Ranger Oil (ROCC) 10-Q 2008 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, 2008

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 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 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 8, 2008, 41,669,114 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, 2008 and 2007	1
	Consolidated Balance Sheets as of March 31, 2008 and December 31, 2007	2
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2008 and 2007	3
	Notes to Consolidated Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.	Controls and Procedures	39
PART II.	Other Information
Item 6.	Exhibits	40

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,
	2008			2007
Revenues
Natural gas	$	80,513		$	56,619
Oil and condensate		11,083			5,104
Natural gas midstream		125,048			95,318
Coal royalties		23,962			25,000
Other		8,529			4,229
Total revenues		249,135			186,270
Expenses
Cost of midstream gas purchased		99,697			79,731
Operating		21,002			14,433
Exploration		4,680			5,070
Taxes other than income		7,395			5,376
General and administrative		17,659			15,051
Depreciation, depletion and amortization		38,569			28,070
Total expenses		189,002			147,731
Operating income		60,133			38,539
Other income (expense)
Interest expense		(9,552	)		(6,727	)
Other		2,331			1,416
Derivatives		(25,901	)		(16,721	)
Income before minority interest and income taxes		27,011			16,507
Minority interest		20,028			9,296
Income tax expense		3,057			2,808
Net income	$	3,926		$	4,403
Net income per share, basic	$	0.09		$	0.12
Net income per share, diluted	$	0.09		$	0.11
Weighted average shares outstanding, basic		41,558			37,594
Weighted average shares outstanding, diluted		41,803			38,316

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, 2008			December 31, 2007
Assets
Current assets
Cash and cash equivalents	$	32,880		$	34,527
Accounts receivable		199,334			179,120
Deferred income taxes		23,488			16,273
Derivative assets		3,806			5,683
Other		11,515			8,469
Total current assets		271,023			244,072
Property and equipment
Oil and gas properties (successful efforts method)		1,616,543			1,525,728
Other property and equipment		878,992			859,380
		2,495,535			2,385,108
Accumulated depreciation, depletion and amortization		(523,049	)		(486,094	)
Net property and equipment		1,972,486			1,899,014
Equity investments		26,001			25,640
Goodwill		7,718			7,718
Intangibles, net		28,067			28,938
Derivative assets		419			310
Other assets		46,765			47,769
Total assets	$	2,352,479		$	2,253,461
Liabilities and Shareholders’ Equity
Current liabilities
Current maturities of long-term debt	$	13,269		$	12,561
Accounts payable and accrued liabilities		207,362			205,127
Derivative liabilities		58,605			43,048
Income taxes payable		—			1,163
Total current liabilities		279,236			261,899
Other liabilities		55,529			54,169
Derivative liabilities		9,589			3,030
Deferred income taxes		203,052			193,950
Long-term debt of the Company		406,000			352,000
Long-term debt of subsidiary		400,479			399,153
Minority interests of subsidiaries		187,153			179,162
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; 41,669,059 and 41,408,497 shares issued and outstanding at March 31, 2008 and December 31, 2007		228			225
Paid-in capital		489,516			485,998
Retained earnings		333,805			332,223
Deferred compensation obligation		1,765			1,608
Accumulated other comprehensive income		(11,684	)		(7,936	)
Treasury stock – 81,858 and 77,924 shares common stock, at cost, on
March 31, 2008 and December 31, 2007		(2,189	)		(2,020	)
Total shareholders’ equity		811,441			810,098
Total liabilities and shareholders’ equity	$	2,352,479		$	2,253,461

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,
	2008			2007
Cash flows from operating activities
Net income	$	3,926		$	4,403
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		38,569			28,070
Commodity derivative contracts:
Total derivative losses		27,009			17,142
Cash received (paid) to settle derivatives		(8,953	)		3,512
Deferred income taxes		2,605			1,965
Minority interest		20,028			9,296
Dry hole and unproved leasehold expense		3,553			4,386
Other		(2,161	)		526
Changes in operating assets and liabilities		(18,424	)		(4,359	)
Net cash provided by operating activities		66,152			64,941
Cash flows from investing activities
Acquisitions, net of cash acquired		(4,740	)		(3,835	)
Additions to property and equipment		(108,662	)		(104,771	)
Other		405			47
Net cash used in investing activities		(112,997	)		(108,559	)
Cash flows from financing activities
Dividends paid		(2,344	)		(2,116	)
Distributions paid to minority interest holders		(13,740	)		(11,020	)
Proceeds from borrowings of the Company		54,000			53,000
Proceeds from borrowings of PVR		25,000			10,000
Repayments of borrowings of PVR		(23,000	)		(5,000	)
Other		5,282			943
Net cash provided by financing activities		45,198			45,807
Net increase (decrease) in cash and cash equivalents		(1,647	)		2,189
Cash and cash equivalents – beginning of period		34,527			20,338
Cash and cash equivalents – end of period	$	32,880		$	22,527
Supplemental disclosures:
Cash paid during the periods for:
Interest (net of amounts capitalized)	$	7,237		$	7,584
Income taxes	$	1,245		$	23

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, 2008

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 exploration, development and production of natural gas and oil in various onshore U.S. 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. Our ownership interests in PVR are held principally through our general partner interest and our 82% limited partner interest in Penn Virginia GP Holdings, L.P. (“PVG”), a publicly traded limited partnership. PVG owns an approximately 42% limited partner interest in PVR and 100% of the general partner of PVR, which holds a 2% general partner interest in PVR.

We are engaged in three primary business segments: (1) oil and gas, (2) coal and natural resource management and (3) natural gas midstream. We directly operate our oil and gas segment. PVR operates our coal and natural resource management and natural gas midstream segments. Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. Because PVG controls the general partner of PVR, the financial results of PVR are included in PVG’s 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 was formed by Penn Virginia in 2001 and it is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. PVR completed its initial public offering (the “PVR IPO”) in October 2001. PVG completed its initial public offering (the “PVG IPO”) in December 2006, selling approximately 18% of its outstanding units to the public and using the proceeds from the offering to purchase newly issued common and Class B units from PVR.

PVR’s coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. PVR also earns revenues from other land management activities, such as selling standing timber and real estate rentals, 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 the panhandle of 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. 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, 2007. 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, all of our wholly owned subsidiaries and PVG, of which we indirectly owned the sole general partner and an approximately 82% limited partner interest as of March 31, 2008. PVG GP, LLC, our wholly owned subsidiary, serves as PVG’s sole general partner and controls PVG. Intercompany balances and transactions have been eliminated in consolidation. Our

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consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and Securities and Exchange Commission (“SEC”) regulations. 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, 2007. Operating results for the three months ended March 31, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008. Certain reclassifications have been made to conform to the current period’s presentation.

New Accounting Standard

In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 161,Disclosures about Derivative Instruments and Hedging Activities,an Amendment of FASB Statement No. 133which amends and expands SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. SFAS No. 161 requires companies to disclose the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk and strategies and objectives for using derivative instruments. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application permitted. We are currently assessing the impact on the financial statements of adopting SFAS No. 161 effective January 1, 2009.

4. Fair Value Measurement of Financial Instruments

We adopted SFAS No. 157,Fair Value Measurements, effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being 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. FASB Staff Position FAS 157-2,Effective Date of FASB Statement No. 157,delays the application of SFAS 157 for nonfinancial assets and nonfinancial liabilities to periods beginning after November 15, 2008.

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 our financial instruments by the above SFAS No. 157 categories as of March 31, 2008:

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				Fair Value Measurement at March 31, 2008, Using
Description	Fair Value Measurements, March 31, 2008			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Trading securities	$	4,857		$	4,857	$	—		$	—
Interest rate swap liability - current		(3,865	)		—		(3,865	)		—
Interest rate swap liability - noncurrent		(7,076	)		—		(7,076	)		—
Commodity derivative assets - current		3,806			—		3,806			—
Commodity derivative assets - noncurrent		419			—		419			—
Commodity derivative liability - current		(54,740	)		—		(54,740	)		—
Commodity derivative liability - noncurrent		(2,513	)		—		(2,513	)		—
Total	$	(59,112	)	$	4,857	$	(63,969	)	$	—

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

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

• Commodity derivative instruments: Our oil and gas commodity derivatives consist of costless collar and three-way option derivative contracts, while PVR utilizes costless collar, three-way collar and swap derivative contracts in its natural gas midstream segment. The fair values of our oil and gas commodity derivative agreements are determined based on third-party forward price quotes for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices. The fair values of PVR’s commodity derivative agreements are determined based on forward price quotes for the respective commodities. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. Each of these represents level 2 inputs. See Note 5 – Derivative Instruments.

• Interest rate swaps: We have entered into interest rate swap agreements (the “Revolver 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 swap agreements (the “PVR Revolver Swaps”) to establish fixed rates on a portion of the outstanding borrowings under PVR’s revolving credit facility (the “PVR Revolver”). We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. Each of these represents level 2 inputs. See Note 5 – Derivative Instruments.

5. 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 (shareholders’ equity). The following table summarizes the effects of commodity derivative activities on our consolidated statements of income for the three months ended March 31, 2008 and 2007:

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	Three Months Ended March 31,
	2008			2007
	(in thousands)
Income statement caption:
Natural gas revenues	$	—		$	550
Oil and condensate revenues		—			(127	)
Natural gas midstream revenues		(2,251	)		(2,286	)
Cost of midstream gas purchased		1,143			1,443
Derivatives		(25,901	)		(16,721	)
Decrease in income before minority interest and income taxes	$	(27,009	)	$	(17,141	)
Realized and unrealized derivative impact:
Cash received (paid) for derivative settlements	$	(8,953	)	$	3,512
Unrealized derivative gain (loss)		(18,056	)		(20,653	)
Decrease in income before minority interest and income taxes	$	(27,009	)	$	(17,141	)

Oil and Gas Segment Commodity Derivatives

We utilize costless collar, three-way option derivative contracts and swaps 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, their use also may limit future revenues from favorable price movements.

With respect to a costless collar contract, the counterparty 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 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.

A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes the maximum price that we will receive for the contracted commodity volumes. The purchased put establishes the minimum price that we will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (i.e., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

With respect to a swap contract, the counterparty 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.

The fair values of our oil and gas derivative agreements are determined based on third-party forward price quotes for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of March 31, 2008, the credit risk of our counterparties and our own credit risk in accordance with SFAS No. 157. The following table sets forth our positions as of March 31, 2008:

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			Weighted Average Price							Estimated Fair Value (in thousands)
	Average Volume Per Day		Additional Put Option		Floor			Ceiling
Natural Gas Costless Collars	(in MMBtus	)				(per MMBtu	)
Second Quarter 2008	10,000				$	7.50		$	9.10		(1,114	)
Third Quarter 2008	10,000				$	7.50		$	9.10		(1,114	)
Fourth Quarter 2008	10,000				$	7.50		$	9.10		(371	)
Natural Gas Three-Way Collars	(in MMBtus	)				(per MMBtu	)
Second Quarter 2008	22,500		$	5.00	$	7.11		$	9.09		(2,860	)
Third Quarter 2008	22,500		$	5.00	$	7.11		$	9.09		(2,963	)
Fourth Quarter 2008	67,500		$	5.89	$	8.55		$	11.26		(4,932	)
First Quarter 2009	65,000		$	6.00	$	8.67		$	11.68		(5,726	)
Second Quarter 2009	20,000		$	5.75	$	8.00		$	9.23		(1,001	)
Third Quarter 2009	20,000		$	5.75	$	8.00		$	9.23		(1,052	)
Fourth Quarter 2009	10,000		$	6.00	$	8.50		$	12.15		(63	)
First Quarter 2010	10,000		$	6.00	$	8.50		$	12.15		(316	)
Natural Gas Swaps
Second Quarter 2008	45,000				$	9.03					(3,767	)
Third Quarter 2008	45,000				$	9.03					(5,171	)
Crude Oil Three-Way Collars	(Bbl	)				(Bbl	)
Second Quarter 2008	500		$	70.00	$	95.00		$	108.80		9
Third Quarter 2008	500		$	70.00	$	95.00		$	108.80		38
Oil and gas segment commodity derivatives - net liability										$	(30,403	)

PVR Natural Gas Midstream Segment Commodity Derivatives

PVR utilizes costless collar, three-way collar and swap derivative contracts to hedge against the variability in cash flows associated with forecasted natural gas midstream revenues and cost of midstream gas purchased. PVR also utilizes swap derivative 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 the natural gas liquids, or NGLs, that PVR sells after processing. PVR hedges against the variability in its frac spread by entering into swap derivative contracts to sell NGLs forward at a predetermined swap 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, their use also may limit future revenues or cost savings from favorable price movements.

With respect to a costless collar contract, the counterparty is required to make a payment to PVR if the settlement price for any settlement period is below the floor price for such contract. PVR is required to make 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. With respect to a swap contract, the counterparty is required to make a payment to PVR if the settlement price for any settlement period is less than the swap price for such contract, and PVR is 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 option contract consists of a collar contract as described above plus a put option contract sold by PVR with a price below the floor price of the collar. This additional put requires PVR 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, PVR is entitled to a net payment equal to the difference between the floor

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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. This strategy enables PVR to increase the floor and the ceiling prices of the collar beyond the range of a traditional collar contract while defraying the associated cost with the sale of the additional put option.

The fair values of PVR’s derivative agreements are determined based on forward price quotes for the respective commodities as of March 31, 2008, the credit risks of the counterparties and PVR’s own credit risk. The following table sets forth PVR’s positions as of March 31, 2008 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:

	Average Volume Per Day		Weighted Average Price			Weighted Average Price Collars						Fair Value
						Additional Put Option		Put		Call
Frac Spread	(in MMBtu	)		(per MMBtu	)								(in thousands	)
Second Quarter 2008 through Fourth Quarter 2008	7,824		$	5.02								$	(2,902	)
Ethane Sale Swap	(in gallons	)		(per gallon	)
Second Quarter 2008 through Fourth Quarter 2008	34,440		$	0.4700									(4,133	)
Propane Sale Swaps	(in gallons	)		(per gallon	)
Second Quarter 2008 through Fourth Quarter 2008	26,040		$	0.7175									(5,283	)
Crude Oil Sale Swaps	(in barrels	)		(per barrel	)
Second Quarter 2008 through Fourth Quarter 2008	560		$	49.27									(7,622	)
Natural Gasoline Collar	(in gallons	)							(per gallon)
Second Quarter 2008 through Fourth Quarter 2008	6,300							$	1.4800	$	1.6465		(901	)
Crude Oil Collar	(in barrels	)							(per barrel)
Second Quarter 2008 through Fourth Quarter 2008	400							$	65.00	$	75.25		(2,682	)
Natural Gas Sale Swaps	(in MMBtu	)		(per MMBtu	)
First Quarter 2008 through Fourth Quarter 2008	4,000		$	6.97									3,653
Crude Oil Three-Way Collar	(in barrels	)							(per barrel)
First Quarter 2009 through Fourth Quarter 2009	1,000					$	70.00	$	90.00	$	119.25		544
Settlements to be paid in subsequent period													(3,300	)
Natural gas midstream segment commodity derivatives - net liability												$	(22,626	)

At March 31, 2008, PVR reported a (i) net derivative liability related to the natural gas midstream segment of $22.6 million and (ii) loss in accumulated other comprehensive income of $2.9 million, net of the related income tax benefit of $1.5 million, related to derivatives in the natural gas midstream segment for which PVR discontinued hedge accounting in 2006. The $2.9 million loss, net of related income tax benefit of $1.5 million, will be recorded in earnings through the end of 2008 as the hedged transactions settle.

Interest Rate Swaps

We have entered into the Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under our Revolver until December 2010. The notional amounts of the Revolver Swaps total $50.0 million. 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 Revolver Swaps are recorded as interest expense. The Revolver Swaps were designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings as interest expense. We reported a (i) derivative liability of $3.6 million at March 31, 2008 and (ii) loss in accumulated other comprehensive income of $2.4 million, net of the related income tax benefit of $1.2 million, at March 31, 2008 related to the Revolver Swaps. In connection with periodic settlements, we recognized less than $0.1 million in net hedging gains in interest expense for the three months ended March 31, 2008.

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Interest Rate Swaps—PVR

PVR has entered into the PVR Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. Until March 2010, the notional amounts of the PVR Revolver Swaps total $160.0 million. From March 2010 to December 2011, the notional amounts of the PVR Revolver Swaps total $100.0 million. Until March 2010, PVR will pay a weighted average fixed rate of 4.33% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. From March 2010 to December 2011, PVR will pay a weighted average fixed rate of 4.40% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the PVR Revolver Swaps are recorded as interest expense. The PVR Revolver Swaps are designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings as interest income expense. PVR reported a (i) derivative liability of $7.3 million at March 31, 2008 and (ii) loss in accumulated other comprehensive income of $4.8 million, net of the related income tax benefit of $2.5 million, at March 31, 2008 related to the PVR Revolver Swaps. In connection with periodic settlements, PVR recognized $0.2 million, net of the related income taxes of $0.1 million, in net hedging gains in interest expense for the three months ended March 31, 2008.

6. 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, 2008 and 2007:

	Three Months Ended March 31,
	2008		2007
	(in thousands, except per share data)
Net income	$	3,926	$	4,403
Weighted average shares, basic		41,558		37,594
Effect of dilutive securities:
Stock options		245		722
Weighted average shares, diluted		41,803		38,316
Net income per share, basic	$	0.09	$	0.12
Net income per share, diluted	$	0.09	$	0.11

7. 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 stock granted under our stock compensations plans. For the three months ended March 31, 2008 and 2007, we recognized a total of $1.2 million and $1.1 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 $0.4 million for the three months ended March 31, 2008 and 2007.

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Stock Options. In February 2008, we granted 446,458 stock options with a weighted average exercise price of $42.27 and a weighted average grant date fair value of $12.83 per option. The options granted vest over a three-year period, with one-third vesting in each year.

Restricted Stock. In February 2008, we also granted 39,354 shares of restricted stock with a weighted average grant date fair value of $42.27 per share. The restricted stock granted vests 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.

PVR Long-Term Incentive Plan

For the three months ended March 31, 2008 and 2007, PVR recognized a total of $0.7 million and $0.5 million of compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under its long-term incentive plan. During the three months ended March 31, 2008, 130,551 restricted units with a weighted average grant date fair value of $26.91 per unit were granted to employees of Penn Virginia and its affiliates. During the same period, 70,007 restricted units with a weighted average grant date fair value of $27.27 per unit vested. The restricted units granted 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.

8. Comprehensive Income

Comprehensive income represents changes in shareholders’ equity during the reporting period, including net income and charges directly to shareholders’ equity which are excluded from net income. The following table sets forth the components of comprehensive income for the three months ended March 31, 2008 and 2007:

	Three Months Ended March 31,
	2008			2007
	(in thousands)
Net income	$	3,926		$	4,403
Unrealized holding gains (losses) on derivative activities, net of tax		(4,351	)		(284	)
Reclassification adjustment for derivative activities, net of tax		562			163
Pension plan adjustment		41			(36	)
Comprehensive income	$	178		$	4,246

9. Suspended Well Costs

One exploratory well that was pending determination of proved reserves as of December 31, 2007 was subsequently determined to be unsuccessful. Accordingly, we wrote off $0.7 million of capitalized exploratory drilling costs related to this well during the three months ended March 31, 2008.

10. Commitments and Contingencies

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, liquidity or operations.

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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 property leases impose liability for all environmental and reclamation liabilities arising under those laws and regulations on the relevant lessees. 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, 2008 and December 31, 2007, PVR’s environmental liabilities included $1.4 million and $1.5 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.

11. 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 and real estate rentals; 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.

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

The following table presents a summary of certain financial information relating to our segments as of and for the three months ended March 31, 2008 and 2007:

	Oil and Gas			PVR Coal and Natural Resource Management			PVR Natural Gas Midstream		Corporate and Other			Consolidated
	(in thousands)
For the Three Months Ended March 31, 2008:
Revenues	$	92,772		$	30,492		$	126,047	$	(176	)	$	249,135
Intersegment revenues (1)		(473	)		(198	)		473		198			—
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
Interest expense													(9,552	)
Interest income and other													2,331
Derivatives													(25,901	)
Income before minority interest and taxes												$	27,011
Total assets (2)	$	1,339,274		$	567,703		$	348,149	$	97,353		$	2,352,479
Equity investments	$	—		$	25,941		$	60	$	—		$	26,001
Additions to property and equipment and acquisitions, net of cash acquired	$	95,189		$	48		$	17,622	$	543		$	113,402
For the Three Months Ended March 31, 2007:
Revenues	$	62,353		$	28,286		$	95,398	$	233		$	186,270
Intersegment revenues (1)		(318	)		198			318		(198	)		—
Operating costs and expenses		21,612			5,094			86,633		6,322			119,661
Depreciation, depletion and amortization		17,844			5,490			4,643		93			28,070
Operating income (loss)	$	22,579		$	17,900		$	4,440	$	(6,380	)		38,539
Interest expense													(6,727	)
Interest income and other													1,416
Derivatives													(16,721	)
Income before minority interest and taxes												$	16,507
Total assets	$	944,285		$	365,326		$	353,519	$	35,682		$	1,698,812
Equity investments	$	—		$	25,528		$	60	$	—		$	25,588
Additions to property and equipment and acquisitions, net of cash acquired	$	99,725		$	1,336		$	6,005	$	1,540		$	108,606

(1) Represents 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.

(2) PVR coal and natural resource management segment excludes $31.0 million of royalty interests that PVR purchased from us in October 2007, as well as the related depreciation and depletion associated with this royalty interest.

12. Subsequent Events

On April 9, 2008, PVR amended the PVR Revolver to increase the commitments under the PVR Revolver from $450.0 million to $600.0 million.

On April 24, 2008, PVR acquired a 25% member interest in a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin for $52.0 million in cash, after customary closing adjustments. Funding for the acquisition was provided by borrowings under the PVR Revolver.

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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 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 exploration, development and production of natural gas and oil in various onshore U.S. 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 PVR are held principally through our general partner and 82% limited partner interests in PVG. PVG owns an approximately 42% limited partner interest in PVR and 100% of the general partner of PVR, which holds a 2% general partner interest in PVR.

We are engaged in three primary business segments: (1) oil and gas, (2) coal and natural resource management and (3) natural gas midstream. We operate our oil and gas segment. PVR operates our coal and natural resource management and natural gas midstream segments and is consolidated by PVG, because PVG controls PVR’s general partner. We consolidate PVG’s results into our financial statements, because we control the general partner of PVG. As of March 31, 2008, we had an approximately 82% interest in PVG’s net income. Our operating income was $60.1 million in the three months ended March 31, 2008, compared to $38.5 million in the same period of 2007. In the three months ended March 31, 2008, the oil and gas segment contributed $36.4 million, or 60%, to operating income, the PVR coal and natural resource management segment contributed $17.6 million, or 29%, to operating income, and the PVR natural gas midstream segment contributed $13.7 million, or 23%, to operating income. Corporate and other functions resulted in $7.5 million of operating expenses. The following table presents a summary of certain financial information relating to our segments (in thousands):

	Oil and Gas		PVR Coal and Natural Resource Management		PVR Natural Gas Midstream		Corporate and Other			Consolidated
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
For the Three Months Ended March 31, 2007:
Revenues	$	62,035	$	28,484	$	95,716	$	35		$	186,270
Operating costs and expenses		21,612		5,094		86,633		6,322			119,661
Depreciation, depletion and amortization		17,844		5,490		4,643		93			28,070
Operating income (loss)	$	22,579	$	17,900	$	4,440	$	(6,380	)	$	38,539
											��

Oil and Gas Segment

We have a geographically diverse asset base with core areas of operation in East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast regions of the United States. As of December 31, 2007, we had proved natural gas and oil reserves of approximately 680 Bcfe, of which 87% were natural gas and 59% were proved developed. In the three months ended March 31, 2008, we produced 10.5 Bcfe, a 21% increase compared to 8.7 Bcfe in the same period of 2007.

Our revenues, profitability and future rate of growth are highly dependent on the prevailing prices for oil and natural gas, which are affected by numerous factors that are generally beyond our control. Crude oil prices are generally determined by global supply and demand. Natural gas prices are influenced by national and regional supply and demand. A substantial or extended decline in the price of oil or natural gas could have a material adverse effect on our revenues, profitability and cash flow and could, under certain circumstances, result in an impairment of some of our oil and natural gas properties. Our future profitability and growth are also highly dependent on the results of our exploratory and development drilling programs.

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In addition to our conventional development program, we have continued to expand our presence in unconventional plays, such as the Cotton Valley play in East Texas, the Selma Chalk play in Mississippi and coalbed methane in Appalachia and the Mid-Continent. We expect to continue to increase our proved reserves and production through our active development drilling programs in each of these areas. We are also committed to expanding our oil and gas reserves and production by using our ability to generate exploratory prospects and development drilling programs internally, primarily along the Gulf Coast of Louisiana and Texas.

PVR Coal and Natural Resource Management Segment

As of December 31, 2007, PVR owned or controlled 818 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 its coal reserves in exchange for royalty payments. PVR actively works with its lessees to develop efficient methods to exploit the reserves and to maximize production from the properties. PVR does not operate any mines. In the three months ended March 31, 2008, PVR’s lessees produced 7.6 million tons of coal from its properties and paid PVR coal royalties revenues of $24.0 million, for an average royalty per ton of $3.14. Approximately 86% of PVR’s coal royalties revenues in the three months ended March 31, 2008 were derived from coal mined on PVR’s properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of PVR’s coal royalties revenues for the respective periods was derived from coal mined on PVR’s properties under leases containing fixed royalty rates that escalate annually.

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, its lessees or its lessee’s 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 its lessees’ contracts are renegotiated. The global markets for most types of coal remain strong. Continued demand from emerging countries and the increased consumption domestically have created a strong global picture. During 2007, U.S.-produced coal enjoyed increased demand abroad as dwindling supplies and the decline of the dollar made U.S.-exported coal more attractive. Pricing in 2008 is strong primarily due to increasing global demand and supply difficulties.

PVR also earns revenues from the provision of fee-based coal preparation and loading services, from the sale of standing timber on its properties, from oil and gas royalty interests it owns and from coal transportation, or wheelage, fees.

PVR’s management continues to focus on acquisitions that increase and diversify its sources of cash flow.

PVR Natural Gas Midstream Segment

PVR owns and operates natural gas midstream assets located in Oklahoma and the panhandle of Texas. These assets include approximately 3,716 miles of natural gas gathering pipelines and four natural gas processing facilities having 220 MMcfd of total capacity. PVR also owns a natural gas processing facility in East Texas with 80 MMcfd of total capacity that PVR management expects to commence operations in the second quarter of 2008. 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. 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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For the three months ended March 31, 2008, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 17.3 Bcf, or approximately 190 MMcfd. For the three months ended March 31, 2008, two of PVR’s natural gas midstream customers accounted for 54% of PVR’s natural gas midstream revenues and 28% of our total consolidated revenues.

Revenues, profitability and the future rate of growth of PVR’s 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 uncertainty.

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.

Corporate and Other

Corporate and other primarily represents corporate functions.

Ownership of and Relationship with PVG and PVR

Penn Virginia, PVG and PVR are publicly traded on the New York Stock Exchange under the symbols “PVA,” “PVG” and “PVR.” Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. Because PVG controls the general partner of PVR, the financial results of PVR are included in PVG’s condensed 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 from PVG.

As of March 31, 2008, we owned the general partner of PVG and an approximately 82% limited partner interest in PVG. PVG owns an approximately 42% limited partner interest in PVR, 100% of the general partner of PVR, which holds a 2% general partner interest in PVR, and all the incentive distribution rights. We directly owned an additional 0.2% limited partner interest in PVR as of March 31, 2008. The following diagram depicts our ownership of PVG and PVR as of March 31, 2008:

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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 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.

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, 2008 and 2007 (in thousands):

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For The Three Months Ended March 31, 2008:	Oil and Gas & Corporate			PVR			Consolidated
Net cash provided by operating activities	$	37,306		$	28,846		$	66,152
Cash flows from financing activities:
Dividends paid		(2,344	)		—			(2,344	)
PVR distributions received (paid)		10,978			(24,718	)		(13,740	)
Debt borrowings, net		54,000			2,000			56,000
Other		5,282			—			5,282
Net cash provided by (used in) financing activities		67,916			(22,718	)		45,198
Net cash provided by operating and financing activities		105,222			6,128			111,350
Net cash used in investing activities		(95,668	)		(17,329	)		(112,997	)
Net increase (decrease) in cash and cash equivalents	$	9,554		$	(11,201	)	$	(1,647	)
For the Three Months Ended March 31, 2007:	Oil and Gas & Corporate			PVR			Consolidated
Net cash provided by operating activities	$	41,423		$	23,518		$	64,941
Cash flows from financing activities:
Dividends paid		(2,116	)		—			(2,116	)
PVR distributions received (paid)		10,009			(21,029	)		(11,020	)
Debt borrowings, net		53,000			5,000			58,000
Other		83			860			943
Net cash provided by (used in) financing activities		60,976			(15,169	)		45,807
Net cash provided by operating and financing activities		102,399			8,349			110,748
Net cash used in investing activities		(101,261	)		(7,298	)		(108,559	)
Net increase in cash and cash equivalents	$	1,138		$	1,051		$	2,189

Cash provided by operating activities of the oil and gas segment and corporate decreased by $4.1 million, or 10%, from $41.4 million in the three months ended March 31, 2007 to $37.3 million in the same period of 2008. This overall decrease was primarily attributable to decreased cash inflows for our oil and gas segment derivative settlements and a decrease in working capital in the oil and gas segment from the three months ended March 31, 2007 to the same period of 2008.

Cash provided by operating activities for PVR increased by $5.3 million, or 23%, from $23.5 million in the three months ended March 31, 2007 to $28.8 million in the same period of 2008. The overall increase in cash provided by operating activities in the three months ended March 31, 2007 compared to the same period in 2008 was primarily attributable to the increase in PVR’s natural gas midstream segment’s operating income, partially offset by increased cash outflows for derivative settlements.

Capital Expenditures

Capital expenditures, which comprise the primary portion of cash used in investing activities, totaled $114.5 million in the three months ended March 31, 2008, compared to $106.2 million in the same period of 2007. The following table sets forth capital expenditures by segment during the three months ended March 31, 2008 and 2007:

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	Three Months Ended March 31,
	2008		2007
	(in thousands)
Oil and gas
Proved property acquisitions	$	—	$	1,400
Development drilling		79,115		69,445
Exploration drilling		5,425		19,231
Seismic		680		866
Lease acquisition and other		4,614		811
Pipeline, gathering, facilities		4,862		4,882
Total		94,696		96,635
Coal and natural resource management
Acquisitions		20		339
Expansion capital expenditures		—		85
Other property and equipment expenditures		28		39
Total		48		463
Natural gas midstream
Expansion capital expenditures		16,373		5,677
Other property and equipment expenditures		3,106		1,907
Total		19,479		7,584
Other		251		1,540
Total capital expenditures	$	114,474	$	106,222

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, 2007, the oil and gas segment made aggregate capital expenditures of $96.6 million primarily for development drilling and exploration drilling. In the three months ended March 31, 2008 and 2007, PVR made aggregate capital expenditures of $19.5 and $8.0 million primarily for natural gas midstream gathering system expansion projects and other natural gas midstream property and equipment expenditures.

We funded oil and gas and other capital expenditures in the three months ended March 31, 2008 and 2007 with borrowings under our Revolver and cash provided by operating activities. PVR funded coal and natural resource management and natural gas midstream capital expenditures in the three months ended March 31, 2008 and 2007 primarily with cash provided by operating activities and borrowings under the PVR Revolver.

We had $54.0 million of net borrowings under our Revolver as of March 31, 2008. This is compared to net borrowings of $53.0 million under the Revolver as of March 31, 2007. As a result of our partner interests in PVG and PVR, we received cash distributions of $10.4 million in the three months ended March 31, 2008, compared to $2.4 million of cash distributions in the three months ended March 31, 2007. Funds from both of these sources were primarily used for capital expenditures.

PVR had net borrowings of $2.0 million in the three months ended March 31, 2008, comprised of net borrowings of $8.0 million under the PVR Revolver and net repayments of $6.0 million under PVR’s senior unsecured notes, or the PVR Notes. This is compared to $5.0 million of net borrowings in the three months ended March 31, 2007, comprised of net borrowings of $10.0 million under the PVR Revolver and net repayments of $5.0 million under the PVR Notes. Funds from the borrowings in the three months ended March 31, 2008 and 2007 were primarily used for capital expenditures.

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In April 2008, PVG declared a $0.34 per unit quarterly distribution for the three months ended March 31, 2008, or $1.36 on an annualized basis, of which we will receive $10.7 million, or $42.8 million on an annualized basis. These distributions are as a result of our limited partner interest in PVG. The portion of PVR’s distribution paid to PVG serves as the basis for PVG’s distribution to its unitholders, including us.

Long-Term Debt

Revolving Credit Facility. As of March 31, 2008, we had $176.0 million outstanding under our Revolver that matures in December 2010. The Revolver 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. We had outstanding letters of credit of $0.3 million as of March 31, 2008. Effective with the closing of our offering of the Convertible Senior Subordinated Notes, or Convertible Notes, on December 5, 2007, the commitments and borrowing base under the Revolver automatically decreased from $525.0 million to $479.0 million. At the current $479.0 million limit on the Revolver, and given our outstanding balance of $176.0 million, net of $0.3 million of letters of credit, we could borrow up to $302.7 million at March 31, 2008. In the three months ended March 31, 2008, we incurred commitment fees of $0.2 million on the unused portion of the Revolver. We capitalized $0.6 million of interest cost incurred in the three months ended March 31, 2008. The Revolver is governed by a borrowing base calculation and is redetermined semi-annually. We have the option to elect interest at (i) LIBOR, plus a margin ranging from 1.00% to 1.75%, 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 0.50%. The weighted average interest rate on borrowings outstanding under the Revolver during the three months ended March 31, 2008 was 5.6%.

The financial covenants under the Revolver require us to not exceed specified debt-to-EBITDAX (as defined in the Revolver) and EBITDAX-to-interest expense ratios and impose dividend limitation restrictions. The Revolver contains various other covenants that limit, among other things, our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business, acquire another company or enter into a merger or sale of assets, including the sale or transfer of interests in our subsidiaries. As of March 31, 2008, we were in compliance with all of our covenants under the Revolver.

Convertible Notes. As of March 31, 2008, we had $230.0 million of Convertible Notes outstanding. The Convertible Notes bear interest at a rate of 4.50% per year payable semiannually in arrears on May 15 and November 15 of each year, beginning on May 15, 2008.

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: (1) during any fiscal quarter beginning after December 31, 2007 (and only during such 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; (2) 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 (3) 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.

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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.

In connection with the sale of the Convertible Notes, we entered into convertible note hedge transactions with respect to shares of our common stock (the “Note Hedges”) 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. 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 whereby we sold to the Option Counterparties warrants to acquire, subject to anti-dilution adjustments, approximately 3,982,680 shares of our common stock (the “Warrants”) at an exercise price of $74.25 per share. We received proceeds of $18.2 million resulting from this sale. Upon exercise of the Warrants, we have the option to deliver cash or 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.

Credit Facility. We have a credit facility with a financial institution, which had no borrowings against it as of March 31, 2008. The facility is effective through August 31, 2008 and is renewable annually. The facility consists of a working capital facility in the amount of $10.0 million. An additional $10.0 million facility is available upon bank approval. The interest rate on the working capital facility is equal to LIBOR plus 1.00% and the interest rate on the additional facility is equal to LIBOR plus an applicable margin ranging from 1.00% to 1.50%.

Interest Rate Swaps. We have entered into the Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver until December 2010. The notional amounts of the Revolver Swaps total $50.0 million. 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 Revolver Swaps are recorded as interest expense. The Revolver Swaps were designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings in interest expense. After considering the applicable margin of 1.00% in effect as of March 31, 2008, the total interest rate on the $50.0 million portion of Revolver borrowings covered by the Revolver Swaps was 6.34% at March 31, 2008.

PVR Revolving Credit Facility. As of March 31, 2008, PVR had $355.7 million outstanding under the PVR Revolver that matures in December 2011. On April 9, 2008, the commitments under the PVR Revolver increased to $600.0 million. The PVR Revolver 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. PVR had outstanding letters of credit of $1.6 million as of March 31, 2008. At the current $600.0 million limit on the PVR Revolver, and given the outstanding balance of $355.7 million, net of $1.6 million of letters of credit, PVR could borrow up to $242.7 million. In the three months ended March 31, 2008, PVR incurred commitment fees of less than $0.1 million on the unused portion of the PVR Revolver. The interest rate under the PVR Revolver fluctuates

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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 0.75% 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 0.75% to 1.75% if PVR selects the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the PVR Revolver in the three months ended March 31, 2008 was 5.1%.

The financial covenants under the PVR Revolver require PVR not to exceed specified debt-to-consolidated EBITDA and consolidated EBITDA-to-interest expense ratios. 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. In addition, the PVR Revolver contains various covenants that limit, among other things, PVR’s ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of its business, acquire another company or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. As of March 31, 2008, PVR was in compliance with all of its covenants under the PVR Revolver.

PVR Senior Unsecured Notes. As of March 31, 2008, PVR owed $58.0 million under the PVR Notes. The PVR Notes bear interest at a fixed rate of 6.02% and mature in March 2013, with semi-annual principal and interest payments. The PVR Notes are equal in right of payment with all of PVR’s other unsecured indebtedness, including the PVR Revolver. The PVR Notes require PVR to obtain an annual confirmation of its credit rating, with a 1.00% increase in the interest rate payable on the PVR Notes in the event that its credit rating falls below investment grade. In March 2008, PVR’s investment grade credit rating was confirmed by Dominion Bond Rating Services. The PVR Notes contain various covenants similar to those contained in the PVR Revolver. As of March 31, 2008, PVR was in compliance with all of its covenants under the PVR Notes.

PVR Interest Rate Swaps. PVR has entered into the PVR Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. Until March 2010, the notional amounts of the PVR Revolver Swaps total $160.0 million. From March 2010 to December 2011, the notional amounts of the PVR Revolver Swaps total $100.0 million. Until March 2010, PVR will pay a weighted average fixed rate of 4.33% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. From March 2010 to December 2011, PVR will pay a weighted average fixed rate of 4.40% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the PVR Revolver Swaps are recorded as interest expense. The PVR Revolver Swaps are designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings in interest expense. After considering the applicable margin of 1.25% in effect as of March 31, 2008, the total interest rate on the $160.0 million portion of PVR Revolver borrowings covered by the PVR Revolver Swaps was 5.58% at March 31, 2008.

Future Capital Needs and Commitments

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 balances relatively low risk, moderate return development projects in East Texas, the Mid-Continent, Appalachia and Mississippi with relatively moderate risk, potentially higher return development projects and exploration prospects in south Louisiana and south Texas. We expect to continue to execute a program dominated by relatively low risk, moderate return development drilling and, to a lesser extent, higher risk, higher return exploration drilling, supplemented periodically with acquisitions.

We have budgeted oil and gas segment capital expenditures, excluding acquisitions, of $474.8 million in 2008. These expenditures are expected to be funded primarily by operating cash flow, cash distributions received from PVG and PVR and from the Revolver as needed. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on industry conditions and the availability of capital. We believe our cash flow from operating activities and sources of debt financing are sufficient to fund our 2008 planned oil and gas capital expenditure program.

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We believe our portfolio of assets provides us with opportunities for organic growth in 2008 which will require capital in excess of our internal sources. We expect to continue to rely on the Revolver to fund a large portion of our capital needs, supplemented by the issuance of additional debt and equity securities as needed.

Currently, PVG has no capital requirements. In the future, we may decide to facilitate PVR acquisitions by providing additional debt or equity to PVR.

Part of PVR’s strategy is to make acquisitions and other capital expenditures which increase cash available for distribution to its unitholders. PVR’s ability to make these acquisitions in the future will depend in part on the availability of debt financing and on its ability to periodically use equity financing through the issuance of new common units, which will depend on various factors, including prevailing market conditions, interest rates and its financial condition and credit rating at the time. For 2008 projects, PVR has budgeted capital expenditures, excluding acquisitions, of $15.7 million, consisting of $0.2 million in the coal and natural resource management segment and $15.5 million in the natural gas midstream segment. PVR intends to fund these capital expenditures with a combination of cash flows provided by operating activities and borrowings under the PVR Revolver. PVR makes quarterly cash distributions of its available cash, generally defined as all of its cash and cash equivalents on hand at the end of each quarter less cash reserves. PVR believes that it will continue to have adequate liquidity to fund future recurring operating and investing activities. Short-term cash requirements, such as operating expenses and quarterly distributions to PVR’s general partner and unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for asset acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities and the issuance of additional equity and debt securities.

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, 2008 and 2007:

	Three Months Ended March 31,
	2008		2007
	(in thousands, except per share data)
Revenues	$	249,135	$	186,270
Expenses	$	189,002	$	147,731
Operating income	$	60,133	$	38,539
Net income	$	3,926	$	4,403
Earnings per share, basic	$	0.09	$	0.12
Earnings per share, diluted	$	0.09	$	0.11
Cash flows provided by operating activities	$	66,152	$	64,941

Operating income increased by $21.6 million in the three months ended March 31, 2008 compared to the same period of 2007 primarily due to a $23.9 million increase in natural gas revenue, a $6.0 million increase in oil and condensate revenue and a $9.8 million increase in natural gas midstream gross processing margin, partially offset by a $6.6 million increase in operating expenses and a $10.5 million increase in depreciation, depletion and amortization expenses. Net income decreased by $0.5 million in the three months ended March 31, 2008 compared to the same period of 2007 primarily due to a $2.8 million increase in interest expense, a $9.2 million increase in derivative losses and a $10.7 million increase in minority interest, partially offset by the $21.6 million increase in operating income.

The assets, liabilities and earnings of PVG are fully consolidated in our financial statements, with the public unitholders’ interest (18% as of March 31, 2008) reflected as a minority interest in our consolidated financial

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statements. The assets, liabilities and earnings of PVR are fully consolidated in PVG’s financial statements, with the public unitholders’ interest (56%, after the effect of incentive distribution rights, as of March 31, 2008) reflected as a minority interest in PVG’s condensed consolidated financial statements.

Oil and Gas Segment

Three Months Ended March 31, 2008 Compared With the Three Months Ended March 31, 2007

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, 2008 and 2007:

	Three Months Ended March 31,				% Change		Three Months Ended March 31,
	2008		2007				2008		2007
	(in thousands, except as noted)						(per Mcfe) (1)
Financial Highlights
Revenues
Natural gas	$	80,513	$	56,619	42	%	$	8.26	$	7.00
Oil and condensate		11,083		5,104	117	%		85.91		47.70
Other income		703		312	125	%
Total revenues		92,299		62,035	49	%		8.77		7.11
Expenses
Operating		14,209		8,919	59	%		1.35		1.02
Taxes other than income		5,858		4,223	39	%		0.56		0.48
General and administrative		4,584		3,400	35	%		0.44		0.39
Production costs		24,651		16,542	49	%		2.34		1.90
Exploration		4,680		5,070	(8	%)		0.44		0.58
Depreciation, depletion and amortization		26,616		17,844	49	%		2.53		2.04
Total expenses		55,947		39,456	42	%		5.32		4.52
Operating income	$	36,352	$	22,579	61	%	$	3.45	$	2.59
Production
Natural gas (MMcf)		9,748		8,084	21	%
Oil and condensate (Mbbl)		129		107	21	%
Total production (MMcfe)		10,522		8,726	21	%

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

Production. Approximately 93% of production in the three months ended March 31, 2008 and 2007 was natural gas. Total production increased by 1.8 Bcfe, or 21%, from 8.7 Bcfe in the three months ended March 31, 2007 to 10.5 Bcfe in the same period of 2008 primarily due to increased production in the East Texas, Mid-Continent and Gulf Coast regions, partially offset by decreased production in the Appalachian and Mississippi regions.

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The following table summarizes total natural gas, oil and condensate production and total natural gas, oil and condensate revenues by region for the three months ended March 31, 2008 and 2007:

	Natural Gas, Oil and Condensate Production		Natural Gas, Oil and Condensate Revenues
	Three Months Ended March 31,		Three Months Ended March 31,
Region	2008	2007	2008		2007
	(MMcfe)		(in thousands)
East Texas	2,757	1,584	$	25,525	$	11,663
Mid-Continent	1,462	811		11,784		4,925
Appalachia	2,840	2,926		22,962		20,778
Mississippi	1,806	1,811		15,282		12,640
Gulf Coast	1,657	1,594		16,043		11,717
Total	10,522	8,726	$	91,596	$	61,723

Revenues. Natural gas revenues increased by $23.9 million, or 42%, from $56.6 million in the three months ended March 31, 2007 to $80.5 million in the same period of 2008. Of the $23.9 million increase, $11.7 million was the result of increased natural gas production from drilling and $12.2 million was the result of increased realized prices for natural gas. Our average realized price received for natural gas increased by $1.26 per Mcf, or 18%, from $7.00 per Mcf in the three months ended March 31, 2007 to $8.26 per Mcf in the same period of 2008. Oil and condensate revenues increased by $6.0 million, or 117%, from $5.1 million in the three months ended March 31, 2007 to $11.1 million in the same period of 2008. Of the $6.0 million increase, $1.1 million was the result of increased oil and condensate production and $4.9 million was the result of higher realized prices for crude oil. Our average realized price received for oil increased by $38.21 per Bbl, or 80%, from $47.70 per Bbl in the three months ended March 31, 2007 to $85.91 per Bbl in the same period of 2008.

Natural gas, oil and condensate revenues are derived from the sale of our oil and gas production, which is net of the effects of the settlement of derivative contracts that previously followed hedge accounting. Settlement of our derivative contracts that do not follow hedge accounting has no effect on our reported revenues. Our revenues may vary 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. The use of this risk management strategy has resulted in lower price realizations compared to physical sale prices in the last several years.

In 2007, we reclassified the remaining amounts in Accumulated Other Comprehensive Income in earnings. As a result, in the three months ended March 31, 2008, no derivatives gains or losses were reported as part of natural gas or oil and condensate revenues. The following table shows a summary of the effects of derivative activities on revenues and realized prices for the three months ended March 31, 2008 and 2007:

	Three Months Ended March 31,
	2008		2007			2008		2007
	(in thousands)					(per Mcf)
Natural gas revenues, as reported	$	80,513	$	56,619		$	8.26	$	7.00
Derivatives (gains) losses included in natural gas revenues		—		(550	)		—		(0.07	)
Natural gas revenues before impact of derivatives		80,513		56,069			8.26		6.93
Cash settlements on natural gas derivatives		—		5,547			—		0.69
Natural gas revenues, adjusted for derivatives	$	80,513	$	61,616		$	8.26	$	7.62
	(in thousands)					(per Bbl)
Crude oil revenues, as reported	$	11,083	$	5,104		$	85.91	$	47.70
Derivatives (gains) losses included in oil and condensate revenues		—		128			—		1.20
Oil and condensate revenues before impact of derivatives		11,083		5,232			85.91		48.90
Cash settlements on crude oil derivatives		—		36			—		0.34
Oil and condensate revenues, adjusted for derivatives	$	11,083	$	5,268		$	85.91	$	49.24

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Expenses. Aggregate operating costs and expenses increased by $16.4 million, or 42%, from $39.5 million in the three months ended March 31, 2007 to $55.9 million in the same period of 2008 primarily due to increased operating expenses, taxes other than income, general and administrative expenses and depreciation, depletion and amortization expenses, partially offset by a decrease in exploration expenses.

Operating expenses increased by $5.3 million, or 59%, from $8.9 million, or $1.02 per Mcfe, in the three months ended March 31, 2007 to $14.2 million, or $1.35 per Mcfe, in the same period of 2008. This increase is due primarily to increased gathering, compression and water disposal costs in the Cotton Valley region, and increased compressor rentals and gathering costs in the Mid-Continent region to support increased drilling and properties acquired during 2007.

Taxes other than income increased by $1.7 million, or 39%, from $4.2 million in the three months ended March 31, 2007 to $5.9 million in the same period of 2008 primarily due to increased production taxes, which are driven by higher volume sales and increased production.

General and administrative expenses increased by $1.2 million, or 35%, from $3.4 million in the three months ended March 31, 2007 to $4.6 million in the same period of 2008 primarily due to increased staffing and consulting costs. General and administrative costs, on a Mcfe basis, increased from $0.39 in the three months ended March 31, 2007 to $0.44 in the same period of 2008.

Exploration expenses in the three months ended March 31, 2008 and 2007 consisted of the following:

	Three Months Ended March 31,
	2008		2007
	(in thousands)
Dry hole costs	$	718	$	1,398
Geological and geophysical		680		803
Unproved leasehold		2,834		2,736
Other		448		133
Total	$	4,680	$	5,070

Exploration expenses decreased by $0.4 million, or 8%, from $5.1 million in the three months ended March 31, 2007 to $4.7 million in the same period of 2008 primarily due to decreases in dry hole costs, partially offset by increases in other costs. Dry hole costs decreased primarily due to a $0.5 million write-off of an exploratory well in the Appalachian region and a $1.0 million write-off of an exploratory well in the Gulf Coast region in the three months ended March 31, 2007, compared to a $0.7 million write-off of one exploratory well in the Appalachian region in the same period of 2008. Other costs increased primarily due to an increase in delay rental payments in the Cotton Valley and Appalachian regions.

DD&A expenses increased by $8.8 million, or 49%, from $17.8 million in the three months ended March 31, 2007 to $26.6 million in the same period of 2008 primarily due to the 21% increase in equivalent production and higher depletion rates. Our average depletion rate increased from $2.04 per Mcfe in the three months ended March 31, 2007 to $2.53 per Mcfe in the same period of 2008 due to higher cost wells per Mcfe and acquisitions.

PVR Coal and Natural Resource Management Segment

Three Months Ended March 31, 2008 Compared With the Three Months Ended March 31, 2007

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, 2008 and 2007:

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	Three Months Ended March 31,						% Change
	2008			2007
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	23,962		$	25,000		(4	)%
Coal services		1,862			1,601		16	%
Timber		1,584			179		785	%
Oil and gas royalty		1,234			277		345	%
Other		1,652			1,427		16	%
Total revenues		30,294			28,484		6	%
Expenses
Coal royalties		2,512			1,783		41	%
Other operating		231			372		(38	)%
Taxes other than income		371			323		15	%
General and administrative		3,185			2,616		22	%
Depreciation, depletion and amortization		6,413			5,490		17	%
Total expenses		12,712			10,584		20	%
Operating income	$	17,582		$	17,900		(2	)%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		7,640			8,284		(8	)%
Average royalties revenues per ton ($/ton)	$	3.14		$	3.02		4	%
Less royalties expense per ton ($/ton)		(0.33	)		(0.22	)	50	%
Average net coal royalties per ton ($/ton)	$	2.81		$	2.80		0	%

Revenues. Coal royalties revenues decreased by $1.0 million, or 4%, from $25.0 million in the three months ended March 31, 2007 to $24.0 million in the same period of 2008. Coal royalties expense increased by $0.7 million, or 41%, from $1.8 million in the three months ended March 31, 2007 to $2.5 million in the same period of 2008. Tons produced by PVR’s lessees decreased by 0.7 million tons, or 8%, from 8.3 million tons in the three months ended March 31, 2007 to 7.6 million tons in the same period of 2008. PVR’s average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, remained relatively constant from the three months ended March 31, 2007 to the same period of 2008.

The following table summarizes coal production and coal royalties revenues by region for the three months ended March 31, 2008 and 2007:

	Coal Production		Coal Royalty Revenues						Coal Royalties Per Ton
	Three Months Ended March 31,		Three Months Ended March 31,						Three Months Ended March 31,
Property	2008	2007	2008			2007			2008			2007
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	4,811	4,957	$	18,579		$	18,910		$	3.86		$	3.81
Northern Appalachia	674	1,370		1,134			2,103			1.68			1.54
Illinois Basin	1,033	619		1,938			1,307			1.88			2.11
San Juan Basin	1,122	1,338		2,311			2,680			2.06			2.00
Total	7,640	8,284	$	23,962		$	25,000		$	3.14		$	3.02
Less coal royalties expense (1)				(2,512	)		(1,783	)		(0.33	)		(0.22	)
Net coal royalties revenues			$	21,450		$	23,217		$	2.81		$	2.80

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

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Coal services revenues increased by $0.3 million, or 16%, from $1.6 million in the three months ended March 31, 2007 to $1.9 million in the same period of 2008. This increase is due primarily to increased preparation and loading fees based on continued successes of PVR’s lessees operating PVR’s coal services facility in Knott County, Kentucky. Timber revenues increased by $1.4 million, or 785%, from $0.2 million in the three months ended March 31, 2007 to $1.6 million in the same period of 2008 primarily due to the effects of PVR’s September 2007 forestland acquisition. Oil and gas royalty revenues increased by $0.9 million, or 345%, from $0.3 million in the three months ended March 31, 2007 to $1.2 million in the same period of 2008 primarily due to the increased royalties resulting from PVR’s October 2007 oil and gas royalty interest acquisition. Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fee income, increased by $0.3 million, or 16%, from $1.4 million in the three months ended March 31, 2007 to $1.7 million in the same period of 2008 primarily due to increased wheelage income in Central Appalachia as well as an overall increase in minimum rental income.

Expenses.General and administrative expenses increased by $0.6 million, or 22%, from $2.6 million in the three months ended March 31, 2007 to $3.2 million in the same period of 2008 primarily due to increased staffing costs. DD&A expenses increased by $0.9 million, or 17%, from $5.5 million in the three months ended March 31, 2007 to $6.4 million in the same period of 2008 primarily due to increased depletion resulting from PVR’s forestland acquisition in September 2007 and PVR’s oil and gas royalty interest acquisition in October 2007.

PVR Natural Gas Midstream Segment

Three Months Ended March 31, 2008 Compared With the Three Months Ended March 31, 2007

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, 2008 and 2007:

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	Three Months Ended March 31,
	2008			2007			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	61,667		$	59,680		3	%
Natural gas liquids		56,197			31,988		76	%
Condensate		6,216			2,916		113	%
Gathering and transportation fees		968			734		32	%
Total natural gas midstream revenues		125,048			95,318		31	%
Producer services		1,472			398		270	%
Total revenues		126,520			95,716		32	%
Expenses
Cost of midstream gas purchased		99,697			79,731		25	%
Operating		4,050			3,359		21	%
Taxes other than income		701			520		35	%
General and administrative		3,333			3,023		10	%
Depreciation and amortization		5,087			4,643		10	%
Total operating expenses		112,868			91,276		24	%
Operating income	$	13,652		$	4,440		207	%
Operating Statistics
System throughput volumes (MMcf)		17,287			15,900		9	%
System throughput volumes (MMcf/day)		190			177		7	%
Gross processing margin	$	25,351		$	15,587		63	%
Impact of derivatives		(8,414	)		(1,229	)	585	%
Gross processing margin, adjusted for impact of derivatives	$	16,937		$	14,358		18	%
Gross processing margin ($/MMcf)	$	1.47		$	0.98		50	%
Impact of derivatives ($/MMcf)		(0.49	)		(0.08	)	513	%
Gross processing margin, adjusted for impact of derivatives ($/MMcf)	$	0.98		$	0.90		9	%

Gross Processing Margin. PVR’s gross processing margin is the difference between natural gas midstream revenues and the 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 increased by $29.7 million, or 31%, from $95.3 million in the three months ended March 31, 2007 to $125.0 million in the same period of 2008. Cost of midstream gas purchased increased by $20.0 million, or 25%, from $79.7 million in the three months ended March 31, 2007 to $99.7 million in the same period of 2008. PVR’s gross processing margin increased by $9.8 million, or 63%, from $15.6 million in the three months ended March 31, 2007 to $25.4 million in the same period of 2008. The gross processing margin increase was a result of an increased pricing environment, increased system throughput volumes and higher fractionation, or “frac” spreads during the three months ended March 31, 2008 compared to the same period of 2007. Frac spreads are the difference between the price of NGL’s sold and the cost of natural gas purchased on a per MMBtu basis.

System throughput volumes increased by 13 MMcfd, or 7%, from 177 MMcfd in the three months ended March 31, 2007 to 190 MMcfd in the same period of 2008. This increase in throughput volumes is due primarily to the continued successful development by producers operating in the vicinity of PVR’s systems, as well as PVR’s success in contracting and connecting new supply. PVR also increased its processing capacity with the addition of the Spearman plant in the three months ended March 31, 2008.

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During the three months ended March 31, 2008, PVR generated a majority of its gross processing margin from contractual arrangements under which its 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. Adjusted for the impact of derivative financial instruments, PVR’s gross processing margin increased by $2.5 million, or 18%, from $14.4 million for the three months ended March 31, 2007 to $16.9 million for the same period of 2008. On a per MMcf basis, the gross processing margin adjusted for the impact of derivatives increased by $0.08, or 9%, from $0.90 per MMcf in the three months ended March 31, 2007 to $0.98 per MMcf in the same period of 2008.

Producer Services Revenues.Producer services revenues increased by $1.1 million, or 270%, from $0.4 million in the three months ended March 31, 2007 to $1.5 million in the same period of 2008 primarily due to an increase in collected agent fees for the marketing of our and other third parties’ natural gas production.

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

Operating expenses increased by $0.7 million, or 21%, from $3.4 million in the three months ended March 31, 2007 to $4.1 million in the same period of 2008 primarily due to expenses related to PVR’s expanding footprint in areas of operation, including the addition of the Spearman plant. General and administrative expenses increased by $0.3 million, or 10%, from $3.0 million in the three months ended March 31, 2007 to $3.3 million in the same period of 2008 primarily due to increased staffing costs. Depreciation and amortization expenses increased by $0.4 million, or 10%, from $4.7 million in the three months ended March 31, 2007 to $5.1 million in the same period of 2008. This increase is primarily due to the addition of the Spearman plant, as well as an $11.9 million increase in segment capital expenditures, from $7.6 million in the three months ended March 31, 2007 to $19.5 million in the same period of 2008.

Corporate and Other

Our corporate and other results consist of corporate operating expenses, interest expense, derivative gains and losses and minority interest.

Corporate Operating Expenses. Corporate operating expenses primarily consist of general and administrative expenses other than from our oil and gas segment and the PVR coal and natural resource management and PVR natural gas midstream segments. Corporate operating expenses increased by $1.1 million, or 17%, from $6.4 million in the three months ended March 31, 2007 to $7.5 million in the same period of 2008 primarily due to increased general and administrative expenses resulting from wage increases, increased consulting expenses and the recognition of additional stock-based compensation expenses.

Interest Cost. Our consolidated interest cost is comprised of the following:

	Three Months Ended March 31,				% Change
	2008		2007
	(in thousands)
PVA interest expense	$	4,620	$	3,180	45	%
PVA capitalized interest		554		979	(43	)%
PVR interest expense		4,932		3,547	39	%
PVR capitalized interest		488		—	—
Total interest cost	$	10,594	$	7,706	37	%

Our interest expense increased by $1.4 million, or 45%, from $3.2 million in the three months ended March 31, 2007 to $4.6 million in the same period of 2008. Our oil and gas segment also capitalized $1.0 million of capitalized interest in the three months ended March 31, 2007, compared to $0.5 million in the same period of 2008. The borrowings for both periods funded the preparation of unproved oil and gas properties for their development. This increase in interest cost is primarily due to the change in our average debt balance, which increased from $242.0 million at March 31, 2007 to $374.5 million at March 31, 2008.

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PVR’s interest expense increased by $1.4 million, or 39%, from $3.5 million in the three months ended March 31, 2007 to $4.9 million in the same period of 2008. PVR also capitalized $0.5 million of interest costs in the three months ended March 31, 2008 related to the construction of its natural gas gathering facility in East Texas. PVR had no capitalized interest in the three months ended March 31, 2007. This increase in interest cost is primarily due to the increase in PVR’s average debt balance, which increased from $221.8 million at March 31, 2007 to $412.5 million at March 31, 2008.

Derivatives. Our derivative activity is summarized below:

	Three Months Ended March 31,						% Change
	2008			2007
	(in thousands)
Oil and gas segment unrealized derivative loss	$	(34,246	)	$	(19,658	)	74	%
Oil and gas segment realized gain		569			5,584		(90	)%
PVR midstream segment unrealized derivative gain (loss)		17,298			(575	)	(3108	)%
PVR midstream segment realized loss		(9,522	)		(2,072	)	360	%
Total derivative losses	$	(25,901	)	$	(16,721	)	55	%

Minority Interest. Minority interest represents PVG’s net income allocated to the limited partner units owned by the public. In the three months ended March 31, 2008 and 2007, minority interest reduced our consolidated income from operations by $20.0 million and $9.3 million. The increase in minority interest was primarily due to the increase in PVG’s net income from $7.7 million in the three months ended March 31, 2007 to $16.8 million in the same period of 2008 and the increase in PVR’s net income from $16.4 million in the three months ended March 31, 2007 to $34.5 million in the same period of 2008.

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 reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those quantities that require additional capital investment through drilling or well recompletion techniques.

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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.

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 deplete 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. We deplete timber on an area-by-area basis at a rate based upon the quantity of timber sold.

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.

Natural Gas Midstream Revenues

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. 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 may take up to 30 days following the month of production. Therefore, we make 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.

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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Derivative Activities

Until 2006, we used hedge accounting for commodity derivative financial instruments as allowed under SFAS No. 133. Our commodity derivative financial instruments initially qualified as cash flow hedges, and changes in fair value from these contracts were deferred in accumulated comprehensive income until the hedged transactions settled. When we discontinued hedge accounting in 2006, a net loss remained in accumulated other comprehensive income. As the hedged transactions settled in 2006 and 2007, we and PVR recognized the deferred changes in fair value in revenues and cost of gas purchased in our consolidated statements of income. As of March 31, 2008, PVR had $4.4 million of losses remaining in accumulated other comprehensive income. PVR will recognize these hedging losses during the remainder of 2008 as the hedged transactions settle.

Beginning in 2006, we began recognizing changes in fair value in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (shareholders’ equity). Because we no longer use hedge accounting for our commodity derivatives, we have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to swings in the value of these contracts. Our results of operations are affected by the potential volatility of changes in fair value, which fluctuate with changes in NGL, crude oil and natural gas prices. These fluctuations could be significant in a volatile pricing environment.

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 find 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, 2008, the costs attributable to unproved properties were $127.8 million. We regularly assess on a property-by-property basis the impairment of individual unproved properties whose acquisition costs are relatively significant. 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 and development activities and their results.

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. SFAS No.157 applies to all financial assets and financial liabilities that are being 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.

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• 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 financial instruments:

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

• Commodity derivative instruments: Our oil and gas derivatives consist of costless collar and three-way option derivative contracts, while PVR utilizes costless collar, three-way collar and swap derivative contracts in its natural gas midstream segment. The fair values of our oil and gas derivative agreements are determined based on third-party forward price quotes for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices. The fair values of PVR’s derivative agreements are determined based on forward price quotes for the respective commodities. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. Each of these is a level 2 input. See Note 5 – Derivative Instruments.

• Interest rate swaps: We have entered into the Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under our Revolver. PVR has entered into interest the PVR Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. Each of these is a level 2 input. See Note 5 – 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 for all environmental and reclamation liabilities arising under those laws and regulations on the relevant lessees. 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, 2008 and December 31, 2007, PVR’s environmental liabilities included $1.4 million and $1.5 million, which represents PVR’s best estimate of the liabilities as of those dates related to its coal and natural

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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, coal, oil and NGL prices;

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

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

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• hedging results;

• accidents;

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

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

• risks and uncertainties relating to general domestic and international economic (including inflation, interest rates and financial market) 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 Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

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, 2007. 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 natural gas, NGL, crude oil, and coal price risks and interest rate risk.

We are also indirectly exposed to the credit risk of our and PVR’s customers and PVR’s lessees. If our or PVR’s customers or lessees become financially insolvent, they may not be able to continue to operate or meet their payment obligations.

Price Risk Management

Our price risk management program permits the utilization of derivative financial instruments (such as futures, forwards, option contracts and swaps) to seek to mitigate the price risks associated with fluctuations in natural gas, NGL and crude oil prices as they relate to our anticipated production and PVR’s natural gas midstream business. The derivative financial instruments are placed with major financial institutions that we believe are of minimum 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.

For the three months ended March 31, 2008, we reported a net derivative loss of $25.9 million. Until 2006, we used hedge accounting for commodity derivative financial instruments as allowed under SFAS No. 133. Our commodity derivative financial instruments initially qualified as cash flow hedges, and changes in fair value from these contracts were deferred in accumulated comprehensive income until the hedged transactions settled. When we discontinued hedge accounting in 2006, a net loss remained in accumulated other comprehensive income. As the hedged transactions settled in 2006 and 2007, we and PVR recognized the deferred changes in fair value in revenues and cost of gas purchased in our consolidated statements of income. As of March 31, 2008, PVR had $4.4 million of net losses remaining in accumulated other comprehensive income. PVR will recognize these hedging losses during the remainder of 2008 as the hedged transactions settle.

Beginning in 2006, we began recognizing changes in fair value in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (shareholders’ equity). Because we no longer use hedge accounting for our commodity derivatives, we have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to swings in the value of these contracts. Our results of operations are affected by the potential volatility of 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.

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Oil and Gas Segment

The following tables list our derivative agreements and their fair values as of March 31, 2008:

		Weighted Average Price						Estimated Fair Value (in thousands)
	Average Volume Per Day	Additional Put Option		Floor		Ceiling
Natural Gas Costless Collars	(in MMBtus)		(per MMBtu)
Second Quarter 2008	10,000			$	7.50	$	9.10		(1,114	)
Third Quarter 2008	10,000			$	7.50	$	9.10		(1,114	)
Fourth Quarter 2008	10,000			$	7.50	$	9.10		(371	)
Natural Gas Three-Way Collars	(in MMBtus)		(per MMBtu)
Second Quarter 2008	22,500	$	5.00	$	7.11	$	9.09		(2,860	)
Third Quarter 2008	22,500	$	5.00	$	7.11	$	9.09		(2,963	)
Fourth Quarter 2008	67,500	$	5.89	$	8.55	$	11.26		(4,932	)
First Quarter 2009	65,000	$	6.00	$	8.67	$	11.68		(5,726	)
Second Quarter 2009	20,000	$	5.75	$	8.00	$	9.23		(1,001	)
Third Quarter 2009	20,000	$	5.75	$	8.00	$	9.23		(1,052	)
Fourth Quarter 2009	10,000	$	6.00	$	8.50	$	12.15		(63	)
First Quarter 2010	10,000	$	6.00	$	8.50	$	12.15		(316	)
Natural Gas Swaps
Second Quarter 2008	45,000			$	9.03				(3,767	)
Third Quarter 2008	45,000			$	9.03				(5,171	)
Crude Oil Three-Way Collars	(Bbl)		(Bbl)
Second Quarter 2008	500	$	70.00	$	95.00	$	108.80		9
Third Quarter 2008	500	$	70.00	$	95.00	$	108.80		38
Oil and gas segment commodity derivatives - net liability								$	(30,403	)

We estimate that excluding the derivative positions described above, for every $1.00 per MMBtu decrease or increase in natural gas prices, our operating income from oil and gas operations in 2008 would increase or decrease by approximately $20.0 million. This assumes that natural gas production remains constant at budgeted levels. In addition, we also estimate that for every $5.00 per barrel increase or decrease in the oil prices, our operating income from oil and gas operations would increase or decrease by approximately $2.0 million. This assumes that oil and other liquid production remains constant at budgeted levels. These estimated changes in operating income exclude the potential cash receipts or payments in settling these derivative positions.

PVR Natural Gas Midstream Segment

The following table lists PVR’s derivative agreements and their fair values as of March 31, 2008:

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	Average Volume Per Day		Weighted Average Price			Weighted Average Price Collars						Fair Value
						Additional Put Option		Put		Call
Frac Spread	(in MMBtu	)		(per MMBtu	)								(in thousands	)
Second Quarter 2008 through Fourth Quarter 2008	7,824		$	5.02								$	(2,902	)
Ethane Sale Swap	(in gallons	)		(per gallon	)
Second Quarter 2008 through Fourth Quarter 2008	34,440		$	0.4700									(4,133	)
Propane Sale Swaps	(in gallons	)		(per gallon	)
Second Quarter 2008 through Fourth Quarter 2008	26,040		$	0.7175									(5,283	)
Crude Oil Sale Swaps	(in barrels	)		(per barrel	)
Second Quarter 2008 through Fourth Quarter 2008	560		$	49.27									(7,622	)
Natural Gasoline Collar	(in gallons	)							(per gallon)
Second Quarter 2008 through Fourth Quarter 2008	6,300							$	1.4800	$	1.6465		(901	)
Crude Oil Collar	(in barrels	)							(per barrel)
Second Quarter 2008 through Fourth Quarter 2008	400							$	65.00	$	75.25		(2,682	)
Natural Gas Sale Swaps	(in MMBtu	)		(per MMBtu	)
First Quarter 2008 through Fourth Quarter 2008	4,000		$	6.97									3,653
Crude Oil Three-Way Collar	(in barrels	)							(per barrel)
First Quarter 2009 through Fourth Quarter 2009	1,000					$	70.00	$	90.00	$	119.25		544
Settlements to be paid in subsequent period													(3,300	)
Natural gas midstream segment commodity derivatives - net liability												$	(22,626	)

We estimate that excluding the derivative positions described above, for every $1.00 per MMBtu decrease or increase in natural gas prices from the $7.50 per MMBtu budgeted 2008 benchmark price, natural gas midstream gross processing margin and operating income in 2008 would increase or decrease by approximately $7.2 million. This assumes oil and other liquids prices and inlet volumes remain constant at budgeted levels. In addition, we also estimate that excluding the derivative positions described above, for every $5.00 per barrel increase or decrease in the oil prices from the $80.00 per barrel budgeted 2008 benchmark price, natural gas midstream gross processing margin and operating income would increase or decrease by approximately $3.2 million. This assumes natural gas prices and inlet volumes remain constant at budgeted levels. These estimated changes in gross processing margin and operating income exclude the potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of March 31, 2008, we had $176.0 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Revolver 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 Revolver 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) at March 31, 2008 would cost us approximately $1.3 million in additional interest expense.

As of March 31, 2008, PVR had $355.7 million of outstanding indebtedness under the PVR Revolver, which carries a variable interest rate throughout its term. PVR entered into the PVR Revolver Swaps to effectively convert the interest rate on $160.0 million of the amount outstanding under the PVR Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.33% plus the applicable margin until March 2010. From March 2010 to December 2011, the PVR Revolver Swaps will effectively convert the interest rate on $100.0 million of the amount outstanding under the PVR Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.40% plus the applicable margin. The PVR Revolver 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 PVR Revolver (net of amounts fixed through hedging transactions) at March 31, 2008 would cost PVR approximately $2.0 million in additional interest expense.

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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, 2008. 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, 2008, 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 1 Legal Proceedings

Loadout LLC (“Loadout”), a subsidiary of PVR, holds permits (which have been assigned to a mine operator who leases the property for mining) to mine at the Nellis Surface Mine in Boone County, West Virginia. The U.S. Army Corps of Engineers (“Corps”) issued a permit under Section 404 of the federal Clean Water Act to Loadout on April 16, 2008, authorizing the placement of fill material into certain waters of the United States in conjunction with the construction of four valley fills, three sediment pond embankments and one haul road at the Nellis Mine. On April 23, 2008, the plaintiffs in the suitOhio Valley Environmental Coalition v. U.S. Army Corps of Engineers, No. 3:05-0784 (S.D. W. Va.) filed a complaint and motion for a temporary restraining order (“TRO”) seeking to suspend or revoke the Corps’ Section 404 permit, alleging, among other things, violations by the Corps of the National Environmental Policy Act and Clean Water Act. The plaintiffs have since filed a motion to withdraw their motion for a TRO on April 30, 2008, pending good-faith negotiations between the plaintiffs, Loadout, and Loadout’s designated operator, Coal River Mining, LLC, to reach an agreement over the Nellis Section 404 permit. Because of the limited volume of projected coal to be produced from the Nellis Surface Mine relative to total production from all PVR holdings, it is not expected that either a settlement of this matter or possible delay in proceeding with mining pending litigation would materially affect PVR’s business interests.

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Item 6 Exhibits

12.1	Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.
31.1	Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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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 9, 2008	By:	/s/ Frank A. Pici
		Frank A. Pici
		Executive Vice President and Chief Financial Officer
Date:    May 9, 2008	By:	/s/ Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller