices for the respective commodities, and use discount rates adjusted for the credit risk of the counterparties if the derivative is in an asset position and our own credit risk for derivatives in a liability position. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a Level 2 input. See Note 6 – “Derivative Instruments.”

• Interest rate swaps: We have entered into interest rate swaps (the “Interest Rate Swaps”) to establish fixed rates on a portion of the outstanding borrowings under our revolving credit facility (the “Revolver”). PVR has entered into interest rate swaps (the “PVR Interest Rate Swaps”) to establish fixed rates on a portion of the outstanding borrowings under PVR’s revolving credit facility (the “PVR Revolver”). We use an income approach using valuation techniques that connect future cash flows to a single discounted value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate, and use discount rates adjusted for the credit risk of the counterparties if the derivative is in an asset position and our own credit risk for derivatives in a liability position. Each of these is a Level 2 input. See Note 6 – “Derivative Instruments.”

6. Derivative Instruments

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

Oil and Gas Segment Commodity Derivatives

We utilize costless collars, price swaps and three-way collar derivative contracts to hedge against the variability in cash flows associated with forecasted sales of our future oil and gas production. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues or cost savings from favorable price movements.

The counterparty to a costless collar contract is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. The counterparty to a swap contract is required to make a payment to us if the settlement price for any settlement period is less than the swap price for such contract, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price for such contract.

A three-way collar contract consists of a collar contract plus a put option contract sold by us with a price below the floor price of the collar. The counterparty to a collar contract is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. The additional put option sold by us requires us to make a payment to the counterparty if the settlement price for any settlement period is below the put option price. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the collar contract and the additional put option price if the settlement price is equal to or less than the additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a collar contract only. If market prices are below the additional put option, we would be entitled to receive the market price plus the difference between the additional put option and the floor.

We determine the fair values of our oil and gas derivative agreements based on discounted cash flows derived from third-party forward quoted prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil forward prices as of March 31, 2009. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties for derivatives in an asset position and our own credit risk derivatives in a liability position, in

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accordance with SFAS No. 157. The following table sets forth our commodity derivative positions as of March 31, 2009:

		Weighted Average Price						Estimated Fair Value (in thousands)
	Average Volume Per Day	Additional Put Option		Floor		Ceiling
	(in MMBtus)			(per MMBtu)
Natural Gas Costless Collars
Second Quarter 2009	15,000			$	4.25	$	5.70		791
Third Quarter 2009	15,000			$	4.25	$	5.70		633
Fourth Quarter 2009	15,000			$	4.25	$	5.70		(89	)
First Quarter 2010	35,000			$	4.96	$	7.41		(101	)
Second Quarter 2010	30,000			$	5.33	$	8.02		1,077
Third Quarter 2010	30,000			$	5.33	$	8.02		653
Fourth Quarter 2010	30,000			$	5.42	$	8.67		276
First Quarter 2011	30,000			$	5.42	$	8.67		(730	)
	(in MMBtus)			(per MMBtu)
Natural Gas Three-way Collars
Second Quarter 2009	40,000	$	6.38	$	8.75	$	10.79		8,577
Third Quarter 2009	40,000	$	6.38	$	8.75	$	10.79		8,234
Fourth Quarter 2009	30,000	$	6.83	$	9.50	$	13.60		6,358
First Quarter 2010	30,000	$	6.83	$	9.50	$	13.60		5,527
	(in MMBtus)			(per MMBtu)
Natural Gas Swaps
Second Quarter 2009	40,000			$	4.91				4,095
Third Quarter 2009	40,000			$	4.91				2,735
Fourth Quarter 2009	40,000			$	4.91				(105	)
	(Bbl)			(Bbl)
Crude Oil Three-way Collars
Second Quarter 2009	500	$	80.00	$	110.00	$	179.00		1,372
Third Quarter 2009	500	$	80.00	$	110.00	$	179.00		1,326
Fourth Quarter 2009	500	$	80.00	$	110.00	$	179.00		1,261
Settlements to be paid in subsequent period									421
Oil and gas segment commodity derivatives – net asset								$	42,311

At March 31, 2009, we reported a net derivative asset related to the oil and gas commodity derivatives of $42.3 million. See theFinancial Statement Impact of Derivatives section below for the impact of the oil and gas commodity derivatives on our consolidated financial statements.

PVR Natural Gas Midstream Segment Commodity Derivatives

PVR utilizes three-way collar derivative contracts to hedge against the variability in cash flows associated with anticipated natural gas midstream revenues and cost of midstream gas purchased. PVR also utilizes a combination of collar derivative contracts and swap contracts to hedge against the variability in its frac spread. PVR’s frac spread is the spread between the purchase price for the natural gas PVR purchases from producers and the sale price for natural gas liquids (“NGLs”) that PVR sells after processing. PVR hedges against the variability in its frac spread by entering into costless collar and swap derivative contracts to sell NGLs forward at a predetermined commodity price and to purchase an equivalent volume of natural gas forward on an MMBtu basis. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues or cost savings from favorable price movements.

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PVR determines the fair values of its derivative agreements based on discounted cash flows based on forward quoted prices for the respective commodities as of March 31, 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 for derivatives in a liability position. The following table sets forth PVR’s positions as of March 31, 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)
	(in barrels)			(per barrel)
Crude Oil Three-way Collar
Second Quarter 2009 through Fourth Quarter 2009	1,000	$	70.00	$	90.00	$	119.25	$	4,939
	(in MMBtu)			(per MMBtu)
Frac Spread Collar
Second Quarter 2009 through Fourth Quarter 2009	6,000			$	9.09	$	13.94		5,594
Settlements to be received in subsequent period									2,366
Natural gas midstream segment commodity derivatives – net asset								$	12,899

At March 31, 2009, PVR reported a net derivative asset related to the natural gas midstream segment of $12.9 million. See theFinancial Statement Impact of Derivativessection below for the impact of the PVR natural gas midstream commodity derivatives on our consolidated financial statements.

Interest Rate Swaps

We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver until December 2010. The notional amounts of the Interest Rate Swaps total $50.0 million, or approximately 13% of our total long-term debt outstanding under the Revolver at March 31, 2009. We will pay a weighted average fixed rate of 5.34% on the notional amount, and the counterparties will pay a variable rate equal to the three-month London Interbank Offered Rate (“LIBOR”). Settlements on the Interest Rate Swaps are recorded as interest expense. We reported a (i) net derivative liability of $3.4 million at March 31, 2009 and (ii) loss in AOCI of $2.2 million, net of the related income tax benefit of $1.2 million, at March 31, 2009 related to the Interest Rate Swaps. In connection with periodic settlements, we recognized $0.3 million in net hedging losses, net of the related income tax benefit of $0.1 million, on the Interest Rate Swaps in interest expense in the three months ended March 31, 2009. See theFinancial Statement Impact of Derivativessection below for the impact of the Interest Rate Swaps on our consolidated financial statements.

During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps are recognized in earnings currently. At March 31, 2009, a $2.2 million loss remained in AOCI related to these discontinued Interest Rate Swaps hedges. The $2.2 million loss will be recognized in earnings through the end of 2011 as the originally forecasted transactions occur.

PVR Interest Rate Swaps

PVR has entered into the PVR Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. The following table sets forth the PVR Interest Rate Swap positions at March 31, 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%

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The notional amount of $310.0 million represents approximately 52% of PVR’s total long-term debt outstanding at March 31, 2009. The weighted-average fixed rate is paid by PVR based on the notional amount, with the counterparties paying a variable rate equal to the three-month LIBOR. The PVR Interest Rate Swaps extend one year past the maturity of the PVR Revolver. The PVR Interest Rate Swaps have been entered into with seven financial institution counterparties, with no counterparty having more than 24% of the open positions.

During the first quarter of 2009, PVR discontinued hedge accounting for all of the PVR Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the PVR Interest Rate Swaps are recognized in earnings currently. At March 31, 2009, a $3.9 million loss remained in AOCI related to these discontinued PVR Interest Rate Swap hedges. The $3.9 million loss will be recognized in earnings through the end of 2011 as the originally forecasted transactions occur.

PVR reported a (i) net derivative liability of $13.1 million at March 31, 2009 and (ii) loss in AOCI of $3.9 million at March 31, 2009 related to the PVR Interest Rate Swaps. In connection with periodic settlements, PVR recognized $0.8 million of net hedging losses in interest expense in the three months ended March 31, 2009. See theFinancial Statement Impact of Derivativessection below for the impact of the PVR Interest Rate Swaps on our consolidated financial statements.

Financial Statement Impact of Derivatives

In the three months ended March 31, 2009, we reclassified a total of $0.8 million, net of income tax expense of $0.5 million, out of AOCI and into earnings. We also recorded unrealized hedging losses of $0.4 million, net of income tax benefit of $0.2 million, in AOCI in the three months ended March 31, 2009 related to the Interest Rate Swaps and the PVR Interest Rate Swaps. See Note 4, “Noncontrolling Interests,” for a detailed schedule of our AOCI.

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 months ended March 31, 2009 and 2008 (in thousands):

	Location of gain (loss) on derivatives recognized in income	Three Months Ended March 31,
Derivatives de-designated as hedging instruments under SFAS No. 133:		2009			2008
Interest rate contracts (1)	Interest expense	$	(1,263	)	$	243
Increase (decrease) in net income resulting from derivatives de-designated as hedging instruments under SFAS No. 133		$	(1,263	)	$	243
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivatives	$	(1,114	)	$	—
Commodity contracts (1)	Natural gas midstream revenues		—			(2,251	)
Commodity contracts (1)	Cost of midstream gas purchased		—			1,143
Commodity contracts	Derivatives		11,369			(25,901	)
Increase (decrease) in net income resulting from derivatives not designated as hedging instruments under SFAS No. 133		$	10,255		$	(27,009	)
Total increase (decrease) in net income resulting from derivatives		$	8,992		$	(26,766	)
Realized and unrealized derivative impact:
Cash received (paid) for commodity and interest rate contract settlements	Derivatives	$	19,148		$	(8,953	)
Cash paid for interest rate contract settlements	Interest expense		(808	)		243
Unrealized derivative gain	(2)		(9,348	)		(18,056	)
Total increase (decrease) in net income resulting from derivatives		$	8,992		$	(26,766	)

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(1) This represents amounts reclassified out of AOCI and into earnings. At March 31, 2009, a $3.9 million loss remained in AOCI related to the PVR Interest Rate Swaps on which PVR discontinued hedge accounting.

(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 March 31, 2009 and December 31, 2008 (in thousands):

	Balance Sheet Location	Fair values at March 31, 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 under SFAS No. 133		$	—	$	—	$	—	$	6,825
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivative liabilities - current	$	—	$	8,947	$	—	$	4,663
Interest rate contracts	Derivative liabilities - noncurrent		—		7,550		—		5,073
Commodity contracts	Derivative assets/liabilities - current		62,727		8,794		67,569		7,694
Commodity contracts	Derivative assets/liabilities - noncurrent		1,276		—		4,070		—
Total derivatives not designated as hedging instruments under SFAS No. 133		$	64,003	$	25,291	$	71,639	$	17,430
Total estimated fair value of derivative instruments		$	64,003	$	25,291	$	71,639	$	24,255

See Note 5, “Fair Value Measurements” for a description of how the above financial instruments are valued in accordance with SFAS No. 157.

The following table summarizes the effect of the Interest Rate Swaps and the PVR Interest Rate Swaps on our total interest expense for the three months ended March 31, 2009 and 2008 (in thousands):

	Three Months Ended March 31,
Source	2009			2008
Interest on borrowings	$	(11,680	)	$	(12,292	)
Capitalized interest (1)		441			1,302
Interest rate swaps		(1,263	)		243
Total interest expense	$	(12,502	)	$	(10,747	)

(1) Capitalized interest was primarily related to the oil and gas segment’s development of unproved properties.

The effects of derivative gains (losses), cash settlements of our oil and gas commodity derivatives, cash settlements of PVR’s natural gas midstream commodity derivatives and cash settlements of the PVR Interest Rate Swaps are reported as adjustments to reconcile net income to net cash provided by operating activities on our consolidated statements of cash flows. These items are recorded in the “Total derivative losses (gains)” and “Cash settlements of derivatives” lines on our consolidated statements of cash flows.

At March 31, 2009, PVR reported a net commodity derivative asset related to the natural gas midstream segment of $12.9 million that is with two counterparties, which are financial institutions, and is substantially concentrated with one of those counterparties. We reported a net commodity derivative asset related to our oil and gas segment of $42.3 million, 80% of which was concentrated with three counterparties. These concentrations may

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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. 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 March 31, 2009 and March 31, 2008. No significant uncertainties related to the collectability of amounts owed to us or PVR exists with regard to these counterparties.

The above hedging activity represents cash flow hedges. As of March 31, 2009 neither PVR nor we actively traded derivative instruments or has any fair value hedges. In addition, as of March 31, 2009, neither PVR nor we owned derivative instruments containing credit risk contingencies.

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

We adopted 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 are accounting for the adoption of this standard as a change in accounting principle in accordance with FSP APB 14-1 and SFAS 154,Accounting Changes and Error Corrections. FSP APB 14-1 has therefore been applied retrospectively to all periods presented.

Because our Convertible Notes can be settled wholly or partly in cash upon conversion into our common stock, FSP APB 14-1 requires us to separately account 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. Because the liability component was valued exclusive of the conversion feature, the Convertible Notes were recorded at a discount reflecting the below-market coupon interest rate. This discount is accreted to par value over the expected life of the debt through additional interest expense.

The following table reflects the effects of adopting FSP APB 14-1 on our consolidated statements of income for the three months ended March 31, 2009 and 2008 (in thousands):

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Effects of FSP APB 14-1 Adoption on the Consolidated Statement of Income
Three Months Ended March 31, 2009
Consolidated Statement of Income	As computed under prior accounting principle			As adjusted			Effects of change
Interest expense – (1)	$	(10,666	)	$	(12,502	)	$	(1,836	)
Income tax benefit – (2)		3,851			4,562			711
Net income (loss)		(2,426	)		(3,551	)		(1,125	)
Net loss attributable to Penn Virginia Corporation		(6,084	)		(7,209	)		(1,125	)
Earnings per share – basic and diluted:
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, basic	$	(0.15	)	$	(0.17	)	$	(0.02	)
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, diluted	$	(0.14	)	$	(0.17	)	$	(0.03	)

Three Months Ended March 31, 2008
Consolidated Statement of Income	As originally reported			As adjusted			Effects of change
Interest expense – (3)	$	(9,552	)	$	(10,747	)	$	(1,195	)
Income tax expense – (2)		(3,057	)		(2,594	)		463
Net income		23,954			23,222			(732	)
Net income (loss) attributable to Penn Virginia Corporation		3,926			3,194			(732	)
Earnings per share – basic and diluted:
Net income per share attributable to Penn Virginia Corporation common shareholders, basic	$	0.09		$	0.08		$	(0.02	)
Net income per share attributable to Penn Virginia Corporation common shareholders, diluted	$	0.09		$	0.07		$	(0.02	)

(1) The additional interest expense incurred in the three months ended March 31, 2009 as a result of adopting FSP APB 14-1 is due to the debt discount that was created, which increased the amount of interest expense recognized for the period. This increase is partially offset by the amortization of debt issuance costs, which resulted from the separation of the debt and equity components of the Convertible Notes.

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

(3) The impact on interest expense as presented for the three months ended March 31, 2008 is due to 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 changes 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.

The following table reflects the effects of adopting FSP APB 14-1 on our consolidated balance sheets at March 31, 2009 and December 31, 2008 (in thousands):

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Effects of FSP APB 14-1 Adoption on the Consolidated Balance Sheets
Three Months Ended March 31, 2009
Consolidated Balance Sheet	As computed under prior accounting principle		As adjusted		Effect of change
Oil and gas properties (successful efforts method) – (1)	$	2,175,214	$	2,176,467	$	1,253
Other assets – (2)		54,660		53,734		(926	)
Deferred income taxes – (3)		243,716		255,964		12,248
Convertible Notes – (4)		230,000		201,545		(28,455	)
Paid-in capital – (5)		578,768		599,984		21,216
Retained earnings – (6)		439,019		434,087		(4,932	)
December 31, 2008
Consolidated Balance Sheet	As originally reported		As adjusted		Effects of change
Oil and gas properties (successful efforts method) – (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 as a portion of such costs with allocated to equity upon issuance of Convertible Notes.

(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 debt discount attributable to the equity component to the Convertible Note.

(5) The impact on the paid-in capital balance is due to the equity component and related issueance 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 table reflects the effects of adopting FSP APB 14-1 on our consolidated statements of cash flows at March 31, 2009 and December 31, 2008 (in thousands):

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Effects of FSP APB 14-1 Adoption on the Consolidated Statements of Cash Flows
Three Months Ended March 31, 2009
Consolidated Statement of Cash Flows	As computed under prior accounting principle			As adjusted			Effects of change
Cash flows from operating activities
Net income	$	(2,426	)	$	(3,551	)	$	(1,125	)
Deferred income taxes		(3,923	)		(4,634	)		(711	)
Non-cash interest expense		875			2,711			1,836
Total impact on the statement of cash flows	$	(5,474	)	$	(5,474	)	$	—
Three Months Ended March 31, 2008
Consolidated Statement of Cash Flows	As originally reported			As adjusted			Effects of change
Cash flows from operating activities
Net income	$	23,954		$	23,222		$	(732	)
Deferred income taxes		2,605			2,142			(463	)
Non-cash interest expense		757			1,952			1,195
Total impact on the statement of cash flows	$	27,316		$	27,316		$	—

The following table reflects the carrying amounts of the liability and equity components of the Convertible Notes:

	March 31, 2009			December 31, 2008
Principal	$	230,000		$	230,000
Unamortized discount		(28,455	)		(30,104	)
Net carrying amount of liability component	$	201,545		$	199,896
Carrying amount of equity component	$	36,850		$	36,850

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

As of March 31, 2009, the remaining period over which the discount will be amortized is approximately four years. The effective interest rate on the liability component for the three months ended March 31, 2009 and 2008 was 8.50%. For the three months ended March 31, 2009, we recognized $2.6 million of interest expense related to the contractual coupon rate on the Convertible Notes and $1.6 million of interest expense related to the amortization of the discount. For the three months ended March 31, 2008, we recognized $2.5 million of interest expense related to the contractual coupon rate on the Convertible Notes and $1.5 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 17.3160 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.

In connection with the issuance of the Convertible Notes, we entered into convertible note hedge transactions (the “Note Hedges) with respect to shares of our common stock with affiliates of certain of the underwriters of the Convertible Notes (collectively, the “Option Counterparties”). The Note Hedges cover, subject to anti-dilution adjustments, the net shares of our common stock that would be deliverable to converting noteholders in the event of a conversion of the Convertible Notes. In December 2007, we paid an aggregate amount of $18.6 million of the net proceeds from the sale of the Convertible Notes for the cost of the Note Hedges (after such cost was offset by the proceeds of the Warrants described below).

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We also entered into separate warrant transactions (the “Warrants”), whereby we sold to the Option Counterparties warrants to acquire, subject to anti-dilution adjustments, approximately 3,982,680 shares of our common stock at an exercise price of $74.25 per share. In December 2007, we received proceeds of $18.2 million resulting from this sale. If the warrants are exercised, we would deliver shares of our common stock equal to the difference between the then market price and the strike price of the Warrants.

If the market value per share of our common stock at the time of conversion of the Convertible Notes is above the strike price of the Note Hedges, the Note Hedges entitle us to receive from the Option Counterparties net shares of our common stock (and cash for any fractional share cash amount) based on the excess of the then current market price of our common stock over the strike price of the Note Hedges. Additionally, if the market price of our common stock at the time of exercise of the Warrants exceeds the strike price of the Warrants, we will owe the Option Counterparties net shares of our common stock (and cash for any fractional share cash amount), not offset by the Note Hedges, in an amount based on the excess of the then current market price of our common stock over the strike price of the Warrants.

8. Long-Term Debt

In March 2009, our bank group completed a semi-annual re-determination of the borrowing base under the Revolver. As a result, the borrowing base has been revised to $450.0 million, which is approximately 6% less than its previous level of $479.0 million.

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. The December 2011 maturity date for the PVR Revolver did not change. 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 LIBOR, plus an applicable margin ranging from 1.75% to 2.75% if PVR selects the LIBOR-based borrowing option. As of March 31, 2009 the interest rate on the PVR Revolver was at the bank’s base rate of 3.75%. Effective April 1, 2009, the interest rate on the PVR Revolver was a LIBOR-based rate of 2.87%.

9. Impairments and Unproved Leasehold Expense

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. In this circumstance, we recognize an impairment loss equal to the difference between the carrying value and the fair value of the asset. Fair value is estimated to be the present value of future net cash flows from the asset, discounted using a rate commensurate with the risk and remaining life of the asset.

For the three months ended March 31, 2009, we recorded impairment charges related to our oil and gas segment properties of $1.2 million. These charges were primarily related to market declines in the spot and future oil and gas prices.

Costs related to unproved properties are capitalized and periodically evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management. We continue to experience an increase in lease expirations and unproved leasehold expense caused by current economic conditions which have impacted our future drilling plans thereby increasing the amount of expected lease expirations. Effective January 1, 2009, we changed our accounting process to amortize additional insignificant unproved properties over the average estimated life of the leases versus amortizing some leases and assessing other leases on an occurrence basis. As a result of amortizing additional leases, we recorded additional unproved leasehold expense, which is included in exploration expense on the consolidated statements of income, of $6.3 million in the three months ended March 31, 2009. The impact of this change on net income for the three months ended March 31, 2009 was a decrease of $3.9 million, net of income taxes. The impact of this change decreased basic and diluted earnings per share for the three months ended March 31, 2009 by $0.09.

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10. Earnings per Share

The following is a reconciliation of the numerators and denominators used in the calculation of basic and diluted earnings per share for the three months ended March 31, 2009 and 2008:

	Three Months Ended March 31,
	2009			2008
	(in thousands, except per share data)
Net income (loss) attributable to Penn Virginia Corporation common shareholders	$	(7,209	)	$	3,194
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards (net of tax)		(13	)		(103	)
	$	(7,222	)	$	3,091
Weighted average shares, basic		41,922			41,558
Effect of dilutive securities:
Stock options(1)		—			245
Weighted average shares, diluted		41,922			41,803
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, basic	$	(0.17	)	$	0.08
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, diluted	$	(0.17	)	$	0.07

(1) For the three months ended March 31, 2009, 0.2 million, potentially dilutive securities, including stock options and phantom stock had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.

11. Share-Based Compensation

Stock Compensation Plans

We recognized compensation expense related to the granting of common stock and deferred common stock units and the vesting of stock options and restricted and phantom stock granted under our stock compensation plans. For the three months ended March 31, 2009 and 2008, we recognized a total of $2.6 million and $1.2 million of compensation expense related to our stock compensation plans. The total income tax benefit recognized in our consolidated statements of income for our stock compensation plans was $1.0 million and $0.4 million for the three months ended March 31, 2009 and 2008. Compensation expense is recorded on the general and administrative expense line on the consolidated statements of income.

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 granted vest over a three-year period, with one-third vesting in each year. We recognize compensation expense on a straight-line basis over the vesting period.

Phantom Units. In February 2009, we granted 104,449 phantom units of our stock to non-employee directors with a weighted average grant date fair value of $15.06 per share. The phantom units granted vest over a three-year period, with one-third vesting in each year. We recognize compensation expense on a straight-line basis over the vesting period.

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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 granted vest immediately. We recognized compensation expense in the period these units were granted.

PVR Long-Term Incentive Plan

PVR recognized a total of $1.4 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 granted under the long-term incentive plan for the three months ended March 31, 2009 and 2008. During the three months ended March 31, 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. During the same period, 98,322 restricted units with a weighted average grant date fair value of $27.44 per unit vested. 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. These expenses are recorded on the general and administrative expense line on our consolidated statements of income.

12. Commitments and Contingencies

Drilling Rig Commitments and Standby Charges

In the first quarter of 2009, our oil and gas segment opted to defer drilling of many wells due to unfavorable economic conditions. As a result, we amended certain drilling rig contracts to delay commencement of drilling until January 2010. In the first quarter of 2009, we incurred a liability of approximately $9.9 million for lump sum delay fees, minimum daily standby fees and demobilization fees expected to be paid during the standby period. These fees and costs are recorded in accounts payable and accrued liabilities on the consolidated balance sheets and as exploration expense on the 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 $14.8 million for 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.

Environmental Compliance

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 adverse impact on us. 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 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

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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 material impact on its financial condition or results of operations.

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

Mine Health and Safety Laws

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

13. Segment Information

Segment information has been prepared in accordance with SFAS No. 131,Disclosure about Segments of an Enterprise and Related Information. Under SFAS No. 131, operating segments are defined as components of an enterprise about which separate financial information is available and is evaluated regularly by the chief operating decision maker, or decision-making group, in assessing performance. Our decision-making group consists of our Chief Executive Officer and other senior officers. This group routinely reviews and makes operating and resource allocation decisions among our oil and gas operations and PVR’s coal and natural resource management operations and PVR’s natural gas midstream operations. Accordingly, 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.

The following table presents a summary of certain financial information relating to our segments as of and for the three months ended March 31, 2009 and 2008 (in thousands):

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	Revenues						Intersegment revenues (1)
	Three Months Ended March 31,						Three Months Ended March 31,
	2009			2008			2009			2008
Oil and gas	$	64,565		$	92,772		$	(346	)	$	(473	)
Coal and natural resource		38,252			30,492			198			(198	)
Natural gas midstream		118,507			126,047			22,520			473
Other		(22,164	)		(176	)		(22,372	)		198
Consolidated totals	$	199,160		$	249,135		$	—		$	—
	Operating income						DD&A expense
	Three Months Ended March 31,						Three Months Ended March 31,
	2009			2008			2009			2008
Oil and gas	$	(22,655	)	$	36,352		$	39,999		$	26,616
Coal and natural resource		24,974			17,582			7,394			6,413
Natural gas midstream		(3,047	)		13,652			9,109			5,087
Other		(6,711	)		(7,453	)		571			453
Consolidated totals	$	(7,439	)	$	60,133		$	57,073		$	38,569
Interest expense		(12,502	)		(10,747	)
Other		1,573			2,331
Derivatives		10,255			(25,901	)
Income tax expense		4,562			(2,594	)
Net income attributable to noncontrolling interest		(3,658	)		(20,028	)
Net income attributable to Penn Virginia Corporation	$	(7,209	)	$	3,194
	Additions to property and equipment
	Three Months Ended March 31,						Total assets at
	2009			2008			March 31, 2009			December 31, 2008
Oil and gas	$	120,574		$	95,189		$	1,737,860		$	1,728,375
Coal and natural resource		1,300			48			609,372			600,418
Natural gas midstream		17,006			17,622			597,347			618,402
Other		406			543			55,919			49,370
Consolidated totals	$	139,286		$	113,402		$	3,000,498		$	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.

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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 PVR, which is engaged in the coal and natural resource management and natural gas midstream businesses. Our ownership interests in Penn Virginia Resource Partners, L.P., or 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 March 31, 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, or IDRs.

Because PVG controls the general partner of PVR, the financial results of PVR are included in PVG’s consolidated financial statements. Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. However, PVG and PVR function with capital structures that are independent of each other and us, with each having publicly traded common units and PVR having its own debt instruments. PVG does not currently have any debt instruments.

While we report consolidated financial results of PVR’s coal and natural resource management and natural gas midstream businesses, the only cash we received from those businesses is in the form of cash distributions we received from PVG and PVR in respect of our partner interests in each of them.

The following diagram depicts our ownership of PVG and PVR as of March 31, 2009:

We are engaged in three primary business segments: (i) oil and gas, (ii) coal and natural resource management and (iii) natural gas midstream. We operate our oil and gas segment and PVR operates the coal and natural resource management and natural gas midstream segments. Our consolidated operating loss was $7.4 million in the three

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months ended March 31, 2009, compared to consolidated operating income of $60.1 million in the same period of 2008, with contributions by segment as follows:

• a $22.7 million, or 305%, operating loss in the oil and gas segment;

• a $25.0 million, or 336%, operating income in the PVR coal and natural resources segment;

• a $3.0 million, or 41%, operating loss in the PVR natural gas midstream segment; and

• $6.7 million, or 90%, of corporate expenses and intercompany eliminations.

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			Other			Consolidated
	(in thousands)
For the Three Months Ended March 31, 2009:
Revenues	$	64,565		$	38,252	$	118,507		$	(22,164	)	$	199,160
Operating costs and expenses		46,025			5,884		112,445			(16,024	)		148,330
Impairments		1,196			—		—			—			1,196
Depreciation, depletion and amortization		39,999			7,394		9,109			571			57,073
Operating income (loss)	$	(22,655	)	$	24,974	$	(3,047	)	$	(6,711	)	$	(7,439	)
For the Three Months Ended March 31, 2008:
Revenues	$	92,299		$	30,294	$	126,520		$	22		$	249,135
Operating costs and expenses		29,331			6,299		107,781			7,022			150,433
Depreciation, depletion and amortization		26,616			6,413		5,087			453			38,569
Operating income (loss)	$	36,352		$	17,582	$	13,652		$	(7,453	)	$	60,133

The deterioration in global financial markets which began during the third quarter of 2008 and the consequential adverse effect on credit availability continues to adversely impact our and PVR’s access to new capital and credit availability. Depending on the longevity and ultimate severity of this deterioration, our and PVR’s ability to conduct a growth oriented capital spending program will be adversely affected, as could PVR’s ability to make cash distributions to its limited partners and to PVG, the owner of its general partner.

Oil and Gas Segment

We have a geographically diverse asset base with core areas of operation in the East Texas, Mid-Continent, Appalachian and Mississippi regions of the United States. As of December 31, 2008, we had proved natural gas and oil reserves of approximately 916 Bcfe, of which 82% were natural gas and 51% were proved developed. In the three months ended March 31, 2009, we produced 13.7 Bcfe, a 30% increase compared to 10.5 Bcfe in the same period of 2008. However, our average realized price received for natural gas decreased 46%, from $8.26 per Mcf in the three months ended March 31, 2008 to $4.48 per Mcf in the three months ended March 31, 2009, while the average realized price received for our crude oil decreased 62%, from $97.00 per Bbl to $37.01 per Bbl and the average realized price received for our natural gas liquids, or NGLs, decreased 58%, from $54.94 per Bbl to $22.93 per Bbl in the same periods.

The primary development play types that our oil and gas operations have recently focused on include the horizontal Lower Bossier (Haynesville) Shale play in East Texas, the horizontal Granite Wash play in the Mid-Continent, the multi-lateral horizontal coalbed methane play in Appalachia and the predominantly horizontal Selma Chalk play in Mississippi.

Prior to 2009, the growth profile in our oil and gas segment was accomplished primarily by drilling oil and natural gas wells in our operating areas and, to a lesser extent, by making acquisitions of both producing properties

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and undeveloped leases. This growth profile has required us to spend capital in excess of our cash flow from operations, and readily available access to debt and equity capital facilitated our ability to grow. Significantly lower internal cash flows due to reduced energy commodity prices and the continued weakness in global financial markets has adversely impacted our ability to fund a growth oriented capital spending program in 2009. In response to these conditions, we have limited our capital spending in 2009 to more closely mirror internally generated cash flow.

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 three months ended March 31, 2009, PVR’s lessees produced 8.7 million tons of coal from its properties and paid to PVR coal royalties revenues of $30.6 million, for an average royalty per ton of $3.50. Approximately 82% of PVR’s coal royalties revenues in the three months ended March 31, 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 our 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.

Coal royalties are impacted by several factors that PVR generally cannot control. The number of tons mined annually is determined by an operator’s mining efficiency, labor availability, geologic conditions, access to capital, ability to market coal and ability to arrange reliable transportation to the end-user. New legislation or regulations have been or may be adopted which may have a significant impact on the mining operations of PVR’s lessees or their customers’ ability to use coal and which may require PVR, PVR’s lessees or PVR’s lessees’ customers to change operations significantly or incur substantial costs.

To a lesser extent, coal prices also impact coal royalties revenues. Generally, as coal prices change, PVR’s average royalty per ton also changes because the majority of PVR’s lessees pay royalties based on the gross sales prices of the coal mined. Most of PVR’s coal is sold by its lessees under contracts with a duration of one year or more; therefore, changes to PVR’s average royalty occur as PVR’s lessees’ contracts are renegotiated.

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

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

PVR Natural Gas Midstream Segment

The PVR natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of March 31, 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.

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In the three months ended March 31, 2009, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 32.3 Bcf, or approximately 359 MMcfd. In the three months ended March 31, 2009, 25% of the PVR natural gas midstream segment revenues and 15% of our total consolidated revenues were derived from Conoco, Inc., one of the PVR natural gas midstream segment customers.

PVR continually seeks new supplies of natural gas to both offset the natural declines in production from the wells currently connected to its systems and to increase system throughput volumes. New natural gas supplies are obtained for all of PVR’s systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors’ systems. In the three months ended March 31, 2009, the PVR natural gas midstream segment made aggregate capital expenditures of $14.5 million, primarily related to PVR’s Panhandle System where producers continue to develop.

Revenues, profitability and the future rate of growth of our natural gas midstream segment are highly dependent on market demand and prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market demand. The deterioration in the global economy, including financial and credit markets, has resulted in a decrease in worldwide demand for oil and domestic demand for natural gas and NGLs. Limited access to capital could continue to hamper PVR’s ability to fund acquisitions, potentially restricting future growth potential. Depending on the longevity and ultimate severity of the deterioration, NGL production from PVR’s processing plants could decrease and adversely effect PVR’s natural gas midstream processing income and PVR’s ability to make cash distributions.

Other and Eliminations

Other and eliminations primarily represents corporate functions such as interest expense, income tax expense, oil and gas segment derivatives and elimination of intercompany sales.

Liquidity and Capital Resources

Although results are consolidated for financial reporting, Penn Virginia, PVG and PVR operate with independent capital structures. Since PVR’s inception in 2001 and PVG’s inception in 2006, with the exception of cash distributions paid to us by PVG and PVR, the cash needs of each entity have been met independently with a combination of operating cash flows, credit facility borrowings and the issuance of new PVG and PVR units. We expect that our cash needs and the cash needs of PVG and PVR will continue to be met independently of each other with a combination of these funding sources.

Liquidity is defined as the ability to convert assets into cash or to obtain cash. Short-term liquidity refers to the ability to meet short-term obligations of 12 months or less. Liquidity is a matter of degree and is expressed in terms of working capital and the current ratio and, due to the recent deterioration of the credit and financial markets, in terms of the availability of borrowing capacity against existing credit facilities and debt instruments. Our consolidated working capital (current assets minus current liabilities) and consolidated current ratio (current assets divided by current liabilities) are as follows as of March 31, 2009 and December 31, 2008:

	March 31, 2009		December 31, 2008
Current Assets	$	231,864	$	263,518
Current Liabilities		190,340		247,594
Working Capital		41,524		15,924
Current Ratio		1.22		1.06

Because Penn Virginia, PVG and PVR operate with independent capital structures, an important indicator of liquidity is the availability of borrowing capacity. As discussed in more detail in “–Long-Term Debt” below, as of March 31, 2009, we had availability of $59.7 million on our $450.0 million revolving credit facility, or the Revolver, and PVR had availability of $203.3 million on its recently expanded $800.0 million revolving credit facility, or the PVR Revolver.

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With respect to Penn Virginia (excluding the sources and uses of capital by PVG and PVR), we satisfy our working capital requirements and fund our capital expenditures using cash generated from our operations, borrowings under the Revolver and proceeds from equity offerings. We satisfy our debt service obligations and dividend payments solely using cash generated from our operations. We believe that the cash generated from our operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures, scheduled debt payments and dividend payments. Our ability to satisfy our obligations and planned expenditures will depend on our future operating performance, which will be affected by, among other things, prevailing economic conditions in the commodity markets of oil and natural gas, some of which are beyond our control. Because of the recent deterioration in the financial and credit markets we are anticipating a decrease in capital spending in 2009. In addition, depending on the longevity and ultimate severity of the recent deterioration of the global economy, including financial and credit markets, our ability in the future to grow organically or through acquisitions may be significantly adversely effected.

PVR’s ability to satisfy its obligations and planned expenditures will depend upon its future operating performance, which will be affected by prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond PVR’s control. During the first quarter of 2009, PVR completed an amendment to increase the borrowing base under the PVR Revolver, with resultant borrowing availability of $203.3 million as of March 31, 2009. However, depending on the longevity and ultimate severity of the recent deterioration of the global economy, including financial and credit markets, PVR’s ability in the future to grow organically or through acquisitions may be significantly adversely affected, as may PVR’s ability to make cash distributions to its limited partners and to PVG, the owner of PVR’s general partner.

Cash Flows

Except where noted, the following discussion of cash flows and capital expenditures relates to our consolidated results. The following table summarizes our cash flow statements for the three months ended March 31, 2009 and 2008 (in thousands):

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For The Three Months Ended March 31, 2009	Oil and Gas, PVA Corporate & Other			PVG			Consolidated
Cash flows from operating activities:
Net income (loss) contribution	$	(12,493	)	$	8,942		$	(3,551	)
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		51,298			25,679			76,977
Net change in operating assets and liabilities		30,555			(962	)		29,593
Net cash provided by operating activities		69,360			33,659			103,019
Net cash flows from investing activities:
Acquisitions		(1,817	)		(1,256	)		(3,073	)
Additions to property and equipment		(119,163	)		(17,050	)		(136,213	)
Other		(11	)		265			254
Net cash used in investing activities		(120,991	)		(18,041	)		(139,032	)
Cash flows from financing activities:
Dividends paid		(2,349	)		—			(2,349	)
Distributions received (paid)		11,533			(29,988	)		(18,455	)
Debt borrowings, net		58,000			27,000			85,000
Repayment of bank borrowings		(7,542	)		—			(7,542	)
Other		—			(9,258	)		(9,258	)
Net cash provided by (used in) financing activities		59,642			(12,246	)		47,396
Net increase in cash and cash equivalents	$	8,011		$	3,372		$	11,383
For The Three Months Ended March 31, 2008	Oil and Gas, PVA Corporate & Other			PVG			Consolidated
Cash flows from operating activities:
Net income (loss) contribution	$	(10,785	)	$	34,007		$	23,222
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		66,458			(5,104	)		61,354
Net change in operating assets and liabilities		(17,500	)		(924	)		(18,424	)
Net cash provided by operating activities		38,173			27,979			66,152
Net cash flows from investing activities:
Acquisitions		(4,720	)		(20	)		(4,740	)
Additions to property and equipment		(91,012	)		(17,650	)		(108,662	)
Other		64			341			405
Net cash used in investing activities		(95,668	)		(17,329	)		(112,997	)
Cash flows from financing activities:
Dividends paid		(2,344	)		—			(2,344	)
Distributions received (paid)		10,432			(24,172	)		(13,740	)
Debt borrowings, net		54,000			2,000			56,000
Other		5,282			—			5,282
Net cash provided by (used in) financing activities		67,370			(22,172	)		45,198
Net increase (decrease) in cash and cash equivalents	$	9,875		$	(11,522	)	$	(1,647	)

Net Cash Provided by Operating Activities

Changes to working capital and to our current ratio are largely affected by net cash provided by both our and PVR’s operating activities. Net cash provided by our and PVR’s operating activities primarily came from the following sources:

Oil and gas segment:

• the sale of natural gas, crude oil and NGLs;

• settlements from our oil and gas commodity derivatives; and

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• the collection of fees charged for gathering natural gas volumes.

PVR coal and natural resource management segment:

• the collection of coal royalties;

• the sale of standing timber;

• the collection of coal transportation, or wheelage, fees;

• distributions received from PVR’s equity investees; and

• settlements from PVR’s interest rate swaps, or the PVR Interest Rate Swaps.

PVR natural gas midstream segment:

• the collection of revenues from natural gas processing contracts with natural gas producers;

• the collection of revenues from PVR’s natural gas marketing business; and

• settlements from PVR’s natural gas midstream commodity derivatives.

In addition, we receive settlements from our interest rate swaps, or the Interest Rate Swaps, which are included in our corporate and other activities.

Both we and PVR use the cash provided by operating activities in the oil and gas segment, the PVR coal and natural resource management segment and the PVR natural gas midstream segment in the following ways:

• operating expenses, such as office rentals, core-hole drilling costs and repairs and maintenance costs;

• taxes other than income, such as severance and property taxes;

• general and administrative expenses, such as office rentals, staffing costs and legal fees;

• interest on debt service obligations;

• capital expenditures;

• repayments of borrowings;

• PVR’s distributions to partners; and

• dividends to our shareholders.

Net cash provided by operating activities of the oil and gas segment and for Penn Virginia corporate and other activities in the three months ended March 31, 2009 increased by $31.2 million, or 82%, to $69.4 million of cash provided by operating activities from $38.2 million of cash provided by operating activities in the same period of 2008. This increase was primarily due to changes in working capital. Excluding changes in working capital, cash provided by oil and gas segment operating activities decreased by $16.9 million, or 30%, to $38.8 million, due to decreased natural gas and crude oil revenues resulting from decreased commodity prices. See “Results of Operations–Oil and Gas Segment” and “Results of Operations–Eliminations and Other–Corporate Operating Expenses” for a more detailed explanation of the factors that determined cash provided by operating activities.

PVG does not have any operations on a stand-alone basis. It primarily relies on cash distributions received from PVR for its general and administrative expenses, which are the costs of PVG being a publicly traded company.

Net cash provided by PVG’s operating activities in the three months ended March 31, 2009 increased by $5.7 million, or 20%, to $33.7 million from $28.0 million in the same period of 2008. The overall increase in net cash provided by PVG’s operating activities was primarily attributable to increased coal royalties received by PVR, which was driven primarily by increased production and sales prices of coal in all regions and an increase in cash received from the settlement of PVR’s derivative positions. These increases were partially offset by decreased cash received by PVR from the sales of residue gas and NGLs, which was primarily driven by a decrease in commodity prices for natural gas and NGLs. See “Results of Operations – PVR Coal and Natural Resource Management Segment” and “Results of Operations– PVR Natural Gas Midstream Segment” for a more detailed explanation of the factors that increased cash provided by PVR’s operating activities.

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Net Cash Used in Investing Activities

Net cash used in investing activities in the oil and gas segment and for Penn Virginia corporate and other activities in the three months ended March 31, 2009 increased by $25.3 million, or 26%, to $121.0 million from $95.7 million in the same period of 2008. PVG’s investing activities consist solely of cash provided by and used in PVR’s investing activities. Net cash used by PVR in its investing activities in the three months ended March 31, 2009 increased by $0.7 million, or 4%, to $18.0 million from $17.3 million in the same period of 2008. The cash used by both us and PVR in investing activities for the three months ended March 31, 2009 and 2008 were used primarily for capital expenditures. The following table sets forth capital expenditures by segment made during the three months ended March 31, 2009 and 2008, including non-cash adjustments related to accrued drilling costs and acquisitions:

	Three Months Ended March 31,
	2009		2008
	(in thousands)
Oil and gas
Development drilling	$	76,483	$	79,115
Exploration drilling		1,468		5,425
Seismic		734		680
Lease acquisition and other		1,774		4,614
Pipeline, gathering, facilities		5,129		4,862
Total		85,588		94,696
Coal and natural resource management
Acquisitions		1,256		20
Other property and equipment expenditures		44		28
Total		1,300		48
Natural gas midstream
Expansion capital expenditures		11,200		16,373
Other property and equipment expenditures		3,282		3,106
Total		14,482		19,479
Other		595		251
Total capital expenditures	$	101,965	$	114,474

In the three months ended March 31, 2009, the oil and gas segment made aggregate capital expenditures of $85.6 million. These capital expenditures were related to development drilling and pipeline, gathering and facilities primarily in our Lower Bossier (Haynesville) play in East Texas. In the three months ended March 31, 2008, the oil and gas segment made aggregate capital expenditures of $94.7 million primarily for development drilling, exploration drilling and lease acquisitions

In the three months ended March 31, 2009, PVR made aggregate capital expenditures of $15.8 million. These capital expenditures consisted primarily of expansion capital expenditures in the PVR natural gas midstream segment, primarily to develop additional processing capacity in its Panhandle System. The PVR natural gas midstream segment also incurred approximately $3.3 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas.

In the three months ended March 31, 2008, PVR made aggregate capital expenditures of $19.5 million. These capital expenditures consisted primarily of the PVR natural gas midstream segment gathering system expansion

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projects. The PVR natural gas midstream segment also incurred $3.1 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas

We funded oil and gas and other capital expenditures in the three months ended March 31, 2009 and 2008 with borrowings under the Revolver, cash provided by operating activities, cash distributions received from PVG and PVR and cash provided by operating activities. PVR funded its coal and natural resource management and natural gas midstream capital expenditures in the three months ended March 31, 2009 and 2008 primarily with cash provided by operating activities and borrowings under the PVR Revolver. See “—Future Capital Needs and Commitments” for an analysis of future capital expenditures and the sources for funding those expenditures.

Net Cash Provided by Financing Activities

Net cash provided by (used in) financing in the oil and gas segment and for corporate remained relatively constant from the three months ended March 31, 2008 to the same period of 2009. In the three months ended March 31, 2009, we borrowed $58.0 million under the Revolver. See “—Long-Term Debt” below for a more detailed description of our March 31, 2009 long-term debt balance.

As a result of our partner interests in PVG and PVR, we received cash distributions of $11.5 million and $10.4 million in the three months ended March 31, 2009 and 2008. These distributions were primarily used for oil and gas segment capital expenditures and operating activities.

Net cash used in PVG’s financing activities in the three months ended March 31, 2009 decreased by $10.0 million, or 45%, to $12.2 million from $22.2 million in the same period of 2008. Over the comparative period, we had an increase in cash distributions to PVG’s and PVR’s partners, which was related to an increase in the distribution per unit and to debt issuance costs paid by PVR in the three months ended March 31, 2009. The increase in cash distributions to partners was due to the increase in the cash distributions paid per unit and due to an increase in PVR’s outstanding common units resulting from the 2008 unit offering where PVR issued an additional 5.15 million common units to the public. These increases in cash used in financing activities were partially offset by an increase in net proceeds from PVR’s long-term borrowings. See “—Long-Term Debt” below for a more detailed description of PVR’s March 31, 2009 long-term debt balance.

The cash distribution that PVR and PVG will pay to its partners in May 2009 for the first quarter of 2009 will be unchanged from the distributions paid in February 2009. Both PVR and PVG will continue to be cautious about increasing and maintaining cash distributions to unitholders in the foreseeable future in order to preserve cash liquidity in light of uncertain commodity and financial markets.

Long-Term Debt

Revolver. As of March 31, 2009, we had $390.0 million outstanding under the Revolver, which is senior to our convertible senior subordinated notes, or the Convertible Notes. The Revolver is governed by a borrowing base calculation and is redetermined semi-annually. In March 2009, our bank group completed the semi-annual re-determination. As a result, the borrowing base was revised to $450.0 million, which is approximately 6% less than its previous level of $479.0 million. At the current $450.0 million limit on the Revolver, and given our outstanding balance of $390.0 million, net of $0.3 million of letters of credit outstanding, we could borrow up to $59.7 million at March 31, 2009. 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 $20.0 million sublimit for the issuance of letters of credit. In the three months ended March 31, 2009, we incurred commitment fees of $0.1 million on the unused portion of the Revolver. We capitalized $0.4 million of interest cost incurred in the three months ended March 31, 2009. We have the option to elect interest at (i) 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 March 31, 2009, the weighted average interest rate on borrowings outstanding under the Revolver was approximately 4.12%. We do not have a public credit rating for the Revolver.

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The financial covenants under the Revolver require us not to exceed specified ratios. We are required to maintain a Debt-to-EBITDAX ratio of no more than 3.5-to-1.0 and at March 31, 2009, the ratio was 1.7-to-1.0. We are also required to maintain an EBITDAX-to-interest expense ratio of no less than 2.5-to-1.0 and at March 31, 2009, the ratio was 16.2-to-1.0. EBITDAX, which is a non-GAAP measure, is generally defined in the Revolver as our net income before the effects of interest expense, interest income, income tax expense, depreciation depletion and amortization, or DD&A expense, impairments, other similar non-cash charges, exploration expenses, non-cash compensation expense and non-cash hedging activity. For covenant calculation purposes, EBITDAX is further adjusted for distributions received through Penn Virginia’s ownership in PVG and for dividends paid to shareholders. In addition, the financial covenants impose dividend limitation restrictions. The Revolver contains various other covenants that limit our ability to incur 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 March 31, 2009, we were in compliance with all of our covenants under the Revolver.

In the event that we would be in default of our covenants, we could appeal to the banks for a waiver of the covenant default. Should the banks deny our appeal to waive the covenant default, the outstanding borrowings under the Revolver would become payable upon demand and would be reclassified to the current liabilities section of our consolidated balance sheet. The Revolver contains cross-default provisions for default of indebtedness of more than $5.0 million. The Revolver does not contain a subjective acceleration clause.

Convertible Notes, Note Hedges and Warrants. As of March 31, 2009, we had $230.0 million (excluding the discount of $28.5 million) of Convertible Notes outstanding. The Convertible Notes bear interest at a coupon rate of 4.50% per year payable semiannually in arrears on May 15 and November 15 of each year. We do not have a public credit rating for the Convertible Notes.

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 17.3160 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. Holders of Convertible Notes may convert their Convertible Notes at their option prior to the close of business on the business day immediately preceding September 15, 2012 only under the following circumstances: (i) during any fiscal quarter if the last reported sale price per share of common stock for at least 20 trading days (whether or not consecutive) in the 30 consecutive trading days ending on the last trading day of the immediately preceding fiscal quarter is greater than or equal to 130% of the then applicable conversion price on each such trading day; (ii) during the five business day period after any ten consecutive trading day period in which the trading price per $1,000 principal amount of the Convertible Notes for each day of such period was less than 98% of the product of the last reported sale price per share of common stock and the applicable conversion rate on each such day; or (iii) upon the occurrence of certain corporate events set forth in the indenture governing the Convertible Notes. On and after September 15, 2012 until the close of business on the third business day immediately preceding November 15, 2012, holders of the Convertible Notes may convert their Convertible Notes at any time, regardless of the foregoing circumstances.

The holders of the Convertible Notes who convert their Convertible Notes in connection with a make-whole fundamental change, as defined in the indenture governing the Convertible Notes, may be entitled to an increase in the conversion rate as specified in the indenture governing the Convertible Notes. Additionally, in the event of a fundamental change, as defined in the indenture governing the Convertible Notes, the holders of the Convertible Notes may require us to purchase all or a portion of their Convertible Notes at a purchase price equal to 100% of the principal amount of the Convertible Notes, plus accrued and unpaid interest, if any.

The Convertible Notes are our unsecured senior subordinated obligations, ranking junior in right of payment to any of our senior indebtedness and to any of our secured indebtedness to the extent of the value of the assets securing such indebtedness and equal in right of payment to any of our future unsecured senior subordinated indebtedness. The Convertible Notes will rank senior in right of payment to any of our future junior subordinated indebtedness and will structurally rank junior to all existing and future indebtedness of our subsidiaries.

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In connection with the sale of the Convertible Notes, we entered into convertible note hedge transactions, or the Note Hedges, with respect to shares of our common stock with affiliates of certain of the underwriters of the Convertible Notes (collectively, the “Option Counterparties”). The Note Hedges cover, subject to anti-dilution adjustments, the net shares of our common stock that would be deliverable to converting noteholders in the event of a conversion of the Convertible Notes. In December 2007, we paid an aggregate amount of $18.6 million of the net proceeds from the sale of the Convertible Notes for the cost of the Note Hedges (after such cost was offset by the proceeds of the Warrants described below).

We also entered into separate warrant transactions, or the Warrants, whereby we sold to the Option Counterparties warrants to acquire, subject to anti-dilution adjustments, approximately 3,982,680 shares of our common stock at an exercise price of $74.25 per share. In December 2007, we received proceeds of $18.2 million resulting from this sale. Upon exercise of the Warrants, we will deliver shares of our common stock equal to the difference between the then market price and the strike price of the Warrants.

If the market value per share of our common stock at the time of conversion of the Convertible Notes is above the strike price of the Note Hedges, the Note Hedges entitle us to receive from the Option Counterparties net shares of our common stock (and cash for any fractional share cash amount) based on the excess of the then current market price of our common stock over the strike price of the Note Hedges. Additionally, if the market price of our common stock at the time of exercise of the Warrants exceeds the strike price of the Warrants, we will owe the Option Counterparties net shares of our common stock (and cash for any fractional share cash amount), not offset by the Note Hedges, in an amount based on the excess of the then current market price of our common stock over the strike price of the Warrants.

Interest Rate Swaps. We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver until December 2010. The notional amounts of the Interest Rate Swaps total $50.0 million, or approximately 13% of our total long-term debt outstanding under the Revolver at March 31, 2009. We will pay a weighted average fixed rate of 5.34% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the Interest Rate Swaps were recorded as interest expense. During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value and losses for the Interest Rate Swaps will be recognized as a component of derivatives in the income statement. After considering the applicable margin of 2.75% in effect as of March 31, 2009, the total interest rate on the $50.0 million portion of Revolver borrowings covered by the Interest Rate Swaps was 8.09% at March 31, 2009.

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 March 31, 2009, net of outstanding borrowings of $595.1 million and letters of credit of $1.6 million, PVR had remaining borrowing capacity of $203.3 million on the PVR Revolver. 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. In the three months ended March 31, 2009, PVR incurred commitment fees of $0.1 million on the unused portion of the PVR Revolver. The interest rate under the PVR Revolver fluctuates based on the ratio of PVR’s total indebtedness-to-EBITDA. 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 LIBOR plus an applicable margin ranging from 1.75% to 2.75% if PVR selects the LIBOR-based borrowing option. At March 31, 2009, the weighted average interest rate on borrowings outstanding under the PVR Revolver was approximately 3.75%. PVR does not have a public credit rating for the PVR Revolver.

The financial covenants under the PVR Revolver require PVR not to exceed specified ratios. PVR is required to maintain a debt-to-consolidated EBITDA ratio of less than 5.25-to-1.0 and at March 31, 2009, the ratio was 3.37-to-1.0. PVR is also required to maintain a consolidated EBITDA-to-interest expense ratio of greater than 2.5-to-1.0 and at March 31, 2009, the ratio was 6.31-to-1.0. EBITDA, which is a non-GAAP measure, is generally defined in the PVR Revolver as PVR’s net income before the effects of interest expense, interest income, DD&A expense, impairments and other similar charges and non-cash hedging activity. In addition, the PVR Revolver contains various covenants that limit PVR’s ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of PVR’s business or enter into a merger or sale of PVR’s

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assets, including the sale or transfer of interests in its subsidiaries. As of March 31, 2009, PVR was in compliance with all of its covenants under the PVR Revolver.

In the event that PVR would be in default of its covenants, PVR could appeal to the banks for a waiver of the covenant default. Should the banks deny PVR’s appeal to waive the covenant default, the outstanding borrowings under the PVR Revolver would become payable upon demand and would be reclassified to the current liabilities section of our consolidated balance sheet. The PVR Revolver contains cross-default provisions for default of indebtedness of more than $7.5 million. The PVR Revolver does not contain a subjective acceleration clause. The PVR Revolver prohibits PVR from making distributions to its partners if any potential default, or event of default, as defined in the PVR Revolver, occurs or would result from the distributions.

PVR Interest Rate Swaps. PVR has entered into the PVR Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. During the first quarter of 2009, PVR discontinued hedge accounting for all of the PVR Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the PVR Interest Rate Swaps are recognized in earnings currently. Until March 2010, the notional amounts of the PVR Interest Rate Swaps total $310.0 million, or approximately 52% of PVR’s total long-term debt outstanding as of March 31, 2009, with PVR paying a weighted average fixed rate of 3.54% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From March 2010 to December 2011, the notional amounts of the PVR Interest Rate Swaps total $250.0 million with PVR paying a weighted average fixed rate of 3.37% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From December 2011 to December 2012, the notional amounts of the Interest Rate Swaps total $100.0 million, with PVR paying a weighted average fixed rate of 2.09% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. The PVR Interest Rate Swaps extend one year past the maturity of the current PVR Revolver. The PVR Interest Rate Swaps have been entered into with seven financial institution counterparties, with no counterparty having more than 24% of the open positions. After considering the applicable margin of 1.75% in effect as of March 31, 2009, the total interest rate on the $310.0 million portion of PVR Revolver borrowings covered by the PVR Interest Rate Swaps was 5.29% at March 31, 2009.

We and PVR monitor changes in our and its counterparties and are not aware of any specific concerns regarding our or PVR’s counterparties’ ability to make payments under any of the Interest Rate Swaps or PVR Interest Rate Swaps.

Future Capital Needs and Commitments

Subject to commodity prices and the availability of capital, we are committed to expanding our oil and gas operations over the next several years through a combination of development, exploration and acquisition of new properties. We have a portfolio of assets which includes primarily low risk, moderate to potentially higher return development projects in East Texas, the Mid-Continent, Appalachia and Mississippi, with higher risk, potentially higher return exploration prospects in south Louisiana and south Texas. We expect to continue to execute a program dominated by development drilling and, to a lesser extent, exploration drilling, supplemented periodically with property and reserve acquisitions.

For the remainder of 2009, we anticipate making oil and gas segment capital expenditures of approximately $45.0 million to $55.0 million. In addition to our capital expenditures and the $9.9 million we included in exploration expense in the first quarter of 2009, we could incur up to $14.4 million of additional cost for rig delay and standby charges, which would also be recorded as exploration expense as incurred. These capital and other rig delay-related expenditures are expected to be primarily funded from internally generated sources of cash, including cash distributions received from PVG and PVR, supplemented by Revolver borrowings as needed. At March 31, 2009, we had $59.7 million of borrowing capacity under the Revolver. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on industry conditions, cash flows provided by operating activities and the availability of capital. We believe our cash flow from operating activities and sources of debt financing are sufficient to fund our 2009 planned oil and gas capital expenditure program.

For future periods, we continue to assess funding needs for our growth opportunities in the context of our presently available debt capacity. We expect to use a combination of cash flows from operating activities, borrowings under the Revolver, issuances of additional debt and equity securities and sale of non-core assets to fund

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our growth. However, if the current disruptions in the worldwide credit, capital and commodities markets continue into the future, our ability to grow will likely remain limited. We cannot be certain that we will be able to issue our debt or equity securities on terms or in the amounts that we anticipate, or at all, 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. We believe our portfolio of assets provides us with opportunities for organic growth which could require capital in excess of our internal sources. We expect to rely less on the Revolver to fund our capital needs, replaced by other sources of debt and equity capital and non-core asset sales as needed.

Currently, PVG has no capital requirements. In the future, we may decide to facilitate PVR acquisitions and other capital expenditures by the issuance of PVG debt or equity if market conditions are favorable to such an issuance.

PVR believes that its short-term cash requirements for operating expenses and quarterly distributions to PVG, as the owner of PVR’s general partner, and unitholders will be funded through operating cash flows. PVR also believes that its remaining borrowing capacity of $203.3 million will be sufficient for its capital needs and commitments for the remainder of 2009. For the remainder of 2009, PVR anticipates making capital expenditures, excluding acquisitions, of approximately $47.0 to $53.0 million. The majority of the 2009 capital expenditures are expected to be incurred in the PVR natural gas midstream segment. 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.

Part of PVR’s long-term strategy is to increase cash available for distribution to PVR’s unitholders by making acquisitions and other capital expenditures. PVR’s ability to make these acquisitions and other capital expenditures in the future will depend largely on the availability of debt financing and on PVR’s ability to periodically use equity financing through the issuance of new common units. Future financing will depend on various factors, including prevailing market conditions, interest rates and PVR’s financial condition and credit rating.

The current disruptions in the global financial and commodities markets and the general economic climate have made access to equity and debt capital markets very difficult since late in 2008. While signs of improvement in these markets have started to arise in 2009, with issuances of debt and equity securities by other publicly traded partnerships, the short-term outlook remains uncertain with respect to PVR’s ability to access the capital markets on acceptable terms. If the situation worsens and PVR is unable to access the capital markets for an extended period, PVR’s ability to make acquisitions and other capital expenditures, as well as PVR’s ability to increase or sustain cash distributions to its limited partners and to PVG, the owner of PVR’s general partner, will likely become limited. If additional financing is required, there are no assurances that it will be available, or if available, that it can be obtained on terms favorable to PVR or not dilutive to PVR’s future earnings.

Results of Operations

Selected Financial Data—Consolidated

The following table sets forth a summary of certain consolidated financial data for the three months ended March 31, 2009 and 2008:

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	Three Months Ended March 31,
	2009			2008
	(in thousands, except per share data)
Revenues	$	199,160		$	249,135
Expenses		206,599			189,002
Operating income (loss)	$	(7,439	)	$	60,133
Net income (loss) attributable to Penn Virginia Corporation	$	(7,209	)	$	3,194
Earnings (loss) per share, basic	$	(0.17	)	$	0.08
Earnings (loss) per share, diluted	$	(0.17	)	$	0.07
Cash flows provided by operating activities	$	103,019		$	66,152

Operating income (loss) decreased by $67.6 million in the three months ended March 31, 2009 compared to the same period of 2008 primarily due to a $27.7 million decrease in natural gas revenues, an $18.5 million increase in DD&A expense and a $16.6 million increase in exploration expense. These changes were partially offset by a $6.7 million increase in coal royalties revenues.

Net income (loss) decreased by $10.4 million in the three months ended March 31, 2009 compared to the same period of 2008 primarily due to the decrease in operating income (loss), partially offset by a $36.2 million increase in derivative income.

The assets, liabilities and earnings of PVG are fully consolidated in our financial statements, with the public unitholders’ interest (23% as of March 31, 2009) reflected as a minority interest in our consolidated financial statements. The assets, liabilities and earnings of PVR are fully consolidated in PVG’s financial statements, with the interest that PVG does not own (61%, after the effect of IDRs, as of March 31, 2009) reflected as a minority interest in PVG’s consolidated financial statements.

Oil and Gas Segment

Three Months Ended March 31, 2009 Compared With the Three Months Ended March 31, 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 March 31, 2009 and 2008:

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	Three Months Ended March 31,					% Change		Three Months Ended March 31,
	2009			2008				2009			2008
Financial Highlights	(in thousands, except as noted)							(per Mcfe) (1)
Revenues
Natural gas	$	52,821		$	80,513	(34	)%	$	4.48		$	8.26
Crude oil		6,328			9,215	(31	)%		37.01			97.00
NGL		3,370			1,868	80	%		22.93			54.94
Other income		2,046			703	191	%
Total revenues		64,565			92,299	(30	)%		4.71			8.77
Expenses
Operating		14,763			14,209	4	%		1.08			1.35
Taxes other than income		4,826			5,858	(18	)%		0.35			0.56
General and administrative		5,124			4,584	12	%		0.37			0.44
Production costs		24,713			24,651	0	%		1.80			2.34
Exploration		21,312			4,680	355	%		1.55			0.44
Impairments		1,196			—	—			0.09			—
Depreciation, depletion and amortization		39,999			26,616	50	%		2.92			2.53
Total expenses		87,220			55,947	56	%		6.36			5.32
Operating income	$	(22,655	)	$	36,352	(162	)%	$	(1.65	)	$	3.45
Production
Natural gas (MMcf)		11,802			9,748	21	%
Crude oil (MBbl)		171			95	80	%
NGL (MBbl)		147			34	332	%
Total production (MMcfe)		13,710			10,522	30	%

(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.

Production. Approximately 86% and 93% of production in the three months ended March 31, 2009 and 2008 was natural gas. Total production increased by 3.2 Bcfe, or 30%, from 10.5 Bcfe in the three months ended March 31, 2008 to 13.7 Bcfe in the same period of 2009, primarily due to increased production in the East Texas, Mid-Continent, Mississippi and Gulf Coast regions.

The following table summarizes total natural gas, crude oil and NGL production and total natural gas, crude oil and NGL revenues by region for the three months ended March 31, 2009 and 2008:

	Natural Gas, Crude Oil and NGL Production		Natural Gas, Crude Oil and NGL Revenues
	Three Months Ended March 31,		Three Months Ended March 31,
Region	2009	2008	2009		2008
	(MMcfe)		(in thousands)
East Texas	3,676	2,757	$	15,919	$	25,525
Appalachia	2,899	2,840		15,000		22,962
Mid-Continent	2,856	1,462		9,945		11,784
Mississippi	2,094	1,806		10,470		15,282
Gulf Coast	2,185	1,657		11,185		16,043
Total	13,710	10,522	$	62,519	$	91,596

The increased production in the East Texas region is primarily due to aggressive drilling and development in the region, as well as contributions from natural gas production in the horizontal Lower Bossier (Haynesville) Shale play. The increase in production in the Mid-Continent region is primarily due to the natural gas production increases from additional drilling in the Granite Wash play in Oklahoma. The increase in production in the Mississippi and Gulf Coast regions is primarily due to new production from wells drilled in the past year.

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Revenues. Natural gas revenues decreased by $27.7 million, or 34%, from $80.5 million in the three months ended March 31, 2008 to $52.8 million in the same period of 2009. Of the $27.7 million decrease, $44.7 million was the result of decreased realized prices for natural gas, partially offset by $17.0 million resulting from increased natural gas production from drilling. Our average realized price received for natural gas decreased by $3.78 per Mcf, or 46%, from $8.26 per Mcf in the three months ended March 31, 2008 to $4.48 per Mcf in the three months ended March 31, 2009.

Crude oil revenues decreased by $2.9 million, or 31%, from $9.2 million in the three months ended March 31, 2008 to $6.3 million in the same period of 2009. Of the $2.9 million decrease, $10.3 million was the result of decreased crude oil prices, partially offset by $7.4 million resulting from increased crude oil production from drilling. Our average realized price received for crude oil decreased by $59.99 per Bbl, or 62%, from $97.00 per Bbl in the three months ended March 31, 2008 to $37.01 per Bbl in the same period of 2009.

NGL revenues increased by $1.5 million, or 80%, from $1.9 million in the three months ended March 31, 2008 to $3.4 million in the same period of 2009. Of the $1.5 million increase, $6.2 million was the result of increased NGL production, primarily due to a new processing plant in the East Texas region, partially offset by $4.7 million resulting from decreased realized prices for NGLs. Our average realized price received for NGLs decreased by $32.01 per Bbl, or 58%, from $54.94 per Bbl in the three months ended March 31, 2008 to $22.93 per Bbl in the same period of 2009.

Effects of Derivatives

Our natural gas and crude oil revenues may change significantly from period to period as a result of changes in commodity prices or production volumes. As part of our risk management strategy, we use derivative financial instruments to hedge natural gas and, to a lesser extent, oil prices.

Because we do not apply hedge accounting to our commodity derivatives or Interest Rate Swaps, we record realized and mark-to-market gains and losses in the derivatives line of our consolidated statements of income rather than deferring such amounts in accumulated other comprehensive income. See Note 6, “Derivative Instruments,” in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements,” for a tabular schedule of the 2009 and 2008 effects of derivatives on our consolidated statements of income.

For the derivatives related to the oil and gas segment, we received $16.3 million and $0.6 million in cash settlements in the three months ended March 31, 2009 and 2008. The following table reconciles natural gas and crude oil revenues to realized prices, as adjusted for derivative activities for the three months ended March 31, 2009 and 2008:

	Three Months Ended March 31,
	2009		2008		2009		2008
	(in thousands)				(per Mcf)
Natural gas revenues before impact of derivatives	$	52,821	$	80,513	$	4.48	$	8.26
Cash settlements on natural gas derivatives (1)		14,962		569		1.27		0.06
Natural gas revenues, adjusted for derivatives	$	67,783	$	81,082	$	5.75	$	8.32
	(in thousands)				(per Bbl)
Crude oil revenues before impact of derivatives	$	6,328	$	9,215	$	37.01	$	97.00
Cash settlements on crude oil derivatives (1)		1,350		—		7.89		—
Crude oil revenues, adjusted for derivatives	$	7,678	$	9,215	$	44.90	$	97.00

(1) As a result of the original forecasted transactions settling, we mark-to-market our derivative positions and record the gains or losses on the derivatives line of our consolidated statements of income. These cash settlements relate to those derivative gains or losses.

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Other income. Other income increased by $1.3 million, or 191%, from $0.7 million in the three months ended March 31, 2008 to $2.0 million in the same period of 2009, primarily due to a royalty recovery from a lessee in the Appalachia region.

Expenses. Aggregate operating costs and expenses increased primarily due to increased operating, general and administrative, exploration and DD&A expenses. We also incurred impairment charges of $1.2 million in the three months ended March 31, 2009.

Operating expenses increased by $0.6 million, or 4%, from $14.2 million, or $1.35 per Mcfe, in the three months ended March 31, 2008 to $14.8 million, or $1.08 per Mcfe, in the same period of 2009. This increase is due primarily to increased compressor rentals and increased processing fees, both of which were driven by the increase in production and general growth in infrastructure.

Taxes other than income decreased by $1.1 million, or 18%, from $5.9 million in the three months ended March 31, 2008 to $4.8 million in the same period of 2009, primarily due to decreased severance taxes paid resulting from decreased natural gas, crude oil and NGL prices.

General and administrative expenses increased by $0.5 million, or 12%, from $4.6 million in the three months ended March 31, 2008 to $5.1 million in the same period of 2009, primarily due to increased staffing costs in the East Texas and Mid-Continent regions.

Exploration expenses in the three months ended March 31, 2009 and 2008 consisted of the following:

	Three Months Ended March 31,
	2009		2008
	(in thousands)
Dry hole costs	$	1,689	$	718
Geological and geophysical		738		680
Unproved leasehold		8,702		2,834
Other		319		448
Standby rig charges		9,864		—
Total	$	21,312	$	4,680

Exploration expenses increased by $16.6 million, or 355%, from $4.7 million in the three months ended March 31, 2008 to $21.3 million in the same period of 2009. Dry hole costs increased by $1.0 million, or 135%, from $0.7 million in the three months ended March 31, 2008 to $1.7 million in the same period of 2009. This increase was due to the write-off of one well in the Woodford Shale play in the Mid-Continent region. Unproved leasehold expenses increased by $5.9 million, or 207%, from $2.8 million in the three months ended March 31, 2008 to $8.7 million in the same period of 2009. This increase was primarily due to increased amortization of unproved properties located in the East Texas and Mid-Continent regions.

Costs related to unproved properties are capitalized and periodically evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management. We continue to experience an increase in lease expirations and unproved leasehold expense caused by current economic conditions which have impacted our future drilling plans thereby increasing the amount of expected lease expirations. Effective January 1, 2009, we changed our accounting process to amortize additional insignificant unproved properties over the average estimated life of the leases versus amortizing some leases and assessing other leases on an occurrence basis. As a result of amortizing additional leases, we recorded additional unproved leasehold expense, which is included in exploration expense on the consolidated statements of income, of $6.3 million in the three months ended March 31, 2009. The impact of this change on net income for the three months ended March 31, 2009 was a decrease of $3.9 million, net of income taxes. The impact of this change decreased basic and diluted earnings per share for the three months ended March 31, 2009 by $0.09.

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In the first quarter of 2009, our oil and gas segment opted to defer drilling of many wells due to unfavorable economic conditions. As a result, we amended certain drilling rig contracts to delay commencement of drilling until January 2010. In the first quarter of 2009, we incurred a liability of approximately $9.9 million for lump sum delay fees, minimum daily standby fees and demobilization fees expected to be paid during the standby period. These fees and costs are recorded in accounts payable and accrued liabilities on the consolidated balance sheets and as exploration expense on the 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 $14.8 million for 2009.

We recorded impairment charges related to our oil and gas segment properties of $1.2 million. These charges were primarily related to market declines in the spot and future oil and gas prices.

DD&A expenses increased by $14.4 million, or 50%, from $26.6 million in the three months ended March 31, 2008 to $40.0 million in the same period of 2009, primarily due to the 30% increase in equivalent production and higher depletion rates in 2009 when compared to 2008. Our average depletion rate increased by $0.39 per Mcfe, or 15%, from $2.53 per Mcfe in the three months ended March 31, 2008 to $2.92 per Mcfe in the three months ended March 31, 2009 primarily due to increased development costs and the sale of and reduced contributions from properties with lower depletion rates.

PVR Coal and Natural Resource Management Segment

Three Months Ended March 31, 2009 Compared With the Three Months Ended March 31, 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 March 31, 2009 and 2008:

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	Three Months Ended March 31,
	2009			2008			Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	30,630		$	23,962		28	%
Coal services		1,888			1,862		1	%
Timber		1,317			1,584		(17	)%
Oil and gas royalty		703			1,234		(43	)%
Other		3,714			1,652		125	%
Total revenues		38,252			30,294		26	%
Expenses
Coal royalties		1,224			2,512		(51	)%
Other operating		883			231		282	%
Taxes other than income		425			371		15	%
General and administrative		3,352			3,185		5	%
Depreciation, depletion and amortization		7,394			6,413		15	%
Total expenses		13,278			12,712		4	%
Operating income	$	24,974		$	17,582		42	%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,748			7,640		15	%
Average royalties revenues per ton ($/ton)	$	3.50		$	3.14		12	%
Less royalties expense per ton ($/ton)		(0.14	)		(0.33	)	(58	)%
Average net coal royalties per ton ($/ton)	$	3.36		$	2.81		20	%

Revenues. Coal royalties revenues increased by $6.6 million, or 28%, from $24.0 million in the three months ended March 31, 2008 to $30.6 million in the same period of 2009, primarily due to the increase in the average sales price of coal received by lessees and the overall increase in production from certain subleased properties. Coal royalties expense decreased by $1.3 million, or 51%, from $2.5 million in the three months ended March 31, 2008 to $1.2 million in the same period of 2009, primarily due to decreased production from certain subleased properties in the Central Appalachian region. The average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, increased by $0.55 per ton, or 20%, from $2.81 per ton in the three months ended March 31, 2008 to $3.36 per ton in the same period of 2009. The increase in average net coal royalty per ton was due primarily to the higher royalty revenues per ton received from PVR’s lessees in all regions.

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The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the three months ended March 31, 2009 and 2008:

	Coal Production		Coal Royalties Revenues						Coal Royalties Per Ton
	Three Months Ended March 31,		Three Months Ended March 31,						Three Months Ended March 31,
Region	2009	2008	2009			2008			2009			2008
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	4,658	4,811	$	21,683		$	18,579		$	4.66		$	3.86
Northern Appalachia	1,057	674		1,951			1,134			1.85			1.68
Illinois Basin	1,261	1,033		3,241			1,938			2.57			1.88
San Juan Basin	1,772	1,122		3,755			2,311			2.12			2.06
Total	8,748	7,640	$	30,630		$	23,962		$	3.50		$	3.14
Less coal royalties expense (1)				(1,224	)		(2,512	)		(0.14	)		(0.33	)
Net coal royalties revenues			$	29,406		$	21,450		$	3.36		$	2.81

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

Coal production in the Central Appalachian region remained relatively constant from the three months ended March 31, 2008 to the same period of 2009. Coal production in the Northern Appalachian region increased by 0.4 million tons, or 57%, from 0.7 million tons in the three months ended March 31, 2008 to 1.1 million tons in the same period of 2009. This increase was due primarily to increased production on PVR’s longwall mining operations in the region. Coal production in the Illinois Basin region increased by 0.3 million tons, or 22%, from 1.0 million tons in the three months ended March 31, 2008 to 1.3 million tons in the same period of 2009. This increase was due primarily to more efficient mining conditions by certain lessees in Western Kentucky. Coal production in the San Juan Basin region increased by 0.7 million tons, or 58%, from 1.1 million tons in the three months ended March 31, 2008 to 1.8 million tons in the same period of 2009. This increase was due primarily to new mining contracts obtained by lessees in the region.

Coal services revenues remained relatively constant from the three months ended March 31, 2008 to the same period of 2009. Timber revenues decreased by $0.3 million, or 17%, from $1.6 million in the three months ended March 31, 2008 to $1.3 million in the same period of 2009 primarily due to decreased harvesting of timber resulting from weakened market conditions. Oil and gas royalty revenues decreased by $0.5 million, or 43%, from $1.2 million in the three months ended March 31, 2008 to $0.7 million in the same period of 2009, primarily due to decreased natural gas prices. Other revenues increased by $2.0 million, or 125%, from $1.7 million in the three months ended March 31, 2008 to $3.7 million in the same period of 2009, primarily due to forfeited minimum rentals that PVR recorded as revenue in the three months ended March 31, 2009.

Expenses.Other operating expenses increased by $0.7 million, or 282%, from $0.2 million in the three months ended March 31, 2008 to $0.9 million in the same period of 2009, primarily due to increased core drilling expenses related to coal reserves that PVR acquired in May 2008, and increased coal exploration expenses, which were due to coal reserve study expenses incurred in the three months ended March 31, 2009. Both taxes other than income and general and administrative expenses remained relatively constant from the three months ended March 31, 2008 to the same period of 2009. DD&A expenses increased by $1.0 million, or 15%, from $6.4 million in the three months ended March 31, 2008 to $7.4 million in the same period of 2009, primarily due to higher depletion expenses resulting from increased overall coal production.

PVR Natural Gas Midstream Segment

Three Months Ended March 31, 2009 Compared With the Three Months Ended March 31, 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 March 31, 2009 and 2008:

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	Three Months Ended March 31,
	2009			2008			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	81,194		$	61,667		32	%
Natural gas liquids		30,606			56,197		(46	)%
Condensate		2,903			6,216		(53	)%
Gathering, processing and transportation fees		2,676			968		176	%
Total natural gas midstream revenues (1)		117,379			125,048		(6	)%
Equity earnings in equity investment		1,119			—		—
Producer services		9			1,472		(99	)%
Total revenues		118,507			126,520		(6	)%
Expenses
Cost of midstream gas purchased (1)		100,620			99,697		1	%
Operating		6,783			4,050		67	%
Taxes other than income		798			701		14	%
General and administrative		4,244			3,333		27	%
Depreciation and amortization		9,109			5,087		79	%
Total operating expenses		121,554			112,868		8	%
Operating income	$	(3,047	)	$	13,652		(122	)%
Operating Statistics
System throughput volumes (MMcf)		32,280			17,287		87	%
System throughput volumes (MMcfd)		359			190		89	%
Gross margin	$	16,759		$	25,351		(34	)%
Impact of derivatives		3,792			(8,414	)	(145	)%
Gross margin, adjusted for impact of derivatives	$	20,551		$	16,937		21	%
Gross margin ($/Mcf)	$	0.52		$	1.47		(65	)%
Impact of derivatives ($/Mcf)		0.12			(0.49	)	(124	)%
Gross margin, adjusted for impact of derivatives	$	0.64		$	0.98		(35	)%

(1) In the three months ended March 31, 2009, PVR recorded $21.2 million of natural gas midstream revenue and $21.2 million for the cost of midstream gas purchased related to the purchase of natural gas from Penn Virginia Oil & Gas, L.P. 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 the 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 included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to PVR’s gas processing plants. Cost of midstream gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts.

Natural gas midstream revenues decreased by $7.6 million, or 6%, from $125.0 million in the three months ended March 31, 2008 to $117.4 million in the same period of 2009. Cost of midstream gas purchased increased by $0.9 million, or 1%, from $99.7 million in the three months ended March 31, 2008 to $100.6 million in the same period of 2009. The gross margin decreased by $8.6 million, or 34%, from $25.4 million in the three months ended March 31, 2008 to $16.8 million in the same period of 2009. The gross

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margin decrease was a result of decreased commodity pricing, partially offset by margins earned from increased system throughput volume production. The increased volume was from areas exposed to both commodity prices and fixed fees. There were lower frac spreads during the three months ended March 31, 2009 compared to the same period of 2008. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis.

System throughput volumes increased by 169 MMcfd, or 89%, from 190 MMcfd in the three months ended March 31, 2008 to 359 MMcfd in the same period of 2009. This increase in throughput volumes is due primarily 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 March 31, 2009, PVR generated a majority of the 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 6—“Derivative Instruments,” in the Notes to Condensed Consolidated Financial Statements in Item 1, “Financial Statements,” for a description of PVR’s derivatives program. Adjusted for the impact of PVR’s commodity derivative instruments, PVR’s gross margin increased by $3.7 million, or 21%, from $16.9 million in the three months ended March 31, 2008 to $20.6 in the same period of 2009. On a per Mcf basis, the gross margin, adjusted for the impact of PVR’s commodity derivatives, decreased by $0.34 Mcf, or 35%, from $0.98 per Mcf in the three months ended March 31, 2008 to $0.64 in the same period of 2009. These changes are primarily due to the contribution of fixed fee volumes at the Crossroads plant and from the Lone Star acquisition.

Equity Earnings in Equity Investment. This increase is 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 April 2008.

Producer Services Revenues. Producer services revenues decreased by $1.5 million, or 99%, from $1.5 million in the three months ended March 31, 2008 to less than $0.1 million in the same period of 2009 primarily due to the relative changes in natural gas indices from the purchasing and selling of natural gas.

Expenses. Total operating costs and expenses increased primarily due to increased operating expenses, taxes other than income, general and administrative expenses and depreciation and amortization.

Operating expenses increased by $2.7 million, or 67%, from $4.1 million in the three months ended March 31, 2008 to $6.8 million in the same period of 2009. The increase in operating expenses was due primarily to increased costs for chemicals and lubricants, repairs and maintenance expenses and increased compressor rentals, all of which were driven by 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 March 31, 2008 to the same period of 2009. General and administrative expenses increased by $0.9 million, or 27%, from $3.3 million in the three months ended March 31, 2008 to $4.2 million in the same period of 2009, primarily due to increased staffing costs. Depreciation and amortization expenses increased by $4.0 million, or 79%, from $5.1 million in the three months ended March 31, 2008 to $9.1 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.

Other and Eliminations

Other and eliminations primarily represents corporate functions such as interest expense, income tax expense, oil and gas segment derivatives and elimination of intercompany sales.

Corporate Operating Expenses. Corporate operating expenses primarily consist of general and administrative expenses other than from our oil and gas segment, the PVR coal and natural resource management segment and the PVR natural gas midstream segment. Corporate operating expenses decreased by $0.8 million, or 10%, from $7.5 million in the three months ended March 31, 2008 to $6.7 million in the same period of 2009. This decrease was

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primarily due to consulting costs that were incurred in the three months ended March 31, 2008 and due to decreased incentive compensation paid in the first quarter of 2009 as compared to the same period of 2008.

Interest Expense. Our consolidated interest expense increased by $1.8 million, or 16%, from $10.7 million in the three months ended March 31, 2008 to $12.5 million in the same period of 2009. Our consolidated interest expense for the three months ended March 31, 2009 and 2008 is comprised of the following:

	Three Months Ended March 31,
Source	2009			2008
	(in thousands)
Penn Virginia borrowings	$	(6,812	)	$	(6,605	)
Penn Virginia capitalized interest		364			814
Penn Virginia interest rate swaps		(438	)		(24	)
PVR borrowings		(4,868	)		(5,687	)
PVR capitalized interest		77			488
PVR interest rate swaps		(825	)		267
Total interest expense	$	(12,502	)	$	(10,747	)

Total interest expense related to our borrowings, capitalized interest and Interest Rate Swaps increased by $1.1 million, or 18%, from $5.8 million in the three months ended March 31, 2008 to $6.9 million in the same period of 2009. This increase in interest expense is due primarily to the increase in our average debt balance, which increased from $374.5 million in the three months ended March 31, 2008 to $594.5 million in the same period of 2009. Our oil and gas segment capitalized $0.4 million and $0.8 million in the three months ended March 31, 2009 and 2008. Both the borrowings and the capitalized interest for these periods were related to our oil and gas segment’s drilling program and unproved properties where it is anticipated exploratory and development testing will occur.

The increase in PVR’s interest expense is primarily due to the effects of the PVR Interest Rate Swap settlements in a decreased LIBOR environment. These settlements were partially mitigated by the decrease in PVR’s effective interest rate excluding the effects of the PVR Interest Rate Swaps, which decreased from 5.0% in the three months ended March 31, 2008 to 3.3% in the same period of 2009. PVR capitalized $0.5 million in interest costs in the three months ended March 31, 2008 primarily related to the construction of the Spearman and Crossroads plants. In connection with periodic settlements, we recognized $0.8 million in net hedging losses in the three months ended March 31, 2009 and $0.3 million in net hedging gains in the three months ended March 31, 2008 on the PVR Interest Rate Swaps in interest expense.

Derivatives. Our results of operations and operating cash flows were impacted by changes in market prices for NGLs, crude oil and natural gas prices. Commodity markets are volatile, and as a result, our hedging activity results can vary significantly. Our results of operations are affected by the volatility of changes in fair value, which fluctuate with changes in natural gas, crude oil and NGL prices. 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 December 31, 2008.

PVR determines the fair values of its commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties for derivatives in an asset position, and our own credit risk derivatives in a liability position, in accordance with SFAS No. 157.

Consolidated derivative gains were $10.3 million in the three months ended March 31, 2009. Consolidated derivative losses were $25.9 million in the three months ended March 31, 2008. These gains and losses were due primarily to changes in fair value. Cash received for settlements totaled $19.1 million in the three months ended March 31, 2009 and cash paid for settlements totaled $9.0 million in the three months ended March 31, 2008.

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Our consolidated derivative activity for the three months ended March 31, 2009 and 2008 is summarized below:

	Three Months Ended March 31,
	2009			2008
	(in thousands)
Oil and gas segment unrealized derivative gain (loss)	$	1,104		$	(34,246	)
Oil and gas segment realized gain		16,312			569
PVR unrealized derivative gain (loss)		(9,997	)		17,298
PVR realized gain (loss)		2,836			(9,522	)
Consolidated derivative gain (loss)	$	10,255		$	(25,901	)

Noncontrolling Interest. Noncontrolling interest primarily represents PVR’s net income allocated to the limited partner units owned by the public. Net income attributable to the noncontrolling interest reduced our consolidated income from operations by $3.7 million and $20.0 million in the three months ended March 31, 2009 and 2008. The decrease in noncontrolling interest for the three months ended March 31, 2009 compared to the same period of 2008 was primarily due to the decrease in PVR’s net income from $34.5 million in the three months ended March 31, 2008 to $9.5 million in the same period of 2009.

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. We consider the following to be the most critical accounting policies which involve the judgment of our management.

Oil and Gas Reserves

The estimates of oil and gas reserves are the single most critical estimate included in our consolidated financial statements. Reserve estimates become the basis for determining depletive write-off rates, recoverability of historical cost investments and the fair value of properties subject to potential impairments. There are many uncertainties inherent in estimating crude oil and natural gas reserve quantities, including projecting the total quantities in place, future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are less precise than those of producing properties due to the lack of a production history. Accordingly, these estimates are subject to change as additional information becomes available.

Proved reserves are the estimated quantities of crude oil, condensate and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those reserves that are expected to be recovered from new wells or undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

There are several factors which could change our estimates of oil and gas reserves. Significant rises or declines in product prices could lead to changes in the amount of reserves as production activities become more or less economical. An additional factor that could result in a change of recorded reserves is the reservoir decline rates differing from those assumed when the reserves were initially recorded. Estimation of future production and development costs is also subject to change partially due to factors beyond our control, such as energy costs and inflation or deflation of oil field service costs. Additionally, we perform impairment tests pursuant to SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, when significant events occur, such as a market move to a lower price environment or a material revision to our reserve estimates. For the three months ended March 31, 2009, we recorded impairment charges related to our oil and gas segment properties of $1.2 million. See Note 9—“Impairments and Unproved Leasehold Expense” in the Notes to Consolidated Financial

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Statements in Item 1, “Financial Statements,” for a detailed description of the impairment of our oil and gas properties.

Income Taxes. We recognized an income tax benefit of $4.6 million for the three months ended March 31, 2009 as compared to an income tax expense of $2.6 million for the same period of 2008. The income tax benefit is a direct result of a loss for the period and we expect to recognize any operating loss tax benefits created in 2009 by amending prior year tax returns. The effective tax rate for both periods was relatively consistent.

Oil and Gas Properties

We use the successful efforts method to account for our oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. Geological and geophysical costs, delay rentals and costs to drill exploratory wells that do not discover proved reserves are expensed as oil and gas exploration. We will carry the costs of an exploratory well as an asset if the well found a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain projects, it may take us more than one year to evaluate the future potential of the exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe that they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis.

A portion of the carrying value of our oil and gas properties is attributable to unproved properties. At March 31, 2009, the costs attributable to unproved properties were $148.0 million. Unproved properties whose acquisition costs are not relatively significant are amortized in the aggregate over the lesser of five years or the average remaining lease term. As exploration work progresses and the reserves on significant properties are proven, capitalized costs of these properties will be subject to depreciation and depletion. If the exploration work is unsuccessful, the capitalized costs of the properties related to the unsuccessful work will be expensed. The timing of any write-downs of these unproven properties, if warranted, depends upon the nature, timing and extent of future exploration activities and their results.

Oil and Gas Revenues

We record revenues associated with sales of natural gas, crude oil, condensate and NGLs when title passes to the customer. We recognize natural gas sales revenues from properties in which we have an interest with other producers on the basis of our net working interest (“entitlement method of accounting”). Natural gas imbalances occur when we sell more or less than our entitled ownership percentage of total natural gas production. We treat any amount received in excess of our share as deferred revenues. If we take less than we are entitled to take, we record the under-delivery as a receivable. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production, particularly from properties that are operated by our partners. Since the settlement process may take 30 to 60 days following the month of actual production, our financial results include estimates of production and revenues for the related time period. We record any differences, which we do not expect to be significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.

Coal Royalties Revenues

We recognize coal royalties revenues on the basis of tons of coal sold by PVR’s lessees and the corresponding revenues from those sales. Since PVR does not operate any coal mines, it does not have access to actual production and revenues information until approximately 30 days following the month of production. Therefore, our financial results include estimated revenues and accounts receivable for the month of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized.

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Natural Gas Midstream Gross Margin

PVR’s gross margin is the difference between its natural gas midstream revenues and its cost of midstream gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to PVR’s gas processing plants. We recognize revenues from the sale of NGLs and residue gas when PVR sells the NGLs and residue gas produced at its gas processing plants. We recognize gathering and transportation revenues based upon actual volumes delivered. 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.

Due to the time needed to gather information from various purchasers and measurement locations and then calculate volumes delivered, the collection of natural gas midstream revenues and the calculation of the cost of midstream gas purchased may take up to 30 days following the month of production. Therefore, PVR makes accruals for revenues and accounts receivable and the related cost of midstream gas purchased and accounts payable based on estimates of natural gas purchased and NGLs and residue gas sold. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized.

Derivative Activities

From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas, crude oil and NGL price volatility. The derivative financial instruments, which are placed with financial institutions that we believe are acceptable credit risks, take the form of swaps, costless collars and three-way collars. All derivative financial instruments are recognized in our consolidated financial statements at fair value in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. The fair values of our derivative instruments are determined based on discounted cash flows derived from quoted forward prices. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by our board of directors.

During the first quarter of 2009, both we and PVR discontinued hedge accounting for all of our Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for both our and the PVR Interest Rate Swaps are recognized in earnings currently. Our results of operations are affected by the changes in fair value, which fluctuates with changes in interest rates.

Because we do not apply hedge accounting for our commodity derivatives or Interest Rate Swaps, we recognize changes in fair value in earnings currently in the derivatives line on the consolidated statements of income. We have experienced and could continue to experience significant changes in the estimate of unrealized derivative gains or losses recognized due to fluctuations in the value of these commodity derivative contracts. Our results of operations are affected by the volatility of mark-to-market gains and losses and changes in fair value, which fluctuate with changes in natural gas, crude oil and NGL prices. These fluctuations could be significant in a volatile pricing environment. See Note 6—“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.

Depreciation, Depletion and Amortization

We determine depreciation and depletion of oil and gas producing properties by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves. We compute depreciation and amortization of property and equipment using the straight-line balance method over the estimated useful life of each asset as follows:

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	Useful Life
Gathering systems	15-20 years
Compressor stations	5-15 years
Processing plants	15 years
Other property and equipment	3-20 years

PVR depletes coal properties on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by PVR’s own geologists and outside consultants. PVR’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, PVR carries out core-hole drilling activities on its coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. PVR depletes timber using a methodology consistent with the units-of-production method, but that is based on the quantity of timber harvested. PVR determines depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves. When PVR retires or sells an asset, we remove its cost and related accumulated depreciation and amortization from our consolidated balance sheets. We record the difference between the net book value, net of any assumed asset retirement obligation, and proceeds from dispositions as a gain or loss on the sales of property and equipment.

Intangible assets are primarily associated with assumed contracts, customer relationships and rights-of-way. These intangible assets are amortized over periods of up to 20 years, the period in which benefits are derived from the contracts, relationships and rights-of-way, and are combined with property, plant and equipment and are reviewed for impairment under SFAS No. 144.

Fair Value Measurements

We adopted SFAS No. 157,Fair Value Measurements, effective January 1, 2008, for financial assets and liabilities measured on a recurring basis. FASB Staff Position FAS 157-2,Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”), delayed the application of SFAS No. 157 for nonfinancial assets and liabilities to fiscal years and interim periods beginning after November 15, 2008. Prior to the adoption of FSP FAS 157-2, we only applied fair value measurements to our financial assets and liabilities. Effective January 1, 2009, SFAS No. 157 now applies to both financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis.

SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 requires fair value measurements to be classified and disclosed in one of the following three categories:

• Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value.

• Level 2: Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

• Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).

We use the following methods and assumptions to estimate the fair values of certain assets and liabilities:

• Marketable securities: Our marketable securities consist of various publicly traded equities. The fair values are based on quoted market prices, which are Level 1 inputs.

• are based on quoted market prices, which are Level 1 inputs.

• Deferred compensation: The fair values for deferred compensation are based on quoted market prices of the underlying securities, which are Level 1 inputs.

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• Oil and gas segment properties: In accordance with the provisions of SFAS No. 144, oil and gas properties of $5.6 million were written down to their fair value of $4.4 million, resulting in an impairment charge. See Note 9, “Impairments and Unproved Leasehold Expense” for a further description of the impairment charge. The fair value of the oil and gas properties is estimated to be the present value of future net cash flows from the underlying reserves, discounted using a rate derived from a forward strip price and that is commensurate with the risk and remaining life of the asset. This is a Level 3 input.

• Commodity derivative instruments: Both our oil and gas commodity derivatives and PVR’s natural gas midstream segment commodity derivatives utilize three-way collar derivative contracts. PVR also utilizes a combination of costless collar and swap derivative contracts to hedge against the variability in its frac spread. 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 closing prices as of March 31, 2009. PVR determines the fair values of its commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a Level 2 input. See Note 6 – “Derivative Instruments.”

• Interest rate swaps: We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. PVR has entered into the PVR Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. We use an income approach using valuation techniques that connect future cash flows to a single discounted value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these is a Level 2 input. See Note 6—“Derivative Instruments.”

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 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 material impact on its financial condition or results of operations.

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

Recent Accounting Pronouncements

See Note 3 in the Notes to Consolidated Financial Statements for a description of recent accounting pronouncements.

Forward-Looking Statements

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

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

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

• the relationship between natural gas, NGL, 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 differs 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;

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

• hedging results;

• accidents;

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

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

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

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

• other risks set forth in our Annual Report on Form 10-K for the fiscal 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.

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 are exposed are as follows:

• Price Risk

• Interest Rate Risk

• Customer Credit 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 enter into these risk management positions. Sensitivity to these risks has heightened due to the recent deterioration of the global economy, including financial and credit markets.

At March 31, 2009, PVR reported a net commodity derivative asset related to the natural gas midstream segment of $12.9 million that is with two counterparties, which are financial institutions, and is substantially concentrated with one of those counterparties. We reported a net commodity derivative asset related to our oil and gas segment of $42.3 million, 80% of which was concentrated with three 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 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. As a result, our financial results are affected when prices for these commodities fluctuate. Such effects can be significant. Our price risk management program permits the utilization of derivative financial instruments (such as swaps, costless collars and three-way collars) to seek to

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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 are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

Quantities of proved reserves are estimated based on economic conditions in existence in the period of assessment. Lower oil and gas prices may have the impact of shortening the economic lives on certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, thus reducing proved property reserve estimates. If such revisions in the estimated quantities of proved reserves occur, it will have the effect of increasing the rates of DD&A on the affected properties, which would decrease earnings or result in losses through higher DD&A expense. The revisions may also be sufficient enough to cause impairment losses on certain properties that would result in a further non-cash expense to earnings. If natural gas, crude oil and NGL prices decline or we drill uneconomic wells, it is reasonably possible we could have a significant impairment.

The PVR natural gas midstream segment has completed a number of acquisitions in recent years. In conjunction with PVR’s accounting for these acquisitions, it was necessary for PVR to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Changes in operations, further decreases in commodity prices, changes in the business environment or futher deterioriations of market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. If these events occur, it is reasonably possible we could have a significant impairment charge to be recorded in our consolidated statements of income.

In the three months ended March 31, 2009, we reported consolidated net derivative gains of $10.3 million. Because we no longer apply hedge accounting for our commodity derivatives and for our and the PVR Interest Rate Swaps, we recognize changes in fair value in earnings currently in the derivatives line on the 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 6 – “Derivative Instruments” in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements,” for a further description of our and PVR’s derivatives programs.

Oil and Gas Segment

The following tables list our derivative agreements and their fair values as of March 31, 2009:

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		Weighted Average Price						Estimated Fair Value (in thousands)
	Average Volume Per Day	Additional Put Option		Floor		Ceiling
	(in MMBtus)			(per MMBtu)
Natural Gas Costless Collars
Second Quarter 2009	15,000			$	4.25	$	5.70		791
Third Quarter 2009	15,000			$	4.25	$	5.70		633
Fourth Quarter 2009	15,000			$	4.25	$	5.70		(89	)
First Quarter 2010	35,000			$	4.96	$	7.41		(101	)
Second Quarter 2010	30,000			$	5.33	$	8.02		1,077
Third Quarter 2010	30,000			$	5.33	$	8.02		653
Fourth Quarter 2010	30,000			$	5.42	$	8.67		276
First Quarter 2011	30,000			$	5.42	$	8.67		(730	)
	(in MMBtus)			(per MMBtu)
Natural Gas Three-way Collars
Second Quarter 2009	40,000	$	6.38	$	8.75	$	10.79		8,577
Third Quarter 2009	40,000	$	6.38	$	8.75	$	10.79		8,234
Fourth Quarter 2009	30,000	$	6.83	$	9.50	$	13.60		6,358
First Quarter 2010	30,000	$	6.83	$	9.50	$	13.60		5,527
	(in MMBtus)			(per MMBtu)
Natural Gas Swaps
Second Quarter 2009	40,000			$	4.91				4,095
Third Quarter 2009	40,000			$	4.91				2,735
Fourth Quarter 2009	40,000			$	4.91				(105	)
	(Bbl)			(Bbl)
Crude Oil Three-way Collars
Second Quarter 2009	500	$	80.00	$	110.00	$	179.00		1,372
Third Quarter 2009	500	$	80.00	$	110.00	$	179.00		1,326
Fourth Quarter 2009	500	$	80.00	$	110.00	$	179.00		1,261
Settlements to be paid in subsequent period									421
Oil and gas segment commodity derivatives – net asset								$	42,311

We estimate that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, oil and gas segment operating income for the remainder of 2009 would increase or decrease by approximately $28.6 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 4.4 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.

We estimate that a $1.00 per MMBtu increase in the natural gas purchase price would decrease the fair value of the natural gas three-way collars by $23.8 million. We estimate that a $1.00 per MMBtu decrease in the natural gas purchase price would increase the fair value of the natural gas three-way collars by $23.0 million. We estimate that for a $5.00 per barrel increase in the crude oil price, the fair value of the crude oil three-way collar would decrease by $0.1 million. We estimate that for a $5.00 per barrel decrease in the crude oil price, the fair value of the crude oil three-way collar would increase by $0.1 million. These estimated changes exclude potential cash receipts or payments in settling these derivative positions.

PVR Natural Gas Midstream Segment

The following table lists PVR’s open mark-to-market commodity derivative agreements and their fair values as of March 31, 2009:

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	Average Volume Per Day	Weighted Average Price Collars
		Additional Put Option		Put		Call		Fair Value (in thousands)
	(in barrels)			(per barrel)
Crude Oil Three-way Collar
Second Quarter 2009 through Fourth Quarter 2009	1,000	$	70.00	$	90.00	$	119.25	$	4,939
	(in MMBtu)			(per MMBtu)
Frac Spread Collar
Second Quarter 2009 through Fourth Quarter 2009	6,000			$	9.09	$	13.94		5,594
Settlements to be received in subsequent period									2,366
Natural gas midstream segment commodity derivatives – net asset								$	12,899

We estimate that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, natural gas midstream gross margin and operating income for the remainder of 2009 would decrease or increase by approximately $3.7 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, natural gas midstream gross margin and operating income for the remainder of 2009 would increase or decrease by approximately $3.8 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.

We estimate that for a $5.00 per barrel increase in the crude oil price, the fair value of the crude oil three-way collar would decrease by $0.3 million. We estimate that for a $5.00 per barrel decrease in the crude oil price, the fair value of the crude oil three-way collar would increase by $0.2 million. In addition, we estimate 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 $0.2 million. These estimated changes exclude potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of March 31, 2009, we had $390.0 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Interest Rate Swaps to effectively convert the interest rate on $50.0 million of the amount outstanding under the Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 5.34% plus the applicable margin until December 2010. The Interest Rate Swaps are accounted for as cash flow hedges in accordance with SFAS No. 133. 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 March 31, 2009 would cost us approximately $3.4 million in additional interest expense.

As of March 31, 2009, PVR had $595.1 million of outstanding indebtedness under the PVR Revolver, which carries a variable interest rate throughout its term. PVR entered into the PVR Interest Rate Swaps to effectively convert the interest rate on $310.0 million of the amount outstanding under the PVR Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 3.54% plus the applicable margin until March 2010. From March 2010 to December 2011, the notional amounts of the PVR Interest Rate Swaps total $250.0 million with PVR paying a weighted average fixed rate of 3.37% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From December 2011 to December 2012, the notional amounts of the PVR Interest Rate Swaps total $100.0 million, with PVR paying a weighted average fixed rate of 2.09% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. The PVR Interest Rate Swaps extend one year past the maturity of the current PVR Revolver. A 1% increase in short-term interest rates on the floating rate debt outstanding under the PVR Revolver (net of amounts fixed through hedging transactions) as of March 31, 2009 would cost us approximately $2.9 million in additional interest expense.

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. Accordingly, subsequent fair value gains and losses for both our and the PVR Interest Rate Swaps are recognized in earnings currently. Our results of operations are affected by the volatility of changes in fair value, which fluctuates

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with changes in interest rates. These fluctuations could be significant. See Note 6—“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.

Customer Credit Risk

We are exposed to the credit risk of our customers and lessees. Approximately $53.2 million, or 48%, of our consolidated accounts receivable at March 31, 2009 resulted from our oil and gas segment, approximately $43.2 million, or 39%, resulted from the PVR natural gas midstream segment and approximately $14.0 million, or 13%, resulted from the PVR coal and natural resource management segment. Approximately $17.4 million of the PVR natural gas midstream segment’s receivables at March 31, 2009 were related to three customers: Conoco, Inc., Tenaska Marketing Ventures, and Louis Dreyfus Energy Services. Approximately 40% of PVR’s natural gas midstream segment receivables and 16% of our consolidated receivables at March 31, 2009 related to these three natural gas midstream customers. Approximately $12.2 million of our oil and gas segment receivables at March 31, 2009 were related to three customers: Chesapeake Operating, Inc. Crosstex Gulf Coast Marketing Ltd. and Dominion E&P, Inc. Approximately 21% of our oil and gas segment’s receivables and 11% of our consolidated receivables at March 31, 2009 related to these three oil and gas customers. No significant uncertainties related to the collectability of amounts owed to us or PVR exist in regard to these customers.

These customer concentrations increase our exposure to credit risk on our consolidated receivables, since the financial insolvency of any of these customers could have a significant impact on our results of operations. If our customers or PVR’s lessees become financially insolvent, they may not be able to continue to operate or meet their payment obligations. Any material losses as a result of customer defaults could harm and have an adverse effect on our business, financial condition or results of operations. Substantially all of our trade accounts receivable are unsecured.

To mitigate the risks of nonperformance by our customers, we perform ongoing credit evaluations of our existing customers. We monitor individual customer payment capability in granting credit arrangements to new customers by performing credit evaluations, seek to limit credit to amounts we believe the customers can pay and maintain reserves we believe are adequate to cover exposure for uncollectable accounts. As of March 31, 2009, no receivables were collateralized, and we recorded a $1.4 million allowance for doubtful accounts in the PVR natural gas midstream segment.

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 March 31, 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 March 31, 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 6 Exhibits

10.1	Penn Virginia Corporation Sixth Amended and Restated 1999 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on February 23, 2009).
10.2	Form of Agreement for Restricted Stock Unit Awards under 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 February 23, 2009).
10.3	Twelfth Amendment to Amended and Restated Credit Agreement dated as of March 27, 2009 among Penn Virginia Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on March 31, 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:    May 11, 2009	By:	/s/    Frank A. Pici
		Frank A. Pici
		Executive Vice President and Chief Financial Officer

Date:    May 11, 2009	By:	/s/    Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller