10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 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 August 6, 2008, 41,836,363 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

INDEX

		Page
PART I.	Financial Information
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Six Months Ended June 30, 2008 and 2007	1
	Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007	2
	Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2008 and 2007	3
	Notes to Consolidated Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	55
PART II.	Other Information
Item 6.	Exhibits	56

PART I.    FINANCIAL INFORMATION

Item 1 Financial Statements

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME – unaudited

(in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Revenues
Natural gas	$	113,212		$	72,032		$	193,725		$	128,651
Crude oil		14,463			4,533			23,678			8,686
Natural gas liquids (NGL)		6,538			1,217			8,406			2,168
Natural gas midstream		184,298			114,407			309,346			209,725
Coal royalties		31,641			24,029			55,603			49,029
Other		10,262			6,180			18,791			10,409
Total revenues		360,414			222,398			609,549			408,668
Expenses
Cost of midstream gas purchased		152,986			95,077			252,683			174,808
Operating		22,214			15,522			43,216			29,955
Exploration		6,739			5,667			11,419			10,737
Taxes other than income		8,259			5,463			15,654			10,839
General and administrative		19,058			15,049			36,717			30,100
Depreciation, depletion and amortization		44,934			28,546			83,503			56,616
Total expenses		254,190			165,324			443,192			313,055
Operating income		106,224			57,074			166,357			95,613
Other income (expense)
Interest expense		(10,110	)		(8,308	)		(19,662	)		(15,035	)
Interest income and other		975			544			3,306			1,960
Derivatives		(103,618	)		(892	)		(129,519	)		(17,613	)
Income (loss) before minority interest and income taxes		(6,529	)		48,418			20,482			64,925
Minority interest		3,948			9,228			23,976			18,524
Income tax expense (benefit)		(6,684	)		15,312			(3,627	)		18,120
Net income (loss)	$	(3,793	)	$	23,878		$	133		$	28,281
Net income (loss) per share, basic	$	(0.09	)	$	0.63		$	0.00		$	0.75
Net income (loss) per share, diluted	$	(0.09	)	$	0.63		$	0.00		$	0.74
Weighted average shares outstanding, basic		41,740			37,750			41,642			37,682
Weighted average shares outstanding, diluted		41,740			38,055			41,916			37,962

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)

	June 30, 2008			December 31, 2007
Assets
Current assets
Cash and cash equivalents	$	43,480		$	34,527
Accounts receivable		256,471			179,120
Deferred income taxes		49,985			16,273
Derivative assets		4,795			5,683
Other		13,747			8,469
Total current assets		368,478			244,072
Property and equipment
Oil and gas properties (successful efforts method)		1,736,653			1,525,728
Other property and equipment		927,067			859,380
		2,663,720			2,385,108
Accumulated depreciation, depletion and amortization		(566,735	)		(486,094	)
Net property and equipment		2,096,985			1,899,014
Equity investments		77,222			25,640
Goodwill		7,718			7,718
Intangibles, net		27,196			28,938
Derivative assets		—			310
Other assets		63,350			47,769
Total assets	$	2,640,949		$	2,253,461
Liabilities and Shareholders’ Equity
Current liabilities
Current maturities of long-term debt	$	58,083		$	12,561
Accounts payable and accrued liabilities		262,227			205,127
Derivative liabilities		126,683			43,048
Income taxes payable		—			1,163
Total current liabilities		446,993			261,899
Other liabilities		51,801			54,169
Derivative liabilities		21,122			3,030
Deferred income taxes		229,283			193,950
Long-term debt of the Company		435,000			352,000
Long-term debt of subsidiary		323,100			399,153
Minority interests of subsidiaries		275,294			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; 41,836,314 and 41,408,497 shares issued and outstanding at June 30, 2008 and December 31, 2007		229			225
Paid-in capital		537,407			485,998
Retained earnings		327,669			332,223
Deferred compensation obligation		1,923			1,608
Accumulated other comprehensive income		(6,403	)		(7,936	)
Treasury stock – 87,705 and 77,924 shares common stock, at cost, on June 30, 2008 and December 31, 2007		(2,469	)		(2,020	)
Total shareholders’ equity		858,356			810,098
Total liabilities and shareholders’ equity	$	2,640,949		$	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 June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Cash flows from operating activities
Net income (loss)	$	(3,793	)	$	23,878		$	133		$	28,281
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		44,934			28,546			83,503			56,616
Commodity derivative contracts:
Total derivative losses		105,135			2,374			132,144			19,516
Cash received (paid) to settle derivatives		(18,032	)		(1,817	)		(26,985	)		1,695
Deferred income taxes		(3,110	)		10,719			(505	)		12,684
Minority interest		3,948			9,228			23,976			18,524
Dry hole and unproved leasehold expense		5,919			4,330			9,472			8,716
Other		987			745			(1,174	)		1,271
Changes in operating assets and liabilities		(17,248	)		(10,147	)		(35,672	)		(14,506	)
Net cash provided by operating activities		118,740			67,856			184,892			132,797
Cash flows from investing activities
Acquisitions		(111,367	)		(72,389	)		(116,107	)		(76,224	)
Additions to property and equipment		(120,512	)		(94,531	)		(229,174	)		(199,302	)
Other		334			196			739			243
Net cash used in investing activities		(231,545	)		(166,724	)		(344,542	)		(275,283	)
Cash flows from financing activities
Dividends paid		(2,342	)		(2,124	)		(4,686	)		(4,240	)
Distributions paid to minority interest holders		(14,172	)		(12,445	)		(27,912	)		(23,465	)
Proceeds from (repayments of) Company borrowings		29,000			54,500			83,000			107,500
Proceeds from (repayments of) PVR borrowings		(32,600	)		52,000			(30,600	)		57,000
Net proceeds from issuance of PVR partners’ capital		138,015			—			138,015			—
Other		5,504			6,621			10,786			7,564
Net cash provided by financing activities		123,405			98,552			168,603			144,359
Net increase (decrease) in cash and cash equivalents		10,600			(316	)		8,953			1,873
Cash and cash equivalents – beginning of period		32,880			22,527			34,527			20,338
Cash and cash equivalents – end of period	$	43,480		$	22,211		$	43,480		$	22,211
Supplemental disclosures:
Cash paid for:
Interest (net of amounts capitalized)	$	10,654		$	7,183		$	17,891		$	14,767
Income taxes	$	934		$	279		$	2,179		$	302

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

June 30, 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. As of June 30, 2008, PVG owned an approximately 37% limited partner interest in PVR and 100% of the general partner of PVR, which holds a 2% general partner interest in PVR.

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 in October 2001. PVG completed its initial public offering in December 2006.

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. In July 2008, PVR acquired natural gas midstream assets in the Fort Worth Basin of North Texas. See Note 17 – Subsequent Events. 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 June 30, 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 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

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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 and six months ended June 30, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008.

New Accounting Standards

In May 2008, the Financial Accounting Standards Board (“FASB”) issued Staff Position No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (“FSP APB 14-1”). This standard requires issuers of convertible debt that may be settled wholly or partly in cash to account for the debt and equity components separately. FSP APB 14-1 requires that issuers of convertible debt separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. FSP APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years, and must be applied retrospectively to all periods presented. Early adoption is prohibited. We are currently assessing the impact on the financial statements of adopting FSP APB 14-1 effective January 1, 2009.

The FASB’s Emerging Issues Task Force (“EITF”) has reached a consensus with regards to Issue number 07-5, Determining Whether an Instrument (or Embedded Feature) is Indexed to an Entity’s Own Stock (“EITF 07-5”). EITF 07-5 addresses the determination of whether an equity derivative (or an embedded feature) is indexed to an entity’s own stock. Derivative contracts on a company’s own stock may be accounted for as equity instruments, rather than as assets and liabilities, only if they are both indexed solely to the company’s stock and can be settled in shares. Various adjustment features may change the exercise price or notional amount or otherwise alter the payoff at settlement in a way that raises a question as to whether the instruments are indexed solely to the company’s stock. The EITF reached a consensus that contingent and other adjustment features are consistent with equity indexation if they are based on variables that would be inputs to a “plain vanilla” option or forward pricing model and they do not increase the contract’s exposure to those variables. EITF 07-5 is effective for fiscal years beginning after December 15, 2008. It must initially be applied by recording a cumulative-effect adjustment to opening retained earnings at the date of adoption for the effect of EITF 07-5 on outstanding instruments. We expect no effect on retained earnings as a result of adopting EITF 07-5.

In April 2008, the FASB issued Staff Position No. FAS 142-3, Determination of the Useful Life of Intangible Assets (“FSP FAS 142-3”) which amends Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets. The pronouncement requires companies estimating the useful life of a recognized intangible asset to consider their historical experience in renewing or extending similar arrangements or, in the absence of historical experience, to consider assumptions that market participants would use about renewal or extension. FAS 142-3 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and must be applied prospectively to intangible assets acquired after the effective date. We will prospectively apply FSP FAS 142-3 to all intangible assets purchased after January 1, 2009.

4. Acquisition

In April 2008, PVR acquired a 25% member interest in Thunder Creek Gas Services, LLC (“Thunder Creek”), a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin for $51.6 million in cash, after customary closing adjustments. Funding for the acquisition was provided by borrowings under PVR’s revolving credit facility (the “PVR Revolver”). The entire member interest is recorded in equity investments on the consolidated balance sheet. This investment includes $37.3 million of fair value for the net assets acquired and $14.3 million of fair value paid in excess of PVR’s portion of the underlying equity in the net assets acquired related to customer contracts and related customer relations. This excess is being amortized to equity earnings over the life of the underlying contracts. The earnings are recorded in other revenues on the consolidated income statement.

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5. PVR Unit Offering

In the second quarter of 2008, PVR issued 5.15 million common PVR limited partner units to the public representing limited partner interests and received $138.1 million in net proceeds. PVR received contributions of $2.9 million from its general partner in order to maintain its 2% interest. The net proceeds were used to repay a portion of our borrowings under the PVR Revolver.

6. Gain on Sale of Subsidiary Units

We account for PVR equity issuances as sales of minority interest. For each PVR equity issuance, we have calculated a gain under SEC Staff Accounting Bulletin No. 51 (or Topic 5-H), Accounting for Sales of Stock by a Subsidiary (“SAB 51”). SAB 51 provides guidance on accounting for the effect of issuances of a subsidiary’s stock on the parent’s investment in that subsidiary. In some situations, SAB 51 allows registrants to elect an accounting policy of recording gains or losses on issuances of stock by a subsidiary either in income or as a capital transaction. Accordingly, we adopted a policy of recording SAB 51 gains and losses directly to partners’ capital. As a result of PVR’s unit offerings in May and June 2008, we recognized gains in consolidated shareholders’ equity totaling $39.7 million. See Note 5 – PVR Unit Offering.

7. 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 No. 157 for nonfinancial assets and nonfinancial liabilities to fiscal years and interim 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 June 30, 2008 (in thousands):

Description	Fair Value Measurements, June 30, 2008			Fair Value Measurement at June 30, 2008, Using
				Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Trading securities	$	5,434		$	5,434	$	—		$	—
Interest rate swap liability – current		(1,788	)		—		(1,788	)		—
Interest rate swap liability – noncurrent		(2,606	)		—		(2,606	)		—
Commodity derivative assets – current		4,795			—		4,795			—
Commodity derivative liability – current		(124,895	)		—		(124,895	)		—
Commodity derivative liability – noncurrent		(18,516	)		—		(18,516	)		—
Total	$	(137,576	)	$	5,434	$	(143,010	)	$	—

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Reference Note 8 – Derivative Instruments, for the effects of these instruments on our consolidated statements of income.

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, swaps 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 is a level 2 input. See Note 8 – 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 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 8 – Derivative Instruments.

8. 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).

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. 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.

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.

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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 June 30, 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 June 30, 2008 (in thousands):

		Weighted Average Price						Estimated Fair Value
	Average Volume Per Day	Additional Put Option		Floor		Ceiling
Natural Gas Costless Collars	(in MMBtus)	(per MMBtu)
Third Quarter 2008	10,000			$	7.50	$	9.10	$	(5,827	)
Fourth Quarter 2008 (1)	10,000			$	7.50	$	9.10		(971	)
Natural Gas Three-way Collars	(in MMBtus)	(per MMBtu)
Third Quarter 2008	22,500	$	5.00	$	7.11	$	9.09		(14,193	)
Fourth Quarter 2008	67,500	$	5.89	$	8.55	$	11.26		(17,670	)
First Quarter 2009	65,000	$	6.00	$	8.67	$	11.68		(17,541	)
Second Quarter 2009	40,000	$	6.38	$	8.75	$	10.79		(6,344	)
Third Quarter 2009	40,000	$	6.38	$	8.75	$	10.79		(6,733	)
Fourth Quarter 2009	30,000	$	6.83	$	9.50	$	13.60		(2,748	)
First Quarter 2010	30,000	$	6.83	$	9.50	$	13.60		(3,460	)
Natural Gas Swaps
Third Quarter 2008	45,000			$	9.03				(17,576	)
Natural Gas Basis Swaps	(in MMBtus)	(per MMBtu)
Third Quarter 2008	15,000			$	0.39				(87	)
Fourth Quarter 2008	15,000			$	0.39				(72	)
Crude Oil Three-Way Collars	(Bbl)	(Bbl)
Third Quarter 2008	500	$	70.00	$	95.00	$	108.80		(1,476	)
Fourth Quarter 2008	500	$	80.00	$	110.00	$	179.00		(59	)
First Quarter 2009	500	$	80.00	$	110.00	$	179.00		(116	)
Second Quarter 2009	500	$	80.00	$	110.00	$	179.00		(144	)
Third Quarter 2009	500	$	80.00	$	110.00	$	179.00		(170	)
Fourth Quarter 2009	500	$	80.00	$	110.00	$	179.00		(183	)
Settlements to be paid in subsequent period									(378	)
Oil and gas segment commodity derivatives – net liability								$	(95,748	)

(1) This position expires in October 2008.

At June 30, 2008, we reported a net derivative liability related to the oil and gas commodity derivatives of $95.7 million. Reference the Adoption of SFAS No. 161 section below for the impact of the oil and gas commodity derivatives on our consolidated statements of income.

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 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.

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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 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 June 30, 2008, the credit risks of the counterparties and PVR’s own credit risk. The following table sets forth PVR’s positions as of June 30, 2008 for commodities related to natural gas midstream revenues and cost of midstream gas purchased (in thousands):

				Weighted Average Price Collars
	Average Volume Per Day	Weighted Average Price		Additional Put Option		Put		Call		Estimated Fair Value
Frac Spread	(in MMBtu)	(per MMBtu)
Third Quarter 2008 through Fourth Quarter 2008	7,824	$	5.02							$	(5,944	)
Ethane Sale Swap	(in gallons)	(per gallon)
Third Quarter 2008 through Fourth Quarter 2008	34,440	$	0.4700								(4,774	)
Propane Sale Swaps	(in gallons)	(per gallon)
Third Quarter 2008 through Fourth Quarter 2008	26,040	$	0.7175								(5,675	)
Crude Oil Sale Swaps	(in barrels)	(per barrel)
Third Quarter 2008 through Fourth Quarter 2008	560	$	49.27								(9,334	)
Natural Gasoline Collar	(in gallons)					(per gallon)
Third Quarter 2008 through Fourth Quarter 2008	6,300					$	1.4800	$	1.6465		(1,611	)
Crude Oil Collar	(in barrels)					(per barrel)
Third Quarter 2008 through Fourth Quarter 2008	400					$	65.00	$	75.25		(4,784	)
Natural Gas Sale Swaps	(in MMBtu)	(per MMBtu)
Third Quarter 2008 through Fourth Quarter 2008	4,000	$	6.97								4,795
Crude Oil Three-Way Collar	(in barrels)					(per gallon)
First Quarter 2009 through Fourth Quarter 2009	1,000			$	70.00	$	90.00	$	119.25		(10,292	)
Frac Spread Collar (1)	(in MMBtu)					(in MMBtu)
First Quarter 2009 through Fourth Quarter 2009	6,000					$	9.09	$	13.94		—
Settlements to be paid in subsequent period											(5,246	)
Natural gas midstream segment commodity derivatives – net liability										$	(42,865	)

(1) PVR entered into this contract in July 2008.

At June 30, 2008, PVR reported a (i) net derivative liability related to the natural gas midstream segment of $42.9 million and (ii) loss in accumulated other comprehensive income (“AOCI”) of $1.9 million related to derivatives in the natural gas midstream segment, net of the related income tax benefit of $1.0 million, for which we

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discontinued hedge accounting in 2006. The $1.9 million loss, net of the related income tax benefit of $1.0 million, will be recorded in earnings through the end of 2008 as the hedged transactions settle. Reference the Adoption of SFAS No. 161 section below for the impact of the natural gas midstream commodity derivatives on our consolidated statements of income.

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 London Interbank Offered Rate (“LIBOR”). Settlements on the Revolver Swaps are recorded as interest expense. The 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 expense. We reported a (i) derivative liability of $2.0 million at June 30, 2008 and (ii) loss in accumulated other comprehensive income of $1.3 million, net of the related income tax benefit of $0.7 million, at June 30, 2008 related to the Revolver Swaps. In connection with periodic settlements, we recognized $0.3 million and $0.4 million in net hedging losses on the Revolver Swaps in interest expense for the three and six months ended June 30, 2008.

Interest Rate Swaps—PVR

PVR 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 expense. PVR reported a (i) derivative liability of $2.4 million at June 30, 2008 and (ii) loss in accumulated other comprehensive income of $1.6 million, net of the related income tax benefit of $0.8 million, at June 30, 2008 related to the PVR Revolver Swaps. In connection with periodic settlements, we recognized $0.6 million and $0.4 million in net hedging losses on the PVR Revolver Swaps, in interest expense for the three and six months ended June 30, 2008.

Adoption of SFAS No. 161

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of FASB Statement No. 133, which amends and expands SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. We elected to adopt SFAS No. 161 early, effective June 30, 2008. SFAS No. 161 requires companies to disclose how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.

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The following table summarizes the effects of our consolidated derivative activities, as well as the location of the gains and losses, on our consolidated statements of income for the three and six months ended June 30, 2008 (in thousands):

	Location of gain (loss) on derivatives recognized in income	Three Months Ended June 30,			Six Months Ended June 30,
		2008			2008
Derivatives designated as hedging instruments under SFAS No. 133:
Interest rate contracts (1)	Interest expense	$	(955	)	$	(712	)
Decrease in net income resulting from derivatives designated as hedging instruments under SFAS No. 133		$	(955	)	$	(712	)
Derivatives not designated as hedging instruments under SFAS No. 133:
Commodity contracts (1)	Natural gas midstream revenues	$	(1,997	)	$	(4,248	)
Commodity contracts (1)	Cost of midstream gas purchased		480			1,623
Commodity contracts	Derivatives		(103,618	)		(129,519	)
Decrease in net income resulting from derivatives not designated as hedging instruments under SFAS No. 133		$	(105,135	)	$	(132,144	)
Total decrease in net income resulting from derivatives		$	(106,090	)	$	(132,856	)
Realized and unrealized derivative impact:
Cash received (paid) for commodity contract settlements	Derivatives	$	(18,032	)	$	(26,985	)
Cash received (paid) for interest rate contract settlements	Interest expense		(955	)		(712	)
Unrealized derivative loss	(2)		(87,103	)		(105,159	)
Decrease in net income		$	(106,090	)	$	(132,856	)

(1) These amounts represent reclassifications from AOCI. Subsequent to the discontinuation of hedge accounting for commodity derivatives in 2006, amounts remaining in AOCI have been reclassified into earnings in the same period or periods during which the original hedge forecasted transaction affects earnings. The amount remaining in AOCI that will be reclassified to earnings in future periods is $1.9 million, net of related income taxes of $1.0 million.

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

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

		Derivatives Assets		Derivatives Liabilities
	Balance Sheet Location	Estimated fair values as of June 30, 2008
Derivatives designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivative liabilities – current	$	—	$	1,788
Interest rate contracts	Derivative liabilities – noncurrent		—		2,606
Total derivatives designated as hedging instruments under SFAS No. 133		$	—	$	4,394
Derivatives not designated as hedging instruments under SFAS No. 133:
Commodity contracts	Derivative assets/liabilities – current	$	4,795	$	124,895
Commodity contracts	Derivative assets/liabilities – noncurrent		—		18,516
Total derivatives not designated as hedging instruments under SFAS No. 133		$	4,795	$	143,411
Total estimated fair value of derivative instruments		$	4,795	$	147,805

The following table summarizes the effect of the Revolver Swaps and the PVR Revolver Swaps on our total interest expense for the three and six months ended June 30, 2008 (in thousands):

	Three Months Ended			Six Months Ended
Source	June 30, 2008
Interest on borrowings	$	(9,851	)	$	(20,688	)
Capitalized interest (1)		696			1,738
Interest rate swaps		(955	)		(712	)
Total interest expense	$	(10,110	)	$	(19,662	)

(1) Capitalized interest for the three and six months ended June 30, 2008 was primarily related to the construction of PVR’s natural gas gathering facilities and the preparation of unproved oil and gas properties for their development.

The above derivative activity represents cash flow hedges. As of June 30, 2008, neither PVR nor we owned derivative instruments that were classified as fair value hedges, nor were any derivative instruments owned by PVR or we classified as trading securities. In addition, as of June 30, 2008, neither PVR nor we owned derivative instruments containing credit risk contingencies.

9. PVR Senior Notes Repayment

In June 2008, PVR notified the holders of its Senior Unsecured Notes due 2013 (the “PVR Notes”) that it would prepay 100% of the aggregate principal amount of the PVR Notes as provided in the Note Purchase Agreements governing the PVR Notes. In July 2008, PVR paid an aggregate of $63.3 million to the noteholders, which amount consists of approximately $58.4 million aggregate principal amount outstanding on the PVR Notes, $1.1 million in accrued and unpaid interest on the PVR Notes through the prepayment date and $3.8 million in make-whole amounts due in connection with the prepayment of the PVR Notes. The PVR Notes were repaid with borrowings under the PVR Revolver. As a result of calling these notes in June 2008, the PVR Notes are included in the current liabilities section of our consolidated balance sheet.

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10. Income Taxes

The total liability for unrecognized tax benefits at June 30, 2008 was $5.7 million, including $4.2 million of tax positions which would change the effective tax rate, if recognized. During the three and six months ended June 30, 2008, the liability for unrecognized tax benefits decreased by $4.5 million relating to settlements with taxing authorities.

We are currently evaluating the filing status of a subsidiary in two states. If management and the states’ taxing authority determine that the subsidiary’s income is taxable in those states, it is reasonably possible that payments totaling approximately $3.0 million will be made within the next 12 months. We classified $3.0 million of the total liability for unrecognized tax benefits as a current liability on the condensed consolidated balance sheet at June 30, 2008. This current liability represents our best estimate of the change in unrecognized tax benefits that we expect to occur within the next 12 months.

The 2008 effective income tax rates include the effects settlements of liabilities for unrecognized tax benefits for the three and six months ended June 30, 2008.

11. 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 and six months ended June 30, 2008 and 2007:

	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008		2007
	(in thousands, except per share data)					(in thousands, except per share data)
Net income (loss)	$	(3,793	)	$	23,878	$	133	$	28,281
Weighted average shares, basic		41,740			37,750		41,642		37,682
Effect of dilutive securities:
Stock options (1)		—			305		274		280
Weighted average shares, diluted		41,740			38,055		41,916		37,962
Net income (loss) per share, basic	$	(0.09	)	$	0.63	$	0.00	$	0.75
Net income (loss) per share, diluted	$	(0.09	)	$	0.63	$	0.00	$	0.74

(1) For the three months ended June 30, 2008, 0.3 million stock options had the effect of being anti-dilutive and were therefore excluded from the calculation of diluted earnings per share.

12. 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 June 30, 2008 and 2007, we recognized a total of $1.6 million and $0.9 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 $0.6 million and $0.4 million for the three months ended June 30, 2008 and 2007. For the six months ended June 30, 2008 and 2007, we recognized a total of $2.7 million and $2.0 million of compensation expense related to our stock compensation plans. The total income tax benefit recognized in our consolidated statements of income for our stock compensation plans was $1.0 million and $0.8 million for the six months ended June 30, 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. We recognize compensation expense on a straight-line basis over the vesting period.

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

PVR recognized a total of $0.7 million and $0.6 million for the three months ended June 30, 2008 and 2007 and $1.5 million and $1.1 million for the six months ended June 30, 2008 and 2007 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 six months ended June 30, 2008, 131,551 restricted units with a weighted average grant date fair value of $26.93 per unit were granted to employees of Penn Virginia and its affiliates. During the six months ended June 30, 2008, 70,007 restricted units with a weighted average grant date fair value of $27.27 per unit vested. The restricted units granted in 2008 vest over a three-year period, with one-third vesting in each year. PVR recognizes compensation expense on a straight-line basis over the vesting period.

13. 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 and six months ended June 30, 2008 and 2007:

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(in thousands)						(in thousands)
Net income (loss)	$	(3,793	)	$	23,878		$	133		$	28,281
Unrealized holding gains (losses) on derivative activities, net of tax		3,632			994			(719	)		710
Reclassification adjustment for derivative activities, net of tax		1,609			850			2,171			1,013
Pension plan adjustment		40			(35	)		81			(71	)
Comprehensive income	$	1,488		$	25,687		$	1,666		$	29,933

14. Suspended Well Costs

Two exploratory wells that were pending determination of proved reserves as of December 31, 2007 were subsequently determined to be successful. Accordingly, we reclassified $2.6 million of capitalized exploratory drilling costs related to these wells to wells, equipment and facilities during the three and six months ended June 30, 2008.

Two exploratory wells that were pending determination of proved reserves as of December 31, 2007 were subsequently determined to be unsuccessful. Accordingly, we charged to expense $1.1 million and $1.8 million of capitalized exploratory drilling costs related to these wells during the three and six months ended June 30, 2008.

15. 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 our financial condition or results of operations. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations.

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

As of June 30, 2008 and December 31, 2007, PVR’s environmental liabilities included $1.3 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.

16. 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 tables present a summary of certain financial information relating to our segments as of and for the three and six months ended June 30, 2008 and 2007:

	Oil and Gas			PVR Coal and Natural Resource Management			PVR Natural Gas Midstream		Eliminations and Other			Consolidated
	(in thousands)
For the Three Months Ended June 30, 2008:
Revenues	$	134,964		$	39,254		$	186,353	$	(157	)	$	360,414
Intersegment revenues (1)		(597	)		(198	)		51,096		(50,301	)		—
Operating costs and expenses		33,081			7,547			211,710		(43,082	)		209,256
Depreciation, depletion and amortization		31,568			7,526			5,393		447			44,934
Operating income (loss)	$	69,718		$	23,983		$	20,346	$	(7,823	)		106,224
Interest expense													(10,110	)
Interest income and other													975
Derivatives													(103,618	)
Income before minority interest and taxes												$	(6,529	)
Total assets (2)	$	1,462,243		$	697,758		$	403,453	$	77,495		$	2,640,949
Equity investments (3)	$	—		$	25,030		$	52,192	$	—		$	77,222
Additions to property and equipment and acquisitions	$	114,213		$	24,641		$	92,769	$	256		$	231,879
For the Three Months Ended June 30, 2007:
Revenues	$	78,567		$	28,212		$	115,312	$	307		$	222,398
Intersegment revenues (1)		(422	)		198			422		(198	)		—
Operating costs and expenses		23,839			5,524			101,416		5,999			136,778
Depreciation, depletion and amortization		18,632			5,320			4,502		92			28,546
Operating income (loss)	$	35,674		$	17,566		$	9,816	$	(5,982	)		57,074
Interest expense													(8,308	)
Interest income and other													544
Derivatives													(892	)
Income before minority interest and taxes												$	48,418
Total assets	$	1,031,555		$	362,383		$	405,691	$	50,263		$	1,849,892
Equity investments	$	—		$	26,173		$	60	$	—		$	26,233
Additions to property and equipment and acquisitions	$	101,333		$	52,130		$	11,859	$	1,598		$	166,920

(1) Intersegment revenues represent gas gathering and processing transactions for the three months ended June 30, 2008 between the PVR natural gas midstream segment and PVOG. The PVR natural gas midstream segment gathered and processed the natural gas delivered by PVOG and then purchased the processed gas and NGLs from PVOG for $49.8 million to sell to third parties. The intersegment revenues line also 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 accumulated depreciation and depletion associated with this royalty interest. These amounts are represented in the Eliminations and Other column.

(3) This increase in equity investments is due to the 25% member interest in Thunder Creek that PVR acquired in the second quarter of 2008 for $51.6 million. See Note 4 – Acquisition.

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	Oil and Gas			PVR Coal and Natural Resource Management			PVR Natural Gas Midstream		Eliminations and Other			Consolidated
	(in thousands)
For the Six Months Ended June 30, 2008:
Revenues	$	227,736		$	69,746		$	312,400	$	(333	)	$	609,549
Intersegment revenues (1)		(1,070	)		(396	)		51,569		(50,103	)		—
Operating costs and expenses		62,412			13,846			319,491		(36,060	)		359,689
Depreciation, depletion and amortization		58,184			13,939			10,480		900			83,503
Operating income (loss)	$	106,070		$	41,565		$	33,998	$	(15,276	)		166,357
Interest expense													(19,662	)
Interest income and other													3,306
Derivatives													(129,519	)
Income before minority interest and taxes												$	20,482
Total assets (2)	$	1,462,243		$	697,758		$	403,453	$	77,495		$	2,640,949
Equity investments (3)	$	—		$	25,030		$	52,192	$	—		$	77,222
Additions to property and equipment and acquisitions	$	209,402		$	24,689		$	110,391	$	799		$	345,281
For the Six Months Ended June 30, 2007:
Revenues	$	140,920		$	56,498		$	210,710	$	540		$	408,668
Intersegment revenues (1)		(740	)		396			740		(396	)		—
Operating costs and expenses		45,451			10,618			188,049		12,321			256,439
Depreciation, depletion and amortization		36,476			10,810			9,145		185			56,616
Operating income (loss)	$	58,253		$	35,466		$	14,256	$	(12,362	)		95,613
Interest expense													(15,035	)
Interest income and other													1,960
Derivatives													(17,613	)
Income before minority interest and taxes												$	64,925
Total assets	$	1,031,555		$	362,383		$	405,691	$	50,263		$	1,849,892
Equity investments	$	—		$	26,173		$	60	$	—		$	26,233
Additions to property and equipment and acquisitions	$	201,058		$	53,466		$	17,864	$	3,138		$	275,526

(1) Intersegment revenues represent gas gathering and processing transactions for the six months ended June 30, 2008 between the PVR natural gas midstream segment and PVOG. The PVR natural gas midstream segment gathered and processed the natural gas delivered by PVOG and then purchased the processed gas and NGLs from PVOG for $49.8 million to sell to third parties. The intersegment revenues line also 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. These amounts are represented in the Eliminations and Other column.

(3) This increase in equity investments is due to the 25% member interest in Thunder Creek that PVR acquired in the second quarter of 2008 for $51.6 million. See Note 4 – Acquisition.

17. Subsequent Events

On July 17, 2008, PVR completed an acquisition of Lone Star Gathering, L.P. in the Fort Worth Basin of North Texas, which included gas gathering and transportation equipment. PVR acquired this business for approximately $160.0 million and a $5.0 million payment guarantee at a later date, plus contingent payments of $30.0 million and $25.0 million. Funding for the acquisition was provided by $80.0 million of borrowings under the PVR Revolver, 2.0 million PVG common units (which PVR purchased from two of our subsidiaries) and 0.5 million newly issued PVR common units. The contingent payments will be triggered if a defined geographic area in which a subset of the acquired assets are located reaches certain revenue targets by or before June 30, 2013 and will be funded in cash or PVR common units, at PVR’s election.

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On July 31, 2008, we completed the sale of certain oil and gas properties in Louisiana for cash proceeds of $32.0 million. These properties were classified as unproved property as of June 30, 2008 on the consolidated balance sheet. Substantially all of the cash proceeds will be recognized as a gain on sale of properties in the third quarter.

On August 5, 2008, PVR amended and restated the PVR Revolver to increase its available borrowings under the PVR Revolver from $600.0 million to $700.0 million and to make it a secured facility. The PVR Revolver is secured by substantially all of PVR’s assets.

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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. At June 30, 2008, PVG owned a 37% limited partner interest in PVR and 100% of the general partner of PVR, which held 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. Our operating income was $166.4 million in the six months ended June 30, 2008, compared to $95.6 million in the same period of 2007. In the six months ended June 30, 2008, the oil and gas segment contributed $106.1 million, or 64%, to operating income, the PVR coal and natural resource management segment contributed $41.6 million, or 25%, to operating income, and the PVR natural gas midstream segment contributed $34.0 million, or 20%, to operating income.

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		Eliminations and Other			Consolidated
For the Six Months Ended June 30, 2008:
Revenues	$	226,666	$	69,350	$	363,969	$	(50,436	)	$	609,549
Operating costs and expenses		62,412		13,846		319,491		(36,060	)		359,689
Depreciation, depletion and amortization		58,184		13,939		10,480		900			83,503
Operating income (loss)	$	106,070	$	41,565	$	33,998	$	(15,276	)	$	166,357
For the Six Months Ended June 30, 2007:
Revenues	$	140,180	$	56,894	$	211,450	$	144		$	408,668
Operating costs and expenses		45,451		10,618		188,049		12,321			256,439
Depreciation, depletion and amortization		36,476		10,810		9,145		185			56,616
Operating income (loss)	$	58,253	$	35,466	$	14,256	$	(12,362	)	$	95,613

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 six months ended June 30, 2008, we produced 22.0 Bcfe, a 17% increase compared to 18.8 Bcfe in the same period of 2007.

In Harrison County, Texas, we drilled a successful horizontal Lower Bossier Shale well. Initially due to gathering system restrictions, the flow rate was curtailed to approximately 5.0 Mmcf per day. After approximately one month of production, the well is currently producing 4.0 Mmcf per day. Based on this successful horizontal test, additional horizontal Lower Bossier Shale wells will be drilled in the second half of 2008.

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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.

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 six months ended June 30, 2008, PVR’s lessees produced 16.5 million tons of coal from its properties and paid PVR coal royalties revenues of $55.6 million, for an average royalty per ton of $3.37. Approximately 86% of PVR’s coal royalties revenues in the six months ended June 30, 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 lessees’ customers to change operations significantly or incur substantial costs.

To a lesser extent, coal prices also impact coal royalties revenues. Generally, as coal prices change, PVR’s average royalty per ton also changes because the majority of PVR’s lessees pay royalties based on the gross sales prices of the coal mined. Most of PVR’s coal is sold by its lessees under contracts with a duration of one year or more; therefore, changes to PVR’s average royalty occur as 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 and 2008, U.S.-produced coal enjoyed increased demand abroad as dwindling supplies and the decline of the dollar made U.S.-exported coal more attractive.

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, the panhandle of Texas and East Texas. These assets include approximately 3,863 miles of natural gas gathering pipelines as of June 30, 2008. In July 2008, PVR completed the acquisition of Lone Star Gathering, L.P. (the “Lone Star Acquisition”) in which it acquired approximately 132 additional miles of gas

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gathering pipelines in the Fort Worth Basin in North Texas. See Note 17 – Subsequent Events in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements.” 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. In addition, PVR owns a 25% member interest in Thunder Creek Gas Services, LLC (“Thunder Creek”), a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin.

For the six months ended June 30, 2008, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 41.2 Bcf, or approximately 226 MMcfd. For the six months ended June 30, 2008, one of PVR’s natural gas midstream customers accounted for 24% of PVR’s natural gas midstream revenues and 14% 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.

Eliminations and Other

Eliminations and other primarily represents elimination of intercompany sales, corporate functions and the oil and gas segment derivatives.

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.

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As of June 30, 2008, we owned the general partner of PVG and an approximately 82% limited partner interest in PVG. As a result of PVR’s unit offerings, both we and PVG recognized gains in partners’ capital. See Note 6 – Gain on Sale of Subsidiary Units in the Notes to Financial Statements in Item 1, “Financial Statements.” PVG also owns 100% of the general partner of PVR, which holds a 2% general partner interest in PVR, and all the incentive distribution rights. As a result of PVR’s unit offerings in May and June 2008, PVG’s ownership interest in PVR decreased from 42% to 37%. See Note 5 – PVR Unit Offerings in the Notes to Financial Statements in Item 1, “Financial Statements.” We directly owned an additional 0.2% limited partner interest in PVR as of June 30, 2008. The following diagram depicts our ownership of PVG and PVR as of June 30, 2008:

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.

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The following table summarizes our cash flow statements for the six months ended June 30, 2008 and 2007 (in thousands):

For The Six Months Ended June 30, 2008:	Oil and Gas & Corporate			PVR			Consolidated
Net cash provided by operating activities	$	111,565		$	73,327		$	184,892
Cash flows from financing activities:
Dividends paid		(4,686	)		—			(4,686	)
Distributions received (paid)		22,446			(50,358	)		(27,912	)
Debt borrowings, net		83,000			(30,600	)		52,400
Proceeds received from (paid for) issuance of PVR partners’ capital		(2,943	)		140,958			138,015
Other		11,406			(620	)		10,786
Net cash provided by financing activities		109,223			59,380			168,603
Net cash provided by operating and financing activities		220,788			132,707			353,495
Net cash used in investing activities		(210,137	)		(134,405	)		(344,542	)
Net increase (decrease) in cash and cash equivalents	$	10,651		$	(1,698	)	$	8,953
For the Six Months Ended June 30, 2007:	Oil and Gas & Corporate			PVR			Consolidated
Net cash provided by operating activities	$	75,481		$	57,316		$	132,797
Cash flows from financing activities:
Dividends paid		(4,240	)		—			(4,240	)
Distributions received (paid)		19,515			(42,980	)		(23,465	)
Debt borrowings, net		107,500			57,000			164,500
Other		6,704			860			7,564
Net cash provided by financing activities		129,479			14,880			144,359
Net cash provided by operating and financing activities		204,960			72,196			277,156
Net cash used in investing activities		(204,150	)		(71,133	)		(275,283	)
Net increase in cash and cash equivalents	$	810		$	1,063		$	1,873

Cash provided by operating activities of the oil and gas segment and corporate increased by $36.1 million, or 48%, from $75.5 million in the six months ended June 30, 2007 to $111.6 million in the same period of 2008. This increase was primarily attributable to an increase in the oil and gas segment’s operating income, partially offset by an increase in cash paid for derivative settlements.

Cash provided by operating activities for PVR increased by $16.0 million, or 28%, from $57.3 million in the six months ended June 30, 2007 to $73.3 million in the same period of 2008. This increase was primarily attributable to the increase in PVR’s natural gas midstream segment’s operating income, partially offset by an increase in cash paid for natural gas midstream derivative settlements.

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Capital Expenditures

Capital expenditures, which comprise the primary portion of cash used in investing activities, totaled $356.0 million in the six months ended June 30, 2008, compared to $281.8 million in the same period of 2007. The following table sets forth capital expenditures by segment during the six months ended June 30, 2008 and 2007:

	Six Months Ended June 30,
	2008		2007
	(in thousands)
Oil and gas
Proved property acquisitions	$	—	$	8,507
Development drilling		175,187		147,343
Exploration drilling		11,497		27,704
Seismic		1,029		1,582
Lease acquisition and other		19,734		12,868
Pipeline, gathering and facilities		13,693		10,192
Total		221,140		208,196
Coal and natural resource management
Acquisitions		24,579		52,456
Expansion capital		—		52
Other property and equipment		110		85
Total		24,689		52,593
Natural gas midstream
Acquisitions		67,651		—
Expansion capital		35,026		12,540
Other property and equipment		7,031		4,635
Total		109,708		17,175
Other		507		3,802
Total capital expenditures	$	356,044	$	281,766

In the six months ended June 30, 2008, the oil and gas segment made aggregate capital expenditures of $221.1 million primarily for development drilling in the East Texas region. In the six months ended June 30, 2007, the oil and gas segment made aggregate capital expenditures of $208.2 million primarily for development drilling in the East Texas region and exploration drilling.

In the six months ended June 30, 2008, PVR’s natural gas midstream segment made aggregate capital expenditures of $109.7 million, primarily related to PVR’s 25% member interest acquisition of Thunder Creek, a deposit paid in connection with the Lone Star Acquisition and expansion capital expenditures related to the Spearman Natural Gas Processing Plant in the Texas Panhandle (“Spearman plant”) and Crossroads Natural Gas Processing plant in East Texas (“Crossroads plant”).

In April 2008, PVR’s natural gas midstream segment acquired a gathering business in north Texas for approximately $7.8 million, which expanded PVR’s existing gathering system in the Beaver/Perryton area. In May 2008, PVR’s coal and natural resource management segment acquired approximately 29 million tons of coal reserves and an estimated 56 million board feet of hardwood timber in western Virginia and eastern Kentucky for approximately $24.5 million, after customary closing adjustments. These acquisitions were funded by borrowings under the PVR’s revolving credit facility (the “PVR Revolver”).

In the six months ended June 30, 2007, PVR’s coal and natural resource management segment made aggregate capital expenditures of $52.6 million, primarily related to acquisitions of coal reserves, a preparation plant and coal handling facilities. In the six months ended June 30, 2007, PVR’s natural gas midstream segment made aggregate capital expenditures of $17.2 million, primarily for natural gas midstream system expansion projects.

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Other capital expenditures of $3.8 million in the six months ended June 30, 2007 were primarily due to consulting fees related to the implementation of a software system.

We funded oil and gas and other capital expenditures in the six months ended June 30, 2008 and 2007 with borrowings under our revolving credit facility (the “Revolver”) and cash provided by operating activities. PVR funded its coal and natural resource management and natural gas midstream capital expenditures in the six months ended June 30, 2008 and 2007 primarily with cash provided by operating activities and borrowings under the PVR Revolver.

We had $83.0 million of net borrowings under the Revolver in the six months ended June 30, 2008, compared to net borrowings of $107.5 million under the Revolver in the six months ended June 30, 2007. As a result of our partner interests in PVG and PVR, we received cash distributions of $21.3 million in the six months ended June 30, 2008, compared to $10.8 million of cash distributions in the six months ended June 30, 2007. Distributions increased $10.5 million primarily due to PVG increasing its distribution per unit from $0.26 per unit to $0.34 per unit and PVR increasing its distribution from $0.41 per unit to $0.45 per unit. Funds from both of these sources were primarily used for capital expenditures.

PVR had net repayments of $30.6 million in the six months ended June 30, 2008, comprised of net repayments of $24.6 million under the PVR Revolver and net repayments of $6.0 million under the Senior Unsecured Notes due 2013 (the “PVR Notes”). PVR received net proceeds of $138.1 million from the sale of its common units in a public offering in the second quarter of 2008 and $2.9 in contributions from its general partner in order to maintain the general partner’s 2% interest. These proceeds and contributions were partially offset by capital expenditures of $134.4 million in the six months ended June 30, 2008. This is compared to $57.0 million of net borrowings in the six months ended June 30, 2007, comprised of net borrowings of $62.0 million under the Revolver and net repayments of $5.0 million under the PVR Notes. Funds from the borrowings in the six months ended June 30, 2007 were primarily used for capital expenditures.

In July 2008, PVG declared a $0.36 per unit quarterly distribution for the three months ended June 30, 2008, or $1.44 per unit on an annualized basis, of which we will receive $10.8 million. We will receive these distributions 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 June 30, 2008, we had $205.0 million outstanding under the 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 June 30, 2008. At the current $479.0 million limit on the Revolver, and given our outstanding balance of $205.0 million, net of $0.3 million of letters of credit, we could borrow up to $273.7 million at June 30, 2008. In the six months ended June 30, 2008, we incurred commitment fees of $0.4 million on the unused portion of the Revolver. We capitalized $1.1 million of interest cost incurred in the six months ended June 30, 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 six months ended June 30, 2008 was 4.8%.

The financial covenants under the Revolver require us not to 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 June 30, 2008, we were in compliance with all of our covenants under the Revolver.

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Convertible Notes. As of June 30, 2008, we had $230.0 million outstanding of Convertible Senior Subordinated Notes due 2012 (the “Convertible Notes”). 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.

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.

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. In December 2007, we paid an aggregate amount of $18.6 million of the net proceeds from the sale of the Convertible Notes for the cost of the Note Hedges (after such cost was offset by the proceeds of the Warrants described below).

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

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Credit Facility. We have a credit facility with a financial institution, which had no borrowings against it as of June 30, 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 interest rate swap agreements (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 June 30, 2008, the total interest rate on the $50.0 million portion of Revolver borrowings covered by the Revolver Swaps was 6.34% at June 30, 2008.

PVR Revolver. As of June 30, 2008, PVR had $323.1 million outstanding under the PVR Revolver that matures in December 2011. On April 9, 2008, the available borrowings 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 June 30, 2008. At the current $600.0 million limit on the PVR Revolver, and given the outstanding balance of $323.1 million, net of $1.6 million of letters of credit, PVR could borrow up to $275.3 million. In August 2008, PVR increased its available borrowings under the PVR Revolver from $600.0 million to $700.0 million and secured the PVR Revolver with substantially all of PVR’s assets. In the six months ended June 30, 2008, PVR incurred commitment fees of $0.2 million on the unused portion of the PVR Revolver. The interest rate under the PVR Revolver fluctuates based on the ratio of PVR’s total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 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 six months ended June 30, 2008 was 4.6%.

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 June 30, 2008, PVR was in compliance with all of its covenants under the PVR Revolver.

PVR Notes. As of June 30, 2008, PVR owed $58.1 million under the PVR Notes. The PVR Notes bore interest at a fixed rate of 6.02% and were scheduled to mature in March 2013, with semi-annual principal and interest payments.

In June 2008, PVR notified the holders of its Senior Unsecured Notes due 2013 (the “PVR Notes”) that it would prepay 100% of the aggregate principal amount of the PVR Notes as provided in the Note Purchase Agreements governing the PVR Notes. In July 2008, PVR paid an aggregate of $63.3 million to the noteholders, which amount consists of approximately $58.4 million aggregate principal amount outstanding on the PVR Notes, $1.1 million in accrued and unpaid interest on the PVR Notes through the prepayment date and $3.8 million in make-whole amounts due in connection with the prepayment of the PVR Notes. The PVR Notes were repaid with borrowings under the PVR Revolver. As a result of calling these notes in June 2008, PVR reclassified the PVR Notes to the current liabilities section of its condensed consolidated balance sheets.

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PVR Interest Rate Swaps. PVR has entered into interest rate swap agreements (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 June 30, 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 June 30, 2008. In August 2008, PVR entered into an additional interest rate swap with a notional amount of $50.0 million. PVR will pay a weighted average interest rate of 3.877% on the notional amount, and the counterparties will pay a variable rate equal to the three month LIBOR.

PVR Unit Offering

In the second quarter of 2008, PVR issued 5.15 million common PVR limited partner units to the public representing limited partner interests and received $138.1 million in net proceeds. PVR received contributions of $2.9 million from its general partner in order to maintain its 2% interest. The net proceeds were used to repay a portion of our borrowings under the PVR Revolver.

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.

For the remainder of 2008, in addition to the acquisitions mentioned above and in the subsequent events footnote to the financial statements included in this filing, we anticipate making oil and gas segment capital expenditures, excluding acquisitions, of approximately $650.0 million. 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.

We believe our portfolio of assets provides us with opportunities for 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. For the remainder of 2008, in addition to the acquisitions mentioned above and in the subsequent events footnote to the financial statements included in this filing, PVR anticipates making capital expenditures, excluding acquisitions, of $7.5 million, consisting of $2.2 million in the coal and natural resource

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management segment and $5.3 million in the natural gas midstream segment. PVR intends to fund these capital expenditures with a combination of cash flows provided by operating activities, borrowings under the PVR Revolver and possibly with the issuance of additional debt securities. 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 and six months ended June 30, 2008 and 2007:

	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008		2007
	(in thousands, except per share data)					(in thousands, except per share data)
Revenues	$	360,414		$	222,398	$	609,549	$	408,668
Expenses	$	254,190		$	165,324	$	443,192	$	313,055
Operating income	$	106,224		$	57,074	$	166,357	$	95,613
Net income (loss)	$	(3,793	)	$	23,878	$	133	$	28,281
Earnings (loss) per share, basic	$	(0.09	)	$	0.63	$	0.00	$	0.75
Earnings (loss) per share, diluted	$	(0.09	)	$	0.63	$	0.00	$	0.74
Cash flows provided by operating activities	$	118,740		$	67,856	$	184,892	$	132,797

Operating income increased by $49.2 million in the three months ended June 30, 2008 compared to the same period of 2007 primarily due to a $41.2 million increase in natural gas revenues, a $12.0 million increase in natural gas midstream gross margin and a $9.9 million increase in crude oil revenues, partially offset by a $16.4 million increase in depreciation, depletion and amortization (“DD&A”). Operating income increased by $70.7 million in the six months ended June 30, 2008 compared to the same period of 2007 primarily due to a $65.1 million increase in natural gas revenues, a $21.7 million increase in natural gas midstream gross margin and a $15.0 million increase in crude oil revenues, partially offset by a $26.9 million increase in DD&A.

Net income decreased by $27.7 million in the three months ended June 30, 2008 compared to the same period of 2007 primarily due to a $102.7 million increase in derivative expense, partially offset by the $49.2 million increase in operating income. Net income decreased by $28.1 million in the six months ended June 30, 2008 compared to the same period of 2007 primarily due to a $111.9 million increase in derivative expense, partially offset by the $70.7 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 June 30, 2008) reflected as a minority interest in our consolidated financial statements. The assets, liabilities and earnings of PVR are fully consolidated in PVG’s financial statements, with the interest that PVG does not own (61%, after the effect of incentive distribution rights, as of June 30, 2008) reflected as a minority interest in PVG’s condensed consolidated financial statements.

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Oil and Gas Segment

Three Months Ended June 30, 2008 Compared With the Three Months Ended June 30, 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 June 30, 2008 and 2007:

	Three Months Ended June 30,				% Change		Three Months Ended June 30,
	2008		2007				2008		2007
	(in thousands, except as noted)						(per Mcfe) (1)
Financial Highlights
Revenues
Natural gas	$	113,212	$	72,032	57	%	$	11.24	$	7.68
Crude oil		14,463		4,533	219	%		121.54		59.64
NGL		6,538		1,217	437	%		59.98		32.89
Other income		154		363	(58	)%		—		—
Total revenues		134,367		78,145	72	%		11.74		7.77
Expenses
Operating		14,094		10,024	41	%		1.23		1.00
Taxes other than income		7,085		4,646	52	%		0.62		0.46
General and administrative		5,163		3,502	47	%		0.45		0.35
Production costs		26,342		18,172	45	%		2.30		1.81
Exploration		6,739		5,667	19	%		0.59		0.56
Depreciation, depletion and amortization		31,568		18,632	69	%		2.76		1.85
Total expenses		64,649		42,471	52	%		5.65		4.22
Operating income	$	69,718	$	35,674	95	%	$	6.09	$	3.55
Production
Natural gas (MMcf)		10,075		9,381	7	%
Crude oil (Mbbl)		119		76	57	%
NGL (Mbbl)		109		37	195	%
Total production (MMcfe)		11,443		10,060	14	%

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

Production. Approximately 88% and 93% of production in the three months ended June 30, 2008 and 2007 was natural gas. Total production increased by 1.3 Bcfe, or 14%, from 10.1 Bcfe in the three months ended June 30, 2007 to 11.4 Bcfe in the same period of 2008 primarily due to increased production in the East Texas and the Mid-Continent regions, partially offset by decreased production in the Gulf Coast region.

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The following table summarizes total natural gas, crude oil and NGL production and total natural gas, crude oil and NGL revenues by region for the three months ended June 30, 2008 and 2007:

	Natural Gas, Crude Oil and NGL Production		Natural Gas, Crude Oil and NGL Revenues
	Three Months Ended June 30,		Three Months Ended June 30,
Region	2008	2007	2008		2007
	(MMcfe)		(in thousands)
East Texas	3,465	1,631	$	42,272	$	12,774
Mid-Continent	1,653	861		17,637		5,260
Appalachia	2,905	3,123		33,012		24,196
Mississippi	1,819	1,837		20,937		14,415
Gulf Coast	1,601	2,608		20,355		21,137
Total	11,443	10,060	$	134,213	$	77,782

The increased production in the East Texas region is due primarily to aggressive drilling in the region when compared to the three months ended June 30, 2007. The increase in production in the Mid-Continent region is due primarily to high production wells in the Granite Wash area and in coalbed methane. The decrease in production in the Gulf Coast region is due primarily to adverse operating conditions.

In Harrison County, Texas we drilled a successful horizontal Lower Bossier Shale well. Initially due to gathering system restrictions, the flow rate was curtailed to approximately 5.0 Mmcf per day. After approximately one month of production, the well is currently producing 4.0 Mmcf per day. Based on this successful horizontal test, additional horizontal Lower Bossier Shale wells will be drilled in the second half of 2008.

Revenues. Natural gas revenues increased by $41.2 million, or 57%, from $72.0 million in the three months ended June 30, 2007 to $113.2 million in the same period of 2008. Of the $41.2 million increase, $5.3 million was the result of increased natural gas production from drilling and $35.9 million was the result of increased realized prices for natural gas. Our average realized price received for natural gas increased by $3.56 per Mcf, or 46%, from $7.68 per Mcf in the three months ended June 30, 2007 to $11.24 per Mcf in the same period of 2008.

Crude oil revenues increased by $10.0 million, or 219%, from $4.5 million in the three months ended June 30, 2007 to $14.5 million in the same period of 2008. Of the $10.0 million increase, $7.4 million was the result of higher realized prices for crude oil and $2.6 million was the result of increased crude oil production. Our average realized price received for crude oil increased by $61.90 per Bbl, or 104%, from $59.64 per Bbl in the three months ended June 30, 2007 to $121.54 per Bbl in the same period of 2008.

NGL revenues increased by $5.3 million, or 437%, from $1.2 million in the three months ended June 30, 2007 to $6.5 million in the same period of 2008. Of the $5.3 million increase, $2.4 million was the result of increased NGL production from the operation of a new gas processing plant in East Texas and $2.9 million was the result of higher realized prices for NGLs. Our average realized price received for NGLs increased by $27.09 per Bbl, or 82%, from $32.89 per Bbl in the three months ended June 30, 2007 to $59.98 per Bbl in the same period of 2008.

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.

In 2007, we reclassified the remaining amounts in accumulated other comprehensive income to earnings. As a result, in the three months ended June 30, 2008, no derivatives gains or losses were reported as part of natural gas, crude oil and NGL revenues.

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The following table shows a summary of the effects of derivative activities on revenues and realized prices for the three months ended June 30, 2008 and 2007:

	Three Months Ended June 30,
	2008			2007		2008			2007
	(in thousands)					(per Mcf)
Natural gas revenues, as reported	$	113,212		$	72,032	$	11.24		$	7.68
Derivatives losses included in natural gas revenues		—			68		—			0.01
Natural gas revenues before impact of derivatives		113,212			72,100		11.24			7.69
Cash settlements on natural gas derivatives		(8,016	)		326		(0.80	)		0.03
Natural gas revenues, adjusted for derivatives	$	105,196		$	72,426	$	10.44		$	7.72
	(in thousands)					(per Bbl)
Crude oil revenues, as reported	$	14,463		$	4,533	$	121.54		$	59.64
Derivatives losses included in crude oil revenues		—			129		—			1.70
Crude oil revenues before impact of derivatives		14,463			4,662		121.54			61.34
Cash settlements on crude oil derivatives		(313	)		51		(2.63	)		0.67
Crude oil revenues, adjusted for derivatives	$	14,150		$	4,713	$	118.91		$	62.01
	(in thousands)					(per Bbl)
NGL revenues, as reported	$	6,538		$	1,217	$	59.98		$	32.89
Derivatives (gains) losses included in NGL revenues		—			—		—			—
NGL revenues before impact of derivatives		6,538			1,217		59.98			32.89
Cash settlements on NGL derivatives		—			—		—			—
NGL revenues, adjusted for derivatives	$	6,538		$	1,217	$	59.98		$	32.89

Expenses. Aggregate operating costs and expenses increased by $22.1 million, or 52%, from $42.5 million in the three months ended June 30, 2007 to $64.6 million in the same period of 2008 primarily due to increases in operating expenses, taxes other than income, general and administrative expenses, exploration expenses and DD&A.

Operating expenses increased by $4.1 million, or 41%, from $10.0 million, or $1.00 per Mcfe, in the three months ended June 30, 2007 to $14.1 million, or $1.23 per Mcfe, in the same period of 2008. This increase is due primarily to increased compressor rentals in the Mid-Continent and East Texas regions related to facility expansions, where our drilling program is highly active; an increase in repairs and maintenance expenses in the Gulf Coast region related to adverse operating conditions; and an increase in water disposal costs in East Texas related to the increase in equivalent production in that region.

Taxes other than income increased by $2.5 million, or 52%, from $4.6 million in the three months ended June 30, 2007 to $7.1 million in the same period of 2008 primarily due to increased severance taxes related to higher commodity prices and increased production.

General and administrative expenses increased by $1.7 million, or 47%, from $3.5 million in the three months ended June 30, 2007 to $5.2 million in the same period of 2008 primarily due to increased staffing costs in the East Texas and Mid-Continent regions.

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Exploration expenses in the three months ended June 30, 2008 and 2007 consisted of the following:

	Three Months Ended June 30,
	2008		2007
	(in thousands)
Dry hole costs	$	2,113	$	2,329
Geological and geophysical		349		779
Unproved leasehold		3,806		2,001
Other		471		558
Total	$	6,739	$	5,667

Exploration expenses increased by $1.0 million, or 19%, from $5.7 million, or $0.56 per Mcfe, in the three months ended June 30, 2007 to $6.7 million, or $0.59 per Mcfe, in the same period of 2008 primarily due to an increase in unproved leasehold expenses, partially offset by decreases in dry hole costs and geological and geophysical expenses. The increase in unproved leasehold expense is due to leaseholds in the Appalachia, Gulf Coast and East Texas regions that were abandoned in the second quarter of 2008 due to the lack of future drilling potential. Dry hole costs decreased primarily due to the write-off of one exploratory well in the second quarter of 2008 compared to two wells in the second quarter of 2007. A majority of the dry hole expense in the three months ended June 30, 2008 is related to the abandonment of a prospect in Appalachia. The decrease in geological and geophysical expenses is due to the timing of seismic core drilling for horizontal coalbed methane

DD&A expenses increased by $13.0 million, or 69%, from $18.6 million in the three months ended June 30, 2007 to $31.6 million in the same period of 2008 primarily due to the 14% increase in equivalent production and higher depletion rates. Our average depletion rate increased by $0.91 per Mcfe, or 49%, from $1.85 per Mcfe in the three months ended June 30, 2007 to $2.76 per Mcfe in the same period of 2008 due to higher drilling costs and acquisitions.

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Six Months Ended June 30, 2008 Compared With the Six Months Ended June 30, 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 six months ended June 30, 2008 and 2007:

	Six Months Ended June 30,				% Change		Six Months Ended June 30,
	2008		2007				2008		2007
	(in thousands, except as noted)						(per Mcfe) (1)
Financial Highlights
Revenues
Natural gas	$	193,725	$	128,651	51	%	$	9.77	$	7.37
Crude oil		23,678		8,686	173	%		110.64	$	56.77
NGL		8,406		2,168	288	%		58.78		32.36
Other income		857		675	27	%
Total revenues		226,666		140,180	62	%		10.32		7.46
Expenses
Operating		28,303		18,943	49	%		1.29		1.01
Taxes other than income		12,943		8,869	46	%		0.59		0.47
General and administrative		9,747		6,902	41	%		0.44		0.37
Production costs		50,993		34,714	47	%		2.32		1.85
Exploration		11,419		10,737	6	%		0.52		0.57
Depreciation, depletion and amortization		58,184		36,476	60	%		2.65		1.94
Total expenses		120,596		81,927	47	%		5.49		4.36
Operating income	$	106,070	$	58,253	82	%	$	4.83	$	3.10
Production
Natural gas (MMcf)		19,823		17,465	14	%
Crude oil (Mbbl)		214		153	40	%
NGL (Mbbl)		143		67	113	%
Total production (MMcfe)		21,965		18,786	17	%

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

Production. Approximately 90% and 93% of production in the six months ended June 30, 2008 and 2007 was natural gas. Total production increased by 3.2 Bcfe, or 17%, from 18.8 Bcfe in the six months ended June 30, 2007 to 22.0 Bcfe in the same period of 2008 primarily due to increased production in the East Texas and Mid-Continent regions, partially offset by decreased production in the Gulf Coast region.

In Harrison County, Texas we drilled a successful horizontal Lower Bossier Shale well. Initially due to gathering system restrictions, the flow rate was curtailed to approximately 5.0 Mmcf per day. After approximately one month of production, the well is currently producing 4.0 Mmcf per day. Based on this successful horizontal test, additional horizontal Lower Bossier Shale wells will be drilled in the second half of 2008.

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The following table summarizes total natural gas, crude oil and NGL production and total natural gas, crude oil and NGL revenues by region for the six months ended June 30, 2008 and 2007:

	Natural Gas, Crude Oil and NGL Production		Natural Gas, Crude Oil and NGL Revenues
	Six Months Ended June 30,		Six Months Ended June 30,
Region	2008	2007	2008		2007
	(MMcfe)		(in thousands)
East Texas	6,222	3,215	$	67,797	$	24,437
Mid-Continent	3,115	1,672		29,421		10,185
Appalachia	5,745	6,049		55,974		44,974
Mississippi	3,625	3,648		36,219		27,055
Gulf Coast	3,258	4,202		36,398		32,854
Total	21,965	18,786	$	225,809	$	139,505

The increased production in the East Texas region is due primarily to aggressive drilling in the region when compared to the six months ended June 30, 2007. The increase in production in the Mid-Continent region is due primarily to high production wells in the Granite Wash area and in coalbed methane. The decrease in production in the Gulf Coast region is due primarily to adverse operating conditions.

Revenues. Natural gas revenues increased by $65.0 million, or 51%, from $128.7 million in the six months ended June 30, 2007 to $193.7 million in the same period of 2008. Of the $65.0 million increase, $47.7 million was the result of increased realized prices for natural gas and $17.3 million was the result of increased natural gas production from drilling. Our average realized price received for natural gas increased by $2.40 per Mcf, or 33%, from $7.37 per Mcf in the six months ended June 30, 2007 to $9.77 per Mcf in the same period of 2008.

Crude oil revenues increased by $15.0 million, or 173%, from $8.7 million in the six months ended June 30, 2007 to $23.7 million in the same period of 2008. Of the $15.0 million increase, $11.5 million was the result of higher realized prices for crude oil and $3.5 million was the result of increased crude oil production. Our average realized price received for crude oil increased by $53.87 per Bbl, or 95%, from $56.77 per Bbl in the six months ended June 30, 2007 to $110.64 per Bbl in the same period of 2008.

NGL revenues increased by $6.2 million, or 288%, from $2.2 million in the six months ended June 30, 2007 to $8.4 million in the same period of 2008. Of the $6.2 million increase, $3.7 million was the result of higher realized prices for NGLs and $2.5 million was the result of increased NGL production. Our average realized price received for NGLs increased by $26.42 per Bbl, or 82%, from $32.36 per Bbl in the six months ended June 30, 2007 to $58.78 per Bbl in the same period of 2008.

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.

In 2007, we reclassified the remaining amounts in accumulated other comprehensive income in earnings. As a result, in the six months ended June 30, 2008, no derivatives gains or losses were reported as part of natural gas, crude oil and NGL revenues.

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The following table shows a summary of the effects of derivative activities on revenues and realized prices for the six months ended June 30, 2008 and 2007:

	Six Months Ended June 30,
	2008			2007			2008			2007
	(in thousands)						(per Mcf)
Natural gas revenues, as reported	$	193,725		$	128,651		$	9.77		$	7.37
Derivatives (gains) included in natural gas revenues		—			(482	)		—			(0.03	)
Natural gas revenues before impact of derivatives		193,725			128,169			9.77			7.34
Cash settlements on natural gas derivatives		(7,447	)		5,873			(0.38	)		0.34
Natural gas revenues, adjusted for derivatives	$	186,278		$	134,042		$	9.39		$	7.68
	(in thousands)						(per Bbl)
Crude oil revenues, as reported	$	23,678		$	8,686		$	110.64		$	56.77
Derivatives losses included in crude oil revenues		—			256			—			1.67
Crude oil revenues before impact of derivatives		23,678			8,942			110.64			58.44
Cash settlements on crude oil derivatives		(313	)		87			(1.46	)		0.57
Crude oil revenues, adjusted for derivatives	$	23,365		$	9,029		$	109.18		$	59.01
	(in thousands)						(per Bbl)
NGL revenues, as reported	$	8,406		$	2,168		$	58.78		$	32.36
Derivatives (gains) losses included in NGL revenues		—			—			—			—
NGL revenues before impact of derivatives		8,406			2,168			58.78			32.36
Cash settlements on NGL derivatives		—			—			—			—
NGL revenues, adjusted for derivatives	$	8,406		$	2,168		$	58.78		$	32.36

Expenses. Aggregate operating costs and expenses increased by $38.7 million, or 47%, from $81.9 million in the six months ended June 30, 2007 to $120.6 million in the same period of 2008 primarily due to increases in operating expenses, taxes other than income, general and administrative expenses, exploration expenses and DD&A.

Operating expenses increased by $9.4 million, or 49%, from $18.9 million, or $1.01 per Mcfe, in the six months ended June 30, 2007 to $28.3 million, or $1.29 per Mcfe, in the same period of 2008. This increase is due primarily to increased compressor rentals, water disposal costs and repairs and maintenance expenses related to expansion in the East Texas, Gulf Coast and the Mid-Continent regions.

Taxes other than income increased by $4.0 million, or 46%, from $8.9 million in the six months ended June 30, 2007 to $12.9 million in the same period of 2008 primarily due to an increase in severance taxes related to higher commodity prices and increased production and an increase in property taxes.

General and administrative expenses increased by $2.8 million, or 41%, from $6.9 million in the six months ended June 30, 2007 to $9.7 million in the same period of 2008 primarily due to increased staffing costs in the East Texas and Mid-Continent regions.

Exploration expenses in the six months ended June 30, 2008 and 2007 consisted of the following:

	Six Months Ended June 30,
	2008		2007
	(in thousands)
Dry hole costs	$	2,831	$	3,727
Geological and geophysical		1,029		1,582
Unproved leasehold		6,640		4,737
Other		919		691
Total	$	11,419	$	10,737

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Exploration expenses increased by $0.7 million, or 6%, from $10.7 million, in the six months ended June 30, 2007 to $11.4 million in the same period of 2008 primarily due to an increase in unproved leasehold expense, partially offset by a decrease in dry hole costs and geological and geophysical expenses. The increase in unproved leasehold expense is due to leaseholds in the Appalachia, Gulf Coast and East Texas regions that were abandoned in the six months ended June 30, 2008 due to the lack of future production potential. Dry hole costs decreased primarily due to the write-off of two exploratory wells in the six months ended June 30, 2008 compared to three wells in the same period of 2007. The decrease in geological and geophysical expenses is due to the timing of seismic core drilling for horizontal coalbed methane.

DD&A expenses increased by $21.7 million, or 60%, from $36.5 million in the six months ended June 30, 2007 to $58.2 million in the same period of 2008 primarily due to the 17% increase in equivalent production and higher depletion rates. Our average depletion rate increased by $0.71 per Mcfe, or 37%, from $1.94 per Mcfe in the six months ended June 30, 2007 to $2.65 per Mcfe in the same period of 2008 due to higher drilling costs and acquisitions.

PVR Coal and Natural Resource Management Segment

Three Months Ended June 30, 2008 Compared With the Three Months Ended June 30, 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 June 30, 2008 and 2007:

	Three Months Ended June 30,						% Change
	2008			2007
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	31,641		$	24,029		32	%
Coal services		1,841			2,092		(12	)%
Timber		1,833			238		670	%
Oil and gas royalty		1,556			306		408	%
Other		2,185			1,745		25	%
Total revenues		39,056			28,410		37	%
Expenses
Coal royalties expense		3,397			1,820		87	%
Other operating		505			694		(27	)%
Taxes other than income		371			267		39	%
General and administrative		3,274			2,743		19	%
Depreciation, depletion and amortization		7,526			5,320		41	%
Total expenses		15,073			10,844		39	%
Operating income	$	23,983		$	17,566		37	%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,839			8,060		10	%
Average royalties revenues per ton ( $/ton)	$	3.58		$	2.98		20	%
Less royalties expense per ton ($/ton)		(0.38	)		(0.23	)	65	%
Average net coal royalties per ton ($/ton)	$	3.20		$	2.75		16	%

Revenues. Coal royalties revenues increased by $7.6 million, or 32%, from $24.0 million in the three months ended June 30, 2007 to $31.6 million in the same period of 2008. Coal royalties expense increased by $1.6 million, or 87%, from $1.8 million in the three months ended June 30, 2007 to $3.4 million in the same period of 2008 due

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primarily to the timing of longwall mining in Central Appalachia. Tons produced by PVR’s lessees increased by 0.7 million tons, or 10%, from 8.1 million tons in the three months ended June 30, 2007 to 8.8 million tons in the same period of 2008, which was due primarily to increases in production in the Illinois Basin. The increase in this region was due primarily to the June 2007 acquisition of lease rights to coal reserves in western Kentucky, where PVR first recorded production in August 2007.

PVR’s average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, increased by $0.45 per ton, or 16%, from $2.75 per ton in the three months ended June 30, 2007 to $3.20 per ton in the same period of 2008. The increase in the average net coal royalty per ton was due primarily to the increase in average royalty revenues per ton received in Central Appalachia, partially offset by lower royalty revenues per ton received from the aforementioned Illinois Basin acquisition. The increase in average royalty revenues per ton received in Central Appalachia was due primarily to higher coal prices for the region. The decrease in the Illinois Basin was due primarily to a lower royalty rate per ton on the newly acquired lease rights.

The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the three months ended June 30, 2008 and 2007:

	Coal Production		Coal Royalties Revenues						Coal Royalties Per Ton
	Three Months Ended June 30,		Three Months Ended June 30,						Three Months Ended June 30,
Property	2008	2007	2008			2007			2008			2007
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	5,144	5,018	$	24,450		$	18,274		$	4.75		$	3.64
Northern Appalachia	1,110	1,080		1,857			1,654			1.67			1.53
Illinois Basin	1,119	501		2,312			1,180			2.07			2.36
San Juan Basin	1,466	1,461		3,022			2,921			2.06			2.00
Total	8,839	8,060	$	31,641		$	24,029		$	3.58		$	2.98
Less coal royalties expense (1)				(3,397	)		(1,820	)		(0.38	)		(0.23	)
Net coal royalties revenues			$	28,244		$	22,209		$	3.20		$	2.75

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

Coal services revenues decreased by $0.3 million, or 12%, from $2.1 million in the three months ended June 30, 2007 to $1.8 million in the same period of 2008. This decrease is due primarily to the exhaustion of a fee related to a plant in West Virginia. Timber revenues increased by $1.6 million, or 670%, from $0.2 million in the three months ended June 30, 2007 to $1.8 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 $1.3 million, or 408%, from $0.3 million in the three months ended June 30, 2007 to $1.6 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 $0.5 million, or 25%, from $1.7 million in the three months ended June 30, 2007 to $2.2 million in the same period of 2008 primarily due to increased wheelage income in the Central Appalachian region related to an increase in sales prices.

Expenses. Other operating expenses decreased by $0.2 million, or 27%, from $0.7 million in the three months ended June 30, 2007 to $0.5 million in the same period of 2008 primarily due to the timing of core drilling activities. Taxes other than income increased by $0.1 million, or 39%, from $0.3 million in the three months ended June 30, 2007 to $0.4 million in the same period of 2008 primarily due to an increase in severance taxes paid on sales related to PVR’s timber leases. General and administrative expenses increased by $0.6 million, or 19%, from $2.7 million in the three months ended June 30, 2007 to $3.3 million in the same period of 2008 primarily due to increased staffing costs. DD&A expenses increased by $2.2 million, or 41%, from $5.3 million in the three months ended June 30, 2007 to $7.5 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.

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Six Months Ended June 30, 2008 Compared With the Six Months Ended June 30, 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 six months ended June 30, 2008 and 2007:

	Six Months Ended June 30,						% Change
	2008			2007
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	55,603		$	49,029		13	%
Coal services		3,703			3,693		0	%
Timber		3,417			417		719	%
Oil and gas royalty		2,790			583		379	%
Other		3,837			3,172		21	%
Total revenues		69,350			56,894		22	%
Expenses
Coal royalties expense		5,909			3,603		64	%
Other operating		736			1,066		(31	)%
Taxes other than income		742			590		26	%
General and administrative		6,459			5,359		21	%
Depreciation, depletion and amortization		13,939			10,810		29	%
Total expenses		27,785			21,428		30	%
Operating income	$	41,565		$	35,466		17	%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		16,479			16,344		1	%
Average royalties revenues per ton ($/ton)	$	3.37		$	3.00		12	%
Less royalties expense per ton ($/ton)		(0.36	)		(0.22	)	64	%
Average net coal royalties per ton ($/ton)	$	3.01		$	2.78		8	%

Revenues. Coal royalties revenues increased by $6.6 million, or 13%, from $49.0 million in the six months ended June 30, 2007 to $55.6 million in the same period of 2008. Coal royalties expense increased by $2.3 million, or 64%, from $3.6 million in the six months ended June 30, 2007 to $5.9 million in the same period of 2008 due primarily to the timing of longwall mining in Central Appalachia. Total tons produced by PVR’s lessees remained relatively constant from the six months ended June 30, 2007 to the same period in 2008, due primarily to increased production in the Illinois Basin that was mostly offset by decreased production in Northern Appalachia. The increased production in the Illinois Basin was primarily due to the June 2007 acquisition of lease rights to coal reserves in western Kentucky, where PVR first recorded production in August 2007. The decreased production in Northern Appalachia was due to adverse conditions related to longwall production.

PVR’s average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, increased by $0.23 per ton, or 8%, from $2.78 per ton in the six months ended June 30, 2007 to $3.01 per ton in the same period of 2008. The increase in the average net coal royalty per ton was due primarily to an increase in average royalty revenues per ton received in Central Appalachia, partially offset by lower royalty revenues per ton received form the aforementioned Illinois Basin acquisition. The increase in average royalty revenues per ton received in Central Appalachia was due primarily to higher coal prices for the region. The decrease in the Illinois Basin was due primarily to a lower royalty rate per ton on the newly acquired lease rights.

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The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the six months ended June 30, 2008 and 2007:

	Coal Production		Coal Royalties Revenues						Coal Royalties Per Ton
	Six Months Ended June 30,		Six Months Ended June 30,						Six Months Ended June 30,
Property	2008	2007	2008			2007			2008			2007
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	9,955	9,975	$	43,029		$	37,184		$	4.32		$	3.73
Northern Appalachia	1,784	2,450		2,991			3,757			1.68			1.53
Illinois Basin	2,152	1,120		4,250			2,487			1.97			2.22
San Juan Basin	2,588	2,799		5,333			5,601			2.06			2.00
Total	16,479	16,344	$	55,603		$	49,029		$	3.37		$	3.00
Less coal royalties expense (1)				(5,909	)		(3,603	)		(0.36	)		(0.22	)
Net coal royalties revenues			$	49,694		$	45,426		$	3.01		$	2.78

(1) Our coal royalties expense is incurred primarily in the Central Appalachian region.

Coal services revenues remained relatively constant from the six months ended June 30, 2007 to the same period of 2008. Timber revenues increased by $3.0 million, or 719%, from $0.4 million in the six months ended June 30, 2007 to $3.4 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 $2.2 million, or 379%, from $0.6 million in the six months ended June 30, 2007 to $2.8 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 $0.6 million, or 21%, from $3.2 million in the six months ended June 30, 2007 to $3.8 million in the same period of 2008 primarily due to increased wheelage income in the Central Appalachian region related to an increase in sales prices.

Expenses. Other operating expenses decreased by $0.4 million, or 31%, from $1.1 million in the six months ended June 30, 2007 to $0.7 million in the same period of 2008 primarily due to the timing of core drilling activities. Taxes other than income increased by $0.1 million, or 26%, from $0.6 million in the six months ended June 30, 2007 to $0.7 million in the same period of 2008 primarily due to an increase in severance taxes paid on sales related to PVR’s timber leases. General and administrative expenses increased by $1.1 million, or 21%, from $5.4 million in the six months ended June 30, 2007 to $6.5 million in the same period of 2008 primarily due to increased staffing costs. DD&A expenses increased by $3.1 million, or 29%, from $10.8 million in the six months ended June 30, 2007 to $13.9 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.

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PVR Natural Gas Midstream Segment

Three Months Ended June 30, 2008 Compared With the Three Months Ended June 30, 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 June 30, 2008 and 2007:

	Three Months Ended June 30,						% Change
	2008			2007
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	153,537		$	69,384		121	%
Natural gas liquids		70,507			41,162		71	%
Condensate		8,452			3,157		168	%
Gathering and transportation fees		2,301			704		227	%
Total natural gas midstream revenues (1)		234,797			114,407		105	%
Equity earnings in equity investment		556			—		—
Producer services		2,096			1,327		58	%
Total revenues		237,449			115,734		105	%
Expenses
Cost of midstream gas purchased (1)		202,819			95,077		113	%
Operating		4,817			2,983		61	%
Taxes other than income		605			336		80	%
General and administrative		3,469			3,020		15	%
Depreciation and amortization		5,393			4,502		20	%
Total operating expenses		217,103			105,918		105	%
Operating income	$	20,346		$	9,816		107	%
Operating Statistics
System throughput volumes (MMcf)		23,884			17,019		40	%
System throughput volumes (MMcf/day)		262			187		40	%
Gross margin	$	31,978		$	19,330		65	%
Impact of derivatives		(8,186	)		(904	)	806	%
Gross margin, adjusted for impact of derivatives	$	23,792		$	18,426		29	%
Gross margin ($/Mcf)	$	1.34		$	1.14		18	%
Impact of derivatives ($/Mcf)		(0.34	)		(0.05	)	580	%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	1.00		$	1.09		(8	)%

(1) In the three months ended June 30, 2008, PVR recorded $49.8 million of natural gas midstream revenue and $49.8 million for the cost of midstream gas purchased related to the purchase of natural gas from Penn Virginia Oil & Gas, L.P. (“PVOG”) and the subsequent sale of that gas to third parties. These transactions do not impact the gross margin.

Gross Margin. PVR’s gross 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 $120.4 million, or 105%, from $114.4 million in the three months ended June 30, 2007 to $234.8 million in the same period of 2008. Cost of midstream gas purchased increased by $107.7 million, or 113%, from $95.1 million in the three months ended June 30, 2007 to $202.8 million in the same period of 2008. PVR’s gross margin increased by $12.7 million, or 65%, from $19.3 million in the three months

41

ended June 30, 2007 to $32.0 million in the same period of 2008. The gross margin increase was a result of increased commodity pricing, increased system throughput volumes and higher fractionation, or “frac” spreads during the three months ended June 30, 2008 compared to the same period of 2007. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis.

System throughput volumes increased by 75 MMcfd, or 40%, from 187 MMcfd in the three months ended June 30, 2007 to 262 MMcfd in the same period of 2008. This increase in throughput volumes is due primarily to the Crossroads plant in East Texas, which became fully operational in the second quarter of 2008. Also, 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 contributed to the increase in throughput volume.

In the second quarter of 2008, two expansion projects related to PVR’s natural gas processing facilities were operational. These two natural gas processing facilities included the Spearman plant in the Texas Panhandle, which was placed into service in February 2008 and has approximately 60 MMcfd capacity, and the Crossroads plant in East Texas, which was placed in service in April 2008 and has approximately 80 MMcfd capacity. The Crossroads plant will process most of the Cotton Valley gas production for PVOG, and the Spearman plant will process gas that had previously bypassed the Beaver plant.

During the three months ended June 30, 2008, PVR generated a majority of its gross margin from contractual arrangements under which PVR’s margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of PVR’s risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. Adjusted for the impact of derivative financial instruments, PVR’s gross margin increased by $5.4 million, or 29%, from $18.4 million for the three months ended June 30, 2007 to $23.8 million for the same period of 2008. On a per Mcf basis, the gross margin adjusted for the impact of derivatives decreased by $0.09, or 8%, from $1.09 per Mcf in the three months ended June 30, 2007 to $1.00 per Mcf in the same period of 2008. The decrease in gross margin on a per Mcf basis was due to an increase in fee-based volumes associated with the Crossroads plant.

Producer Services. Producer services revenues increased by $0.8 million, or 58%, from $1.3 million in the three months ended June 30, 2007 to $2.1 million in the same period of 2008 primarily due to an increase in collected agent fees for the marketing of Penn Virginia’s and other third parties’ natural gas production.

Equity Earnings in Equity Investment. This increase is due to PVR’s 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. PVR acquired this member interest in the second quarter of 2008.

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 $1.8 million, or 61%, from $3.0 million in the three months ended June 30, 2007 to $4.8 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 and Crossroads plants. Taxes other than income increased by $0.3 million, or 80%, from $0.3 million in the three months ended June 30, 2007 to $0.6 million in the same period of 2008 primarily due to increased property taxes resulting from the construction of the Spearman and Crossroads plants. General and administrative expenses increased by $0.5 million, or 15%, from $3.0 million in the three months ended June 30, 2007 to $3.5 million in the same period of 2008 primarily due to increased staffing costs. Depreciation and amortization expenses increased by $0.9 million, or 20%, from $4.5 million in the three months ended June 30, 2007 to $5.4 million in the same period of 2008. This increase is primarily due to expansion capital incurred, which includes the Spearman and Crossroads plants.

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Six Months Ended June 30, 2008 Compared With the Six Months Ended June 30, 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 six months ended June 30, 2008 and 2007:

	Six Months Ended June 30,
	2008			2007			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	215,204		$	129,064		67	%
Natural gas liquids		126,704			73,150		73	%
Condensate		14,668			6,073		142	%
Gathering and transportation fees		3,269			1,438		127	%
Total natural gas midstream revenues (1)		359,845			209,725		72	%
Equity earnings in equity investment		556			—		—
Producer services		3,568			1,725		107	%
Total revenues		363,969			211,450		72	%
Expenses
Cost of midstream gas purchased (1)		302,516			174,808		73	%
Operating		8,867			6,342		40	%
Taxes other than income		1,306			856		53	%
General and administrative		6,802			6,043		13	%
Depreciation and amortization		10,480			9,145		15	%
Total operating expenses		329,971			197,194		67	%
Operating income	$	33,998		$	14,256		138	%
Operating Statistics
System throughput volumes (MMcf)		41,171			32,919		25	%
System throughput volumes (MMcf/day)		226			182		24	%
Gross margin	$	57,329		$	34,917		64	%
Impact of derivatives		(16,600	)		(2,133	)	678	%
Gross margin, adjusted for impact of derivatives	$	40,729		$	32,784		24	%
Gross margin ($/Mcf)	$	1.39		$	1.06		31	%
Impact of derivatives ($/Mcf)		(0.40	)		(0.07	)	471	%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.99		$	0.99		—

(1) In the six months ended June 30, 2008, PVR recorded $49.8 million of natural gas midstream revenue and $49.8 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG and the subsequent sale of that gas to third parties. These transactions do not impact the gross margin.

Gross Margin. Natural gas midstream revenues increased by $150.1 million, or 72%, from $209.7 million in the six months ended June 30, 2007 to $359.8 million in the same period of 2008. Cost of midstream gas purchased increased by $127.7 million, or 73%, from $174.8 million in the six months ended June 30, 2007 to $302.5 million in the same period of 2008. PVR’s gross margin increased by $22.4 million, or 64%, from $34.9 million in the six months ended June 30, 2007 to $57.3 million in the same period of 2008. The gross margin increase was a result of increased commodity pricing, increased system throughput volumes and higher fractionation, or “frac” spreads during the six months ended June 30, 2008 compared to the same period of 2007. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis.

System throughput volumes increased by 44 MMcfd, or 24%, from 182 MMcfd in the six months ended June 30, 2007 to 226 MMcfd in the same period of 2008. This increase in throughput volumes is due primarily to the Crossroads plant in East Texas, which became fully operational in the second quarter of 2008. Also, 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 contributed to the increase in throughput volume.

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In the second quarter of 2008, two expansion projects related to PVR’s natural gas processing facilities were operational. These two natural gas processing facilities included the Spearman plant in the Texas Panhandle, which was placed into service in February 2008 and has approximately 60 MMcfd capacity and the Crossroads plant in East Texas, which was placed in service in April 2008 and has approximately 80 MMcfd capacity. The Crossroads plant will process most of the Cotton Valley gas production for PVOG, and the Spearman plant will process gas that had previously bypassed the Beaver plant.

During the six months ended June 30, 2008, PVR generated a majority of its gross margin from contractual arrangements under which its gross margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. Adjusted for the impact of derivative financial instruments, PVR’s gross margin increased by $7.9 million, or 24%, from $32.8 million for the six months ended June 30, 2007 to $40.7 million for the same period of 2008. On a per Mcf basis, the gross margin adjusted for the impact of derivatives remained relatively constant in the six months ended June 30, 2007 to the same period of 2008.

Producer Services. Producer services revenues increased by $1.9 million, or 107%, from $1.7 million in the six months ended June 30, 2007 to $3.6 million in the same period of 2008 primarily due to an increase in collected agent fees for the marketing of Penn Virginia’s and other third parties’ natural gas production.

Equity Earnings in Equity Investment. This increase is due to PVR’s 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. PVR acquired this member interest in the second quarter of 2008.

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 $2.6 million, or 40%, from $6.3 million in the six months ended June 30, 2007 to $8.9 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 and Crossroads plants. Taxes other than income increased by $0.4 million, or 53%, from $0.9 million in the six months ended June 30, 2007 to $1.3 million in the same period of 2008 primarily due to increased property taxes resulting from the construction of the Spearman and Crossroads plants. General and administrative expenses increased by $0.8 million, or 13%, from $6.0 million in the six months ended June 30, 2007 to $6.8 million in the same period of 2008 primarily due to increased staffing costs. Depreciation and amortization expenses increased by $1.4 million, or 15%, from $9.1 million in the six months ended June 30, 2007 to $10.5 million in the same period of 2008. This increase is primarily due to expansion capital incurred, which includes the Spearman and Crossroads plants.

Eliminations and Other

Our corporate and other results consist of elimination of intercompany sales, corporate operating expenses, interest expense, derivative expenses and minority interest.

Corporate Operating Expenses. Corporate operating expenses primarily consist of general and administrative expenses other than from our oil and gas segment, the PVR coal and natural resource management and the PVR natural gas midstream segments. Corporate operating expenses increased by $2.9 million, or 48%, from $6.1 million in the three months ended June 30, 2007 to $9.0 million in the same period of 2008. Corporate operating expenses increased by $4.0 million, or 32%, from $12.5 million in the six months ended June 30, 2007 to $16.5 million in the same period of 2008. These increases are primarily due to increased general and administrative expenses resulting from wage increases, increased consulting expenses and the recognition of additional stock-based compensation expenses.

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Interest Expense. Our consolidated interest expense is comprised of the following:

	Three Months Ended								Six Months Ended
	June 30,						% Change		June 30,						% Change
Source	2008			2007					2008			2007
	(in thousands)								(in thousands)
PVA borrowings	$	(4,916	)	$	(5,629	)	(13	)%	$	(10,066	)	$	(9,790	)	3	%
PVA capitalized interest		509			938		(46	)%		1,063			1,917		(45	)%
PVA interest rate swaps		(329	)		—		—			(353	)		2		(17750	)%
PVR borrowings		(4,935	)		(3,790	)	30	%		(10,622	)		(7,508	)	41	%
PVR capitalized interest		187			—		—			675			—		—
PVR interest rate swaps		(626	)		173		(462	)%		(359	)		344		(204	)%
Total interest expense	$	(10,110	)	$	(8,308	)	22	%	$	(19,662	)	$	(15,035	)	31	%

Our interest expense related to borrowings decreased by $0.7 million, or 13%, from $5.6 million in the three months ended June 30, 2007 to $4.9 million in the same period of 2008. This decrease is due primarily to a decrease in the effective interest rate on our borrowings in the three months ended June 30, 2008 compared to the same period of 2007. Our oil and gas segment also capitalized $0.5 million and $0.9 million of interest in the three months ended June 30, 2008 and 2007. Both the borrowings and the capitalized interest for both periods were related to the preparation of unproved oil and gas properties for their development. In connection with periodic settlements, we recognized $0.3 million in net hedging losses on the Revolver Swaps in interest expense for the three months ended June 30, 2008.

Our interest expense related to borrowings remained relatively constant from the six months ended June 30, 2007 to the same period of 2008. Our oil and gas segment capitalized $1.1 million and $1.9 million of interest in the six months ended June 30, 2008 and 2007. Both the borrowings and the capitalized interest for both periods were related to the preparation of unproved oil and gas properties for their development. In connection with periodic settlements, we recognized $0.4 million in net hedging losses on the Revolver Swaps in interest expense for the six months ended June 30, 2008.

PVR’s interest expense related to its borrowings increased by $1.1 million, or 30%, from $3.8 million in the three months ended June 30, 2007 to $4.9 million in the same period of 2008. This increase is primarily due to the increase in PVR’s average debt balance, which increased from $241.6 million for the three months ended June 30, 2007 to $411.8 million for the same period of 2008. The increase in PVR’s average debt balance is due primarily to acquisitions and expansion activity. PVR also capitalized $0.2 million of interest costs in the three months ended June 30, 2008 related to the construction of the Spearman and Crossroads plants. PVR had no capitalized interest in the three months ended June 30, 2007. In connection with periodic settlements, PVR recognized $0.6 million in net hedging losses on the PVR Revolver swaps, in interest expense for the three months ended June 30, 2008.

PVR’s interest expense increased by $3.1 million, or 41%, from $7.5 million in the six months ended June 30, 2007 to $10.6 million in the same period of 2008. This increase is primarily due to the increase in PVR’s average debt balance, which increased from $232.9 million for the six months ended June 30, 2007 to $411.9 million for the same period of 2008. The increase in PVR’s average debt balance is due primarily to acquisitions and expansion activity. PVR also capitalized $0.7 million of interest costs in the six months ended June 30, 2008 related to the construction of the Spearman and Crossroads plants. PVR had no capitalized interest in the six months ended June 30, 2007. In connection with periodic settlements, we recognized $0.4 million in net hedging losses on the PVR Revolver swaps, in interest expense for the six months ended June 30, 2008.

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

Commodity prices increased substantially in the second quarter of 2008 resulting in consolidated derivative expenses of $103.6 million for changes in fair value. Cash paid for settlements totaled $18.0 million for the three months ended June 30, 2008. Derivative expenses in the three months ended June 30, 2007 consisted of $0.9 million for changes in fair value. Cash paid for settlements totaled $1.8 million in the three months ended June 30, 2007.

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Primarily due to the increase in commodity prices in the six months ended June 30, 2008, consolidated derivative expenses were $129.5 million for changes in fair value. Cash paid for settlements totaled $27.0 million in the six months ended June 30, 2008. The derivative expenses in the six months ended June 30, 2007 consisted of $17.6 million for changes in fair value. Cash received for settlements totaled $1.7 million for the six months ended June 30, 2007.

Our consolidated derivative activity is summarized below:

	Three Months Ended								Six Months Ended
	June 30,						% Change		June 30,						% Change
	2008			2007					2008			2007
	(in thousands)								(in thousands)
Oil and gas segment unrealized derivative gain (loss)	$	(65,347	)	$	6,286		(1140	)%	$	(99,593	)	$	(13,372	)	645	%
Oil and gas segment realized gain (loss)		(8,329	)		372		(2339	)%		(7,760	)		5,956		(230	)%
PVR midstream segment unrealized derivative loss		(20,239	)		(5,361	)	278	%		(2,941	)		(5,936	)	(50	)%
PVR midstream segment realized loss		(9,703	)		(2,189	)	343	%		(19,225	)		(4,261	)	351	%
Total derivative losses	$	(103,618	)	$	(892	)	11516	%	$	(129,519	)	$	(17,613	)	635	%

Minority Interest. Minority interest primarily represents PVR’s net income allocated to the limited partner units owned by the public. In the three months ended June 30, 2007 and 2008, minority interest reduced our consolidated income from operations by $9.2 million and $3.9 million. In the six months ended June 30, 2007 and 2008, minority interest reduced our consolidated income from operations by $18.5 million and $24.0 million. The decrease in minority interest for the three months ended June 30, 2008 compared to the same period in 2007 was primarily due the decrease in PVR’s net income from $16.6 million to $9.5 million. The increase in minority interest for the six months ended June 30, 2008 and 2007 was primarily due to the increase in PVR’s net income from $33.0 million to $44.0 million.

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.

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

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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.

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.

Depletion

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.

PVR depletes coal properties on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by PVR’s own geologists and outside consultants. PVR’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. PVR depletes timber on an area-by-area basis at a rate based upon the quantity of timber sold.

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Derivative Activities

Until 2006, we used hedge accounting for commodity derivative financial instruments as allowed under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. 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 June 30, 2008, PVR had $1.9 million of losses remaining in accumulated other comprehensive income, net of related income taxes of $1.0 million. 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 fluctuations 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.

Equity Investments

PVR uses the equity method of accounting to account for its 25% member interest in Thunder Creek, as well as its investment in a coal handling joint venture, recording the initial investment at cost. Subsequently, the carrying amount of the investment is increased to reflect its share of income of the investee and is reduced to reflect its share of losses of the investee or distributions received from the investee as the joint ventures reports them. PVR’s share of earnings or losses from Thunder Creek and from the coal handling joint venture is included in other revenues on our consolidated statements of income. Other revenues also include amortization of the amount of the equity investments that exceed our portion of the underlying equity in net assets. PVR records amortization over the life of the contracts acquired in the Thunder Creek acquisition and the life of the coal services contracts acquired in acquisition of the aforementioned coal handling joint venture.

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 June 30, 2008, the costs attributable to unproved properties were $135.9 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.

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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. FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157, delays the application of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities to fiscal years and interim 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).

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 8 – Derivative Instruments in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements.”

• Interest rate swaps: We have entered into the Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the 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 8 – Derivative Instruments in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements.”

Gain on Sale of Subsidiary Units

We account for PVR equity issuances as sales of minority interest. For each PVR equity issuance, we have calculated a gain under SEC Staff Accounting Bulletin No. 51 (or Topic 5-H), Accounting for Sales of Stock by a Subsidiary (“SAB 51”). SAB 51 provides guidance on accounting for the effect of issuances of a subsidiary’s stock on the parent’s investment in that subsidiary. In some situations, SAB 51 allows registrants to elect an accounting policy of recording gains or losses on issuances of stock by a subsidiary either in income or as a capital transaction. Accordingly, we adopted a policy of recording SAB 51 gains and losses directly to partners’ capital.

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

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

PVR’s operations and those of its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of PVR’s coal property leases impose liability on the relevant lessees for all environmental and reclamation liabilities arising under those laws and regulations 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 June 30, 2008 and December 31, 2007, PVR’s environmental liabilities included $1.3 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.

Recent Accounting Pronouncements

See Note 3 – Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements” for a description of recent accounting pronouncements.

Forward-Looking Statements

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

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

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

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

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

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

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

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

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

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• 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;

• 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.

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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 six months ended June 30, 2008, we reported consolidated net derivative expenses of $129.5 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 June 30, 2008, PVR had $1.9 million of net losses remaining in accumulated other comprehensive income, net of related income taxes of $1.0 million. 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 fluctuations 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 June 30, 2008 (in thousands):

		Weighted Average Price
	Average Volume Per Day	Additional Put Option		Floor		Ceiling		Estimated Fair Value
Natural Gas Costless Collars	(in MMBtus)	(per MMBtu)
Third Quarter 2008	10,000			$	7.50	$	9.10	$	(5,827	)
Fourth Quarter 2008 (1)	10,000			$	7.50	$	9.10		(971	)
Natural Gas Three-way Collars	(in MMBtus)	(per MMBtu)
Third Quarter 2008	22,500	$	5.00	$	7.11	$	9.09		(14,193	)
Fourth Quarter 2008	67,500	$	5.89	$	8.55	$	11.26		(17,670	)
First Quarter 2009	65,000	$	6.00	$	8.67	$	11.68		(17,541	)
Second Quarter 2009	40,000	$	6.38	$	8.75	$	10.79		(6,344	)
Third Quarter 2009	40,000	$	6.38	$	8.75	$	10.79		(6,733	)
Fourth Quarter 2009	30,000	$	6.83	$	9.50	$	13.60		(2,748	)
First Quarter 2010	30,000	$	6.83	$	9.50	$	13.60		(3,460	)
Natural Gas Swaps
Third Quarter 2008	45,000			$	9.03				(17,576	)
Natural Gas Basis Swaps	(in MMBtus)	(per MMBtu)
Third Quarter 2008	15,000			$	0.39				(87	)
Fourth Quarter 2008	15,000			$	0.39				(72	)
Crude Oil Three-Way Collars	(Bbl)	(Bbl)
Third Quarter 2008	500	$	70.00	$	95.00	$	108.80		(1,476	)
Fourth Quarter 2008	500	$	80.00	$	110.00	$	179.00		(59	)
First Quarter 2009	500	$	80.00	$	110.00	$	179.00		(116	)
Second Quarter 2009	500	$	80.00	$	110.00	$	179.00		(144	)
Third Quarter 2009	500	$	80.00	$	110.00	$	179.00		(170	)
Fourth Quarter 2009	500	$	80.00	$	110.00	$	179.00		(183	)
Settlements to be paid in subsequent period									(378	)
Oil and gas segment commodity derivatives – net liability								$	(95,748	)

(1) This position expires in October 2008.

Our management estimates that excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in natural gas prices, operating income from oil and gas operations for the last six months of 2008 would increase or decrease by approximately $23.0 million. This assumes that crude oil and NGL prices and natural gas production remain constant at forecasted levels. In addition, our management also estimates that for every $5.00 per barrel increase or decrease in crude oil prices, operating income from oil and gas operations would increase or decrease by approximately $2.6 million. This assumes that crude oil and NGL production and natural gas prices remain constant at forecasted levels. These estimated changes in operating income exclude the effect of potential cash receipts or payments in settling these derivative positions.

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PVR Natural Gas Midstream Segment

The following table lists PVR’s derivative agreements and their fair values as of June 30, 2008 (in thousands):

						Weighted Average Price Collars
	Average Volume Per Day		Weighted Average Price			Additional Put Option		Put			Call		Estimated Fair Value
Frac Spread	(in MMBtu	)		(per MMBtu	)
Third Quarter 2008 through Fourth Quarter 2008	7,824		$	5.02									$	(5,944	)
Ethane Sale Swap	(in gallons	)		(per gallon	)
Third Quarter 2008 through Fourth Quarter 2008	34,440		$	0.4700										(4,774	)
Propane Sale Swaps	(in gallons	)		(per gallon	)
Third Quarter 2008 through Fourth Quarter 2008	26,040		$	0.7175										(5,675	)
Crude Oil Sale Swaps	(in barrels	)		(per barrel	)
Third Quarter 2008 through Fourth Quarter 2008	560		$	49.27										(9,334	)
Natural Gasoline Collar	(in gallons	)							(per gallon	)
Third Quarter 2008 through Fourth Quarter 2008	6,300							$	1.4800		$	1.6465		(1,611	)
Crude Oil Collar	(in barrels	)							(per barrel	)
Third Quarter 2008 through Fourth Quarter 2008	400							$	65.00		$	75.25		(4,784	)
Natural Gas Sale Swaps	(in MMBtu	)		(per MMBtu	)
Third Quarter 2008 through Fourth Quarter 2008	4,000		$	6.97										4,795
Crude Oil Three-Way Collar	(in barrels	)							(per gallon	)
First Quarter 2009 through Fourth Quarter 2009	1,000					$	70.00	$	90.00		$	119.25		(10,292	)
Frac Spread Collar (1)	(in MMBtu	)							(in MMBtu	)
First Quarter 2009 through Fourth Quarter 2009	6,000							$	9.09		$	13.94		—
Settlements to be paid in subsequent period														(5,246	)
Natural gas midstream segment commodity derivatives – net liability													$	(42,865	)

(1) PVR entered into this contract in July 2008.

Our management estimates that excluding the derivative positions described above, for every $1.00 per MMBtu decrease or increase in natural gas prices, natural gas midstream gross margin and operating income for the last six months of 2008 would increase or decrease by approximately $5.6 million, assuming that crude oil and natural liquids prices and inlet volumes remain constant at forecasted levels. In addition, our management also estimates that for every $5.00 per barrel increase or decrease in the oil prices, natural gas midstream gross margin and operating income would increase or decrease by approximately $2.3 million, assuming that natural gas prices and inlet volumes remain constant at forecasted levels. These estimated changes in gross margin and operating income exclude the effect of potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of June 30, 2008, we had $205.0 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 June 30, 2008 would cost us approximately $1.6 million in additional interest expense.

54

As of June 30, 2008, PVR had $323.1 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 June 30, 2008 would cost PVR approximately $1.6 million in additional interest expense.

Item 4    Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of June 30, 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 June 30, 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 6    Exhibits

10.1	Units Purchase Agreement dated June 17, 2008 by and among Penn Virginia Resource LP Corp, Kanawha Rail Corp. and Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 10.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on July 22, 2008).
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.

56

SIGNATURES

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

		PENN VIRGINIA CORPORATION
Date:    August 7, 2008	By:	/s/ FRANK A. PICI
		Frank A. Pici
		Executive Vice President and Chief Financial Officer
Date:    August 7, 2008	By:	/s/ FORREST W. MCNAIR
		Forrest W. McNair
		Vice President and Controller

57

EX-12.1

Exhibit 12.1

Penn Virginia Corporation and Subsidiaries

Statement of Computation of Ratio of Earnings to Fixed Charges Calculation

(in thousands, except ratios)

											Six Months Ended June 30, 2008
	2003		2004		2005		2006		2007
Earnings
Pre-tax income (loss) *	$	55,987	$	72,779	$	130,918	$	167,080	$	106,818	$	18,738
Fixed charges		8,379		11,067		20,755		31,313		47,689		23,167
Total earnings	$	64,366	$	83,846	$	151,673	$	198,393	$	154,507	$	41,905
Fixed Charges
Interest expense	$	7,352	$	9,679	$	18,815	$	27,984	$	42,371	$	20,031
Rental interest factor		1,027		1,388		1,940		3,329		5,318		3,136
Total fixed charges	$	8,379	$	11,067	$	20,755	$	31,313	$	47,689	$	23,167
Ratio of earnings to fixed charges		7.7x		7.6x		7.3x		6.3x		3.2x		1.8x

* Excludes equity earnings from investees and includes capitalized interest.

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, A. James Dearlove, President and Chief Executive Officer of Penn Virginia Corporation (the “Registrant”), certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of the Registrant (this “Report”);

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

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

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

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

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

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

(d) Disclosed in this Report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors:

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

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

Date: August 7, 2008	/s/ A. JAMES DEARLOVE
	A. James Dearlove President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Frank A. Pici, Executive Vice President and Chief Financial Officer of Penn Virginia Corporation (the “Registrant”), certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of the Registrant (this “Report”);

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

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

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

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

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

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

(d) Disclosed in this Report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors:

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

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

Date: August 7, 2008	/s/ Frank A. PICI
	Frank A. Pici Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Penn Virginia Corporation (the “Company”) on Form 10-Q for the quarter ended June 30, 2008, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, A. James Dearlove, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 7, 2008	/s/ A. JAMES DEARLOVE
	A. James Dearlove President and Chief Executive Officer

This written statement is being furnished to the Securities and Exchange Commission as an exhibit to the Report. A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Penn Virginia Corporation (the “Company”) on Form 10-Q for the quarter ended June 30, 2008, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Frank A. Pici, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 7, 2008	/s/ FRANK A. PICI
	Frank A. Pici Executive Vice President and Chief Financial Officer

This written statement is being furnished to the Securities and Exchange Commission as an exhibit to the Report. A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.