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, 2007

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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨

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 1, 2007, 37,877,010 shares of common stock of the registrant were issued and outstanding.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

INDEX

		Page
PART I.	Financial Information
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three Months and Six Months Ended June 30, 2007 and 2006	1
	Consolidated Balance Sheets as of June 30, 2007 and December 31, 2006	2
	Consolidated Statements of Cash Flows for the Three Months and Six Months Ended June 30, 2007 and 2006	3
	Notes to Consolidated Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 4.	Controls and Procedures	45
PART II.	Other Information
Item 4.	Submission of Matters to a Vote of Security Holders	47
Item 6.	Exhibits	47

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,
	2007			2006			2007			2006
Revenues
Natural gas	$	72,032		$	49,634		$	128,651		$	109,844
Oil and condensate		5,750			5,623			10,854			10,414
Natural gas midstream		114,407			95,350			209,725			204,531
Coal royalties		24,029			24,254			49,029			46,676
Other		6,180			4,289			10,409			8,592
Total revenues		222,398			179,150			408,668			380,057
Expenses
Cost of midstream gas purchased		95,077			75,692			174,808			174,343
Operating		15,522			10,701			29,955			19,179
Exploration		5,667			5,510			10,737			13,401
Taxes other than income		5,463			3,930			10,839			8,895
General and administrative		15,049			11,714			30,100			22,389
Depreciation, depletion and amortization		28,546			21,664			56,616			43,245
Total expenses		165,324			129,211			313,055			281,452
Operating income		57,074			49,939			95,613			98,605
Other income (expense)
Interest expense		(8,308	)		(5,396	)		(15,035	)		(10,184	)
Other		544			363			1,960			759
Derivatives		(892	)		(6,379	)		(17,613	)		(6,537	)
Income before minority interest and income taxes		48,418			38,527			64,925			82,643
Minority interest		9,228			7,759			18,524			12,648
Income tax expense		15,312			12,551			18,120			27,670
Net income	$	23,878		$	18,217		$	28,281		$	42,325
Net income per share, basic	$	0.63		$	0.49		$	0.75		$	1.13
Net income per share, diluted	$	0.63		$	0.48		$	0.74		$	1.12
Weighted average shares outstanding, basic		37,750			37,354			37,682			37,336
Weighted average shares outstanding, diluted		38,055			37,826			37,962			37,794

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

1

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

	June 30, 2007			December 31, 2006
	(unaudited)
Assets
Current assets
Cash and cash equivalents	$	22,211		$	20,338
Accounts receivable		152,403			138,880
Derivative assets		9,374			18,244
Assets held for sale		16,044			—
Other		11,456			14,921
Total current assets		211,488			192,383
Property and equipment
Oil and gas properties (successful efforts method)		1,227,684			1,045,182
Other property and equipment		742,803			671,169
		1,970,487			1,716,351
Accumulated depreciation, depletion and amortization		(411,900	)		(357,968	)
Net property and equipment		1,558,587			1,358,383
Derivative assets		2,302			4,344
Other assets		77,514			78,039
Total assets	$	1,849,891		$	1,633,149
Liabilities and Shareholders’ Equity
Current liabilities
Current maturities of long-term debt	$	11,846		$	10,832
Accounts payable and accrued liabilities		150,209			154,709
Derivative liabilities		15,631			7,149
Other		6,662			—
Total current liabilities		184,348			172,690
Other liabilities		34,909			26,003
Derivative liabilities		6,232			7,065
Deferred income taxes		182,045			178,380
Long-term debt of the Company		328,500			221,000
Long-term debt of PVR		263,283			207,214
Minority interests of subsidiaries		192,402			438,372
Shareholders’ equity
Preferred stock of $100 par value – 100,000 shares authorized; none issued		—			—
Common stock of $0.01 par value – 62,000,000 shares authorized; 37,874,922 and 37,561,264 shares issued and outstanding at June 30, 2007, and December 31, 2006		190			188
Paid-in capital		350,717			100,559
Retained earnings		314,009			289,967
Deferred compensation obligation		1,299			1,314
Accumulated other comprehensive income		(6,300	)		(7,954	)
Treasury stock – 71,760 and 70,898 shares common stock, at cost, on June 30, 2007 and December 31, 2006, respectively		(1,743	)		(1,649	)
Total shareholders’ equity		658,172			382,425
Total liabilities and shareholders’ equity	$	1,849,891		$	1,633,149

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

2

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Cash flows from operating activities
Net income	$	23,878		$	18,217		$	28,281		$	42,325
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		28,546			21,664			56,616			43,245
Commodity derivative contracts:
Total derivative losses		2,374			6,454			19,516			7,633
Cash received (paid) in derivative settlements		(1,817	)		(2,888	)		1,695			(6,217	)
Deferred income taxes		10,719			9,941			12,684			18,823
Minority interest		9,228			7,759			18,524			12,648
Dry hole and unproved leasehold expense		4,330			3,984			8,716			8,359
Other		745			3,716			1,271			4,564
Changes in operating assets and liabilities		(10,147	)		15,358			(14,506	)		18,520
Net cash provided by operating activities		67,856			84,205			132,797			149,900
Cash flows from investing activities
Proceeds from the sale of property and equipment		196			1,247			243			2,475
Acquisitions, net of cash acquired		(72,389	)		(158,418	)		(76,224	)		(164,663	)
Additions to property and equipment		(94,531	)		(58,758	)		(199,302	)		(105,539	)
Net cash used in investing activities		(166,724	)		(215,929	)		(275,283	)		(267,727	)
Cash flows from financing activities
Dividends paid		(2,124	)		(2,103	)		(4,240	)		(4,197	)
Proceeds from borrowings of the Company		54,500			78,000			107,500			86,000
Repayments of borrowings of the Company		—			—			—			(20,000	)
Distributions paid to minority interest holders		(12,445	)		(9,173	)		(23,465	)		(18,317	)
Proceeds from issuance of partners’ capital by PVG		—			—			860			—
Proceeds from borrowings of PVR		52,000			64,800			62,000			64,800
Repayments of borrowings of PVR		—			—			(5,000	)		(3,300	)
Other		6,621			14			6,704			734
Net cash provided by financing activities		98,552			131,538			144,359			105,720
Net increase (decrease) in cash and cash equivalents		(316	)		(186	)		1,873			(12,107	)
Cash and cash equivalents – beginning of period		22,527			13,992			20,338			25,913
Cash and cash equivalents – end of period	$	22,211		$	13,806		$	22,211		$	13,806
Supplemental disclosures:
Cash paid during the periods for:
Interest, net of amounts capitalized	$	7,183		$	4,598		$	14,767		$	10,750
Income taxes	$	279		$	5,765		$	302		$	8,165

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

3

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – unaudited

June 30, 2007

1. Nature of Operations

Penn Virginia Corporation (“Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent energy company that is engaged in three primary business segments. Our oil and gas segment explores for, develops, produces and sells crude oil, condensate and natural gas primarily in the Appalachian, Mississippi, Mid-Continent, east Texas and Gulf Coast regions of the United States. Our coal segment and natural gas midstream segment operate through Penn Virginia Resource Partners, L.P. (“PVR”). We own 100% of the general partner of Penn Virginia GP Holdings, L.P. (“PVG”) and an approximately 82% limited partner interest in PVG. PVG owns 100% of the general partner of PVR, which holds a 2% general partner interest in PVR, and an approximately 42% limited partner interest in 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 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.

PVR is a Delaware limited partnership formed by us in July 2001 primarily to engage in the business of managing coal properties in the United States. PVR completed its initial public offering (the “PVR IPO”) in October 2001. PVG completed its initial public offering (the “PVG IPO”) in December 2006, selling approximately 18% of its outstanding units to the public and using the proceeds from the offering to purchase newly issued common and Class B units from PVR.

In the coal segment, PVR does not operate any coal mines. Instead, PVR enters into leases with various third-party operators which give those operators the right to mine coal reserves on PVR’s land in exchange for royalty payments. PVR also provides fee-based infrastructure facilities to some of its lessees and third parties to generate coal services revenues. These facilities include coal loading facilities, preparation plants and coal handling facilities located at end-user industrial plants. PVR also sells timber growing on its land.

In the natural gas midstream segment, PVR owns and operates a significant set of natural gas midstream assets. 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.

2. 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, 2006. Please refer to such Form 10-K for a further discussion of those policies.

Basis of Presentation

The consolidated financial statements include the accounts of Penn Virginia, all of its 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, 2007. PVG GP, LLC, our wholly-owned subsidiary, serves as PVG’s general partner and controls PVG. Intercompany balances and transactions have been eliminated in consolidation. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and Securities and Exchange Commission 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 the consolidated financial statements have been included. These 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, 2006. Operating results for the three months and six months ended June 30, 2007 are not necessarily indicative of the results that may be expected for the year ending December 31, 2007.

4

New Accounting Standards

In July 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109 (“FIN 48”), which became effective for us on January 1, 2007. FIN 48 creates a single model to address uncertainty in income tax positions. It clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition and clearly scopes income taxes out of Statement of Financial Accounting Standards (“SFAS”) No. 5, Accounting for Contingencies. See Note 8 for more information regarding the adoption of FIN 48.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, a standard that provides enhanced guidance for using fair value to measure assets and liabilities. SFAS No. 157 also responds to investors’ requests for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value and the effect of fair value measurements on earnings. SFAS No. 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value. SFAS No. 157 does not expand the use of fair value in any new circumstances. SFAS No. 157 establishes a fair value hierarchy that prioritizes the information used to develop fair value assumptions. SFAS No. 157 is effective for fiscal years and interim periods beginning after November 15, 2007. We have not yet determined the impact on our consolidated financial statements of adopting SFAS No. 157 effective January 1, 2008.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115, which provides companies with an option to report selected financial assets and liabilities at fair value. The objective of SFAS No. 159 is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. We have not yet determined the impact on our consolidated financial statements of adopting SFAS No. 159 effective January 1, 2008.

3. Acquisitions

Oil and Gas Segment

On May 11, 2007, we acquired from a private seller property covering approximately 640 acres located in Jefferson Davis County, Mississippi, with estimated proved reserves of 11.2 billion cubic feet of natural gas equivalent (“Bcfe”). The purchase price was $10.5 million in cash and was funded with long-term debt under our revolving credit facility. The assets have been recorded as a component of property and equipment; however, the purchase price allocation for this acquisition has not been finalized.

PVR Coal Segment

On June 11, 2007, PVR acquired from a private seller approximately 9 million tons of coal reserves. This property is located on approximately 1,700 acres in Jackson County, Illinois. The purchase price was $9.9 million in cash and was funded with long-term debt under PVR’s revolving credit facility.

On June 29, 2007, PVR acquired from a private seller the fee ownership or lease rights to approximately 51 million tons of coal reserves, along with a preparation plant and coal handling facilities. This property is located on approximately 17,000 acres in Webster and Hopkins Counties, Kentucky. The purchase price was $42.0 million in cash and was funded with long-term debt under PVR’s revolving credit facility. The assets have been recorded as a component of property and equipment; however, the purchase price allocation for this acquisition has not been finalized.

5

4. Stock Split

On May 8, 2007, the Board of Directors approved a two-for-one-split of the Company’s common stock in the form of a 100% stock dividend payable on June 19, 2007 to shareholders of record on June 12, 2007. Shareholders received one additional share of common stock for each share held on the record date. All common shares and per share data have been retroactively adjusted to reflect the stock split.

5. Gain on Sale of Subsidiary Units

We accounted for the PVR IPO and each subsequent PVR equity issuance as a sale of a minority interest. For each PVR equity issuance, we calculated a gain under SEC Staff Accounting Bulletin No. 51 (or Topic 5-H), Accounting for Sales of Stock by a Subsidiary (“SAB 51”). Because the PVR common units had preference over the PVR subordinated units with respect to distributions, the gain was not recognized at the time of each PVR equity issuance. This gain was to be recognized in shareholders’ equity when all of the subordinated units converted to common units. By November 2006, all of the subordinated units had converted to common units. However, because the issuance of the PVR Class B units, which were subordinate to the PVR common units with respect to distributions, was contemplated at the time the final PVR subordinated units converted to PVR common units in November 2006, we did not recognize the SAB 51 gain at the time. After the conversion of the Class B units to common units on a one-for-one basis in May 2007, PVR no longer had any form of junior securities outstanding. Accordingly, we recognized a $138.9 million gain in shareholders’ equity related to PVR equity issuances from the time of the PVR IPO in October 2001 to May 2007. SAB 51 gains will be recognized with respect to future PVR equity issuances at the time of the equity issuances as long PVR does not have any junior securities outstanding and is not contemplating the issuance of junior securities.

Similarly, we accounted for the PVG IPO as a sale of a minority interest in December 2006. Because the PVR common units had preference over the PVR Class B units with respect to distributions, the gain was not recognized at the time of the PVG IPO equity issuance. When the PVR Class B units converted to common units in May 2007, we recognized a $104.1 million gain in shareholders’ equity in accordance with SAB 51.

6. Derivative Instruments

For commodity derivative instruments, we recognize mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (shareholders’ equity). The following table summarizes the effects of commodity derivative activities on our consolidated statements of income:

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(in thousands)						(in thousands)
Income statement caption:
Natural gas revenues	$	(68	)	$	676		$	481		$	(416	)
Oil and condensate revenues		(129	)		(40	)		(256	)		(230	)
Natural gas midstream revenues		(2,050	)		(2,564	)		(4,336	)		(4,732	)
Cost of midstream gas purchased		765			1,853			2,208			4,282
Derivatives		(892	)		(6,379	)		(17,613	)		(6,537	)
Decrease in income before minority interest and income taxes	$	(2,374	)	$	(6,454	)	$	(19,516	)	$	(7,633	)
Realized and unrealized derivative impact:
Cash received (paid) for derivative settlements	$	(1,817	)	$	(2,888	)	$	1,695		$	(6,217	)
Unrealized derivative gain (loss)		(557	)		(3,566	)		(21,211	)		(1,416	)
Decrease in income before minority interest and income taxes	$	(2,374	)	$	(6,454	)	$	(19,516	)	$	(7,633	)

6

Oil and Gas Segment Commodity Derivatives

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

With respect to a costless collar contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. A three-way collar contract consists of a collar contract as described above plus a put option contract sold by us with a price below the floor price of the collar. This additional put requires us to make a payment to the counterparty if the settlement price for any settlement period is below the put option price. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the collar contract and the additional put option price if the settlement price is equal to or less than the additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a collar contract only. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional collar contract while defraying the associated cost with the sale of the additional put option. 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.

7

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, 2007. The following table sets forth our positions as of June 30, 2007:

	Average Volume Per Day	Weighted Average Price						Estimated Fair Value
		Additional Put Option		Floor		Ceiling
	(in Mmbtus)	(per Mmbtu)						(in thousands)
Natural Gas Costless Collars
Third Quarter 2007	15,000			$	7.33	$	12.93		947
Fourth Quarter 2007	11,685			$	8.28	$	15.78		1,375
First Quarter 2008	10,000			$	9.00	$	17.95		1,094
	(in Mmbtus)	(per Mmbtu)
Natural Gas Three-way Collars
Third Quarter 2007	33,000	$	5.00	$	7.39	$	9.05		1,973
Fourth Quarter 2007	26,370	$	5.25	$	7.74	$	11.14		1,616
First Quarter 2008	22,500	$	5.44	$	8.00	$	12.64		522
Second Quarter 2008	22,500	$	5.00	$	7.11	$	9.09		(398	)
Third Quarter 2008	22,500	$	5.00	$	7.11	$	9.09		(400	)
Fourth Quarter 2008	15,870	$	5.21	$	7.58	$	10.73		(139	)
First Quarter 2009	10,000	$	5.50	$	8.00	$	12.60		(76	)
	(in barrels)	(per barrel)
Crude Oil Costless Collars
Third Quarter 2007	200			$	60.00	$	72.20		(30	)
Fourth Quarter 2007	200			$	60.00	$	72.20		(57	)
	(in barrels)	(per barrel)
Crude Oil Swaps
Third Quarter 2007	300			$	69.00				(54	)
Fourth Quarter 2007	300			$	69.00				(68	)
Oil and gas segment commodity derivatives—net asset								$	6,307

At June 30, 2007, we have reported (i) a net derivative asset of $6.3 million and (ii) a loss in accumulated other comprehensive income of $0.3 million, net of a related income tax effect of $0.2 million, related to derivatives in the oil and gas segment for which cash flow hedge accounting was discontinued during 2006.

8

PVR Midstream Segment Commodity Derivatives

PVR also utilizes swap derivative contracts in its natural gas midstream business. 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. The fair values of PVR’s derivative agreements are determined based on forward price quotes for the respective commodities as of June 30, 2007. The following table sets forth PVR’s positions as of June 30, 2007 for commodities related to natural gas midstream revenues (ethane, propane, natural gas and crude oil) and cost of midstream gas purchased (natural gas and crude oil):

	Average Volume Per Day	Weighted Average Price		Weighted Average Collars				Estimated Fair Value
				Put		Call
	(in gallons)	(per gallon)						(in thousands)
Ethane Swaps
Third Quarter 2007 through Fourth Quarter 2007	34,440	$	0.5050					$	(1,421	)
First Quarter 2008 through Fourth Quarter 2008	34,440	$	0.4700						(2,344	)
	(in gallons)	(per gallon)
Propane Swaps
Third Quarter 2007 through Fourth Quarter 2007	26,040	$	0.7550						(1,952	)
First Quarter 2008 through Fourth Quarter 2008	26,040	$	0.7175						(3,820	)
	(in barrels)	(per barrel)
Crude Oil Swaps
Third Quarter 2007 through Fourth Quarter 2007	560	$	50.80						(2,071	)
First Quarter 2008 through Fourth Quarter 2008	560	$	49.27						(4,473	)
	(in MMbtu)	(per MMbtu)
Natural Gas Swaps
Third Quarter 2007 through Fourth Quarter 2008	4,000	$	6.97						2,258
	(in gallons / in barrels)	(per gallon / per barrel)
Natural Gasoline Swap/Crude Oil Swap
Third Quarter 2007 through Fourth Quarter 2007	23,520 / 560	$	1.265 /57.12						(294	)
	(in gallons)			(per gallon)
Ethane Collar
Third Quarter 2007 through Fourth Quarter 2007	5,000			$	0.6100	$	0.7125		(52	)
	(in gallons)			(per gallon)
Propane Collar
Third Quarter 2007 through Fourth Quarter 2007	9,000			$	1.0300	$	1.1640		(72	)
	(in gallons)			(per gallon)
Natural Gasoline Collar
Third Quarter 2007 through Fourth Quarter 2008	6,300			$	1.4800	$	1.6465		(380	)
	(in barrels)			(per barrel)
Crude Oil Collar
First Quarter 2008 through Fourth Quarter 2008	400			$	65.00	$	75.25		(226	)
	(in MMbtu)	(per MMbtu)
Frac Spread
Third Quarter 2007 through Fourth Quarter 2007	7,128	$	4.299						(2,196	)
Settlements to be paid in subsequent period									(1,026	)
Natural gas midstream segment commodity derivatives—net liability								$	(18,069	)

At June 30, 2007, PVR reported (i) a net derivative liability related to the natural gas midstream segment of $18.1 million and (ii) a loss in accumulated other comprehensive income of $5.2 million, net of a related income tax effect of $2.7 million, related to derivatives in the natural gas midstream segment for which PVR discontinued cash flow hedge accounting in 2006.

Interest Rate Swaps—PVA

In August 2006, we entered into interest rate swap agreements (the “Revolver Swaps”) to establish fixed rates on $50 million of the portion of the outstanding balance on our revolving credit facility that is based on the London Inter Bank Offering Rate (“LIBOR”) until December 2010. We pay a weighted average fixed rate of 5.34% on the notional amount plus the applicable margin, and the counterparties 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 as interest expense. We reported (i) a derivative liability of less than $0.1

9

million at June 30, 2007 and (ii) a loss in accumulated other comprehensive income of less than $0.1 million, net of the related tax effect of less than $0.1 million, at June 30, 2007 related to the Revolver Swaps. In connection with periodic settlements, we recognized less than $0.1 million in net hedging gains in interest expense for the six months ended June 30, 2007.

Interest Rate Swaps—PVR

In September 2005, PVR entered into interest rate swap agreements (the “PVR Revolver Swaps”) to establish fixed rates on $60 million of the portion of the outstanding balance on PVR’s revolving credit facility that is based on the LIBOR until March 2010. PVR pays a weighted average fixed rate of 4.22% on the notional amount plus the applicable margin, and the counterparties 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 were designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings as interest expense. PVR reported (i) a derivative asset of approximately $1.7 million at June 30, 2007 and (ii) a gain in accumulated other comprehensive income of $1.1 million, net of related income tax effect of $0.6 million, at June 30, 2007 related to the PVR Revolver Swaps. In connection with periodic settlements, PVR recognized $0.3 million in net hedging gains in interest expense for the six months ended June 30, 2007.

7. Assets Held for Sale

In May 2007, the Board of Directors approved a plan to sell certain working interests in oil and gas wells located in Virginia and Kentucky. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we reclassified these working interests to assets held for sale on our consolidated balance sheet. We expect to complete the sale by the end of the third quarter of 2007. The asset disposition did not qualify for accounting as discontinued operations, in accordance with Emerging Issues Task Force Issue No. 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations. We migrated our investment and operations to other locations within the Appalachian area.

8. Income Taxes

Effective January 1, 2007, we adopted FIN 48. The evaluation of whether a tax position is in accordance with FIN 48 is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon settlement.

The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of FIN 48. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings for that fiscal year. The adoption of FIN 48 did not result in a transition adjustment to retained earnings; instead, $8.7 million was reclassified from deferred income taxes to a long-term liability.

The long-term liability balance at June 30, 2007 was $9.7 million, including $6.6 million of tax positions which would change the effective tax rate, if recognized. We recognize interest related to unrecognized tax benefits in interest expense, and penalties are included in income tax accrued. For the three months and six months ended June 30, 2007, we recognized $0.2 million and $0.3 million in interest and penalties. Prior to adoption of FIN 48, we classified interest on taxes as a component of income tax expense, and penalties were included in other expenses. We had accrued interest and penalties of $3.1 million as of June 30, 2007 and $2.7 million as of January 1, 2007. We do not expect a significant change in unrecognized tax benefits within the next 12 months. Tax years from 2003 forward remain open for examination by the Internal Revenue Service.

10

9. Earnings per Share

The following is a reconciliation of the numerators and denominators used in the calculation of basic and diluted earnings per share for the three months and six months ended June 30, 2007 and 2006:

	Three Months Ended June 30,				Six Months Ended June 30,
	2007		2006		2007		2006
	(in thousands except per share data)
Net income	$	23,878	$	18,217	$	28,281	$	42,325
Weighted average shares, basic		37,750		37,354		37,682		37,336
Effect of dilutive stock options:		305		472		280		458
Weighted average shares, diluted		38,055		37,826		37,962		37,794
Net income per share, basic	$	0.63	$	0.49	$	0.75	$	1.13
Net income per share, diluted	$	0.63	$	0.48	$	0.74	$	1.12

10. Share-Based Payments

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, 2007 and 2006, we recognized a total of $0.9 million and $0.7 million of compensation expense related to our stock compensation plans. The total income tax benefit recognized in our consolidated statements of income for our stock compensation plans was $0.4 million and $0.3 million for the three months ended June 30, 2007 and 2006. For the six months ended June 30, 2007 and 2006, we recognized a total of $2.0 million and $1.3 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 $0.8 million and $0.5 million for the six months ended June 30, 2007 and 2006.

Stock Options. In February 2007, we granted 414,030 stock options with a weighted average exercise price of $35.21 and a weighted average grant date fair value of $9.67 per option. The options vest ratably over a three-year period.

Restricted Stock. In February 2007, we also granted 17,056 shares of restricted stock with a weighted average grant date fair value of $35.21 per share. Restricted stock granted in 2007 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 compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under the long-term incentive plan of PVR’s general partner to our employees who perform services for PVR. For the three months ended June 30, 2007 and 2006, PVR recognized a total of $0.6 million and $0.9 million of compensation expense related to the long-term incentive plan. For the six months ended June 30, 2007 and 2006, PVR recognized a total of $1.1 million and $1.3 million of compensation expense related to the long-term incentive plan.

During the six months ended June 30, 2007, 85,233 PVR restricted units with a weighted average grant date fair value of $26.85 per unit were granted to our employees who perform services for PVR. During the same period, 42,582 PVR restricted units with a weighted average grant date fair value of $27.56 per unit vested. PVR restricted units granted in 2007 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.

11

11. Comprehensive Income

Comprehensive income represents certain changes in equity during the reporting period, including net income and charges directly to equity which are excluded from net income. For the three months and six months ended June 30, 2007 and 2006, the components of comprehensive income were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(in thousands)
Net income	$	23,878		$	18,217		$	28,281		$	42,325
Unrealized holding gains (losses) on derivative activities, net of tax		994			(1,954	)		710			1,555
Reclassification adjustment for derivative activities, net of tax		850			(20	)		1,013			300
Pension plan adjustment		(35	)		—			(71	)		—
Comprehensive income	$	25,687		$	16,243		$	29,933		$	44,180

12. Suspended Well Costs

We had a $1.1 million balance related to one well in capitalized drilling costs at December 31, 2006. Subsequently, the well was determined to be dry and all amounts have been reclassified to exploration expense.

13. 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, management believes these claims will not have a material effect on our financial position, liquidity or operations.

Environmental Compliance

Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent

12

pollution from former operations, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material adverse impact on us. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations.

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

As of June 30, 2007, PVR’s environmental liabilities included $1.5 million, which represents PVR’s best estimate of its liabilities as of that date related to its coal 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 coal 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.

14. 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 chief operating 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, PVR’s coal 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.

• Coal (the “PVR coal” segment)—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.

• Natural Gas Midstream (the “PVR midstream” segment)—natural gas processing, natural gas gathering and other related services.

13

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

	Oil and Gas			PVR Coal		PVR Midstream		Corporate and Other			Consolidated
	(in thousands)
For the Three Months Ended June 30, 2007:
Revenues	$	78,568		$	28,212	$	115,312	$	306		$	222,398
Intersegment revenues (1)		(422	)		198		422		(198	)		—
Operating costs and expenses		23,840			5,524		101,416		5,998			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
Additions to property and equipment and acquisitions, net of cash acquired	$	101,333		$	52,130	$	11,859	$	1,598		$	166,920
For the Three Months Ended June 30, 2006:
Revenues	$	55,636		$	27,700	$	95,565	$	249		$	179,150
Intersegment revenues (1)		—			198		—		(198	)		—
Operating costs and expenses		18,484			3,822		81,536		3,705			107,547
Depreciation, depletion and amortization		12,737			4,747		4,069		111			21,664
Operating income (loss)	$	24,415		$	19,329	$	9,960	$	(3,765	)		49,939
Interest expense												(5,396	)
Interest income and other												363
Derivatives												(6,379	)
Income before minority interest and taxes											$	38,527
Additions to property and equipment and acquisitions, net of cash acquired	$	128,306		$	69,163	$	18,980	$	727		$	217,176

(1) Represents agent fees paid by the oil and gas segment to the PVR midstream segment for marketing certain natural gas production and rail car rental fees paid by a corporate affiliate to the PVR coal segment.

14

	Oil and Gas			PVR Coal		PVR Midstream		Corporate and Other			Consolidated
	(in thousands)
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
Additions to property and equipment and acquisitions, net of cash acquired	$	201,058		$	53,466	$	17,864	$	3,138		$	275,526
For the Six Months Ended June 30, 2006:
Revenues	$	121,377		$	52,830	$	205,401	$	449		$	380,057
Intersegment revenues (1)		—			396		—		(396	)		—
Operating costs and expenses		37,889			7,331		186,124		6,863			238,207
Depreciation, depletion and amortization		25,390			9,499		8,138		218			43,245
Operating income (loss)	$	58,098		$	36,396	$	11,139	$	(7,028	)		98,605
Interest expense												(10,184	)
Interest income and other												759
Derivatives												(6,537	)
Income before minority interest and taxes											$	82,643
Additions to property and equipment and acquisitions, net of cash acquired	$	172,458		$	75,167	$	21,541	$	1,036		$	270,202

(1) Represents agent fees paid by the oil and gas segment to the PVR midstream segment for marketing certain natural gas production and rail car rental fees paid by a corporate affiliate to the PVR coal segment.

15. Subsequent Events

On July 2, 2007, we acquired from a private seller property covering approximately 4,000 acres located in Harrison County, Texas, with estimated proved reserves of 19.5 Bcfe. The purchase price was $22.0 million in cash and was funded with long-term debt under our revolving credit facility.

On July 24, 2007, our Board of Directors declared a $0.05625 per share quarterly dividend for the three months ended June 30, 2007, or $0.225 per share on an annualized basis. The dividend will be paid on September 5, 2007 to shareholders of record at the close of business on August 10, 2007.

15

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 (“Penn Virginia,” the “Company,” “we,” “us” or “our”) should be read in conjunction with our consolidated financial statements and the accompanying notes in Item 1, “Financial Statements.” Our discussion and analysis include the following items:

• Overview of Business

• Acquisitions and Investments

• Liquidity and Capital Resources

• Results of Operations

• Summary of Critical Accounting Policies and Estimates

• Environmental Matters

• Recent Accounting Pronouncements

• Forward-Looking Statements

Overview of Business

We are an independent energy company that is engaged in three primary business segments: oil and gas, coal and natural gas midstream. We directly operate our oil and gas segment. Penn Virginia Resource Partners, L.P., (“PVR”) operates our coal and natural gas midstream segments. We own 100% of the general partner of Penn Virginia GP Holdings, L.P. (“PVG”) and an approximately 82% limited partner interest in PVG. PVG owns 100% of the general partner of PVR, which holds a 2% general partner interest in PVR, and an approximately 42% limited partner interest in PVR. Operating income for the six months ended June 30, 2007 was $95.6 million, compared to $98.6 million for the six months ended June 30, 2006. For the six months ended June 30, 2007, the oil and gas segment contributed $58.3 million, or 61%, to operating income, the PVR coal segment contributed $35.5 million, or 37%, and the PVR natural gas midstream segment contributed $14.3 million, or 15%. Corporate and other functions resulted in $12.4 million of operating expenses. For the six months ended June 30, 2007, we had an approximately 82% interest in PVG’s net income. The following table presents a summary of certain financial information relating to our segments:

	Oil and Gas		PVR Coal		PVR Midstream		Corporate and Other			Consolidated
	(in thousands)
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
For the Six Months Ended June 30, 2006:
Revenues	$	121,377	$	53,226	$	205,401	$	53		$	380,057
Operating costs and expenses		37,889		7,331		186,124		6,863			238,207
Depreciation, depletion and amortization		25,390		9,499		8,138		218			43,245
Operating income (loss)	$	58,098	$	36,396	$	11,139	$	(7,028	)	$	98,605

Oil and Gas Segment

In our oil and gas segment, we explore for, develop, produce and sell crude oil, condensate and natural gas primarily in the Appalachian, Mississippi, east Texas, Mid-Continent and Gulf Coast regions of the United States. At December 31, 2006, we had proved oil and natural gas reserves of approximately 5 million barrels of oil and condensate and 457 billion cubic feet (“Bcf”) of natural gas, or 487 billion cubic feet equivalent (“Bcfe”). Oil and natural gas production from our properties increased to 18.8 Bcfe for the six months ended June 30, 2007, an increase of 27% from 14.8 Bcfe produced in the six months ended June 30, 2006. Two oil and gas segment customers accounted for 36% of our natural gas and oil and condensate revenues.

16

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 is 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 coal bed methane (“CBM”) gas 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 Segment

As of December 31, 2006, PVR owned or controlled approximately 765 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 does not operate any coal mines. In the six months ended June 30, 2007, PVR’s lessees produced 16.3 million tons of coal from its properties and paid PVR coal royalty revenues of $49.0 million, for an average gross coal royalty per ton of $3.00. Approximately 81% of PVR’s coal royalty revenues in the six months ended June 30, 2007 and 2006 were derived from coal mined on PVR 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 its coal royalty revenues for the respective periods was derived from coal mined on PVR 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. The possibility exists that new legislation or regulations have or may be adopted which may have a significant impact on the mining operations of PVR’s lessees or their customers’ ability to use coal and which may require PVR, its lessees or its lessee’s customers to change operations significantly or incur substantial costs.

Coal prices also impact coal royalty revenues. Coal prices, especially in Central Appalachia where the majority of PVR’s coal is produced, increased significantly from the beginning of 2004 through most of 2006. The price increase during that period was primarily the result of increased electricity demand, rebuilding of inventories and decreasing coal production in Central Appalachia. In the second half of 2006 and continuing into 2007, coal prices decreased from the historically high levels experienced in the previous two and one half years, due to higher than normal coal inventories at electric utilities and milder than normal winter weather.

Substantially all of PVR’s leases require the lessee to pay minimum rental payments to PVR in monthly or annual installments. PVR actively works with its lessees to develop efficient methods to exploit its reserves and to maximize production from its properties. PVR also earns revenues from providing fee-based coal preparation and transportation services to its lessees, which enhance their production levels and generate additional coal royalty revenues, and from industrial third party coal end-users by owning and operating coal handling facilities through its joint venture with Massey Energy Company. In addition, PVR earns revenues from oil and gas royalty interests it owns, from coal transportation rights and from the sale of standing timber on its properties.

17

PVR Natural Gas Midstream Segment

PVR owns and operates natural gas midstream assets located in Oklahoma and the panhandle of Texas. These assets include approximately 3,655 miles of natural gas gathering pipelines and three natural gas processing facilities having 160 million cubic feet per day (“MMcfd”) of total capacity. 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.

For the six months ended June 30, 2007, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 32.9 billion cubic feet, or 182 MMcfd, and three of PVR’s natural gas midstream customers accounted for 53% of PVR’s natural gas midstream revenues.

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 by contracting for natural gas that has been released from competitors’ systems.

Revenues, profitability and the future rate of growth of the natural gas midstream segment are highly dependent on market demand and prevailing natural gas liquid (“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.

Corporate and Other

Corporate and other primarily represents corporate functions.

Ownership of and Relationship with PVG and PVR

Penn Virginia, PVG and PVR are publicly traded on the New York Stock Exchange under the symbols “PVA,” “PVG” and “PVR.” Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. Because PVG controls the general partner of PVR, the financial results of PVG include those of PVR. 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 gas midstream businesses, the only cash we received from those businesses is in the form of cash distributions from PVG.

As of June 30, 2007, we owned the general partner of PVG and an approximately 82% limited partner interest in PVG. PVG owns the general partner of PVR, which holds a 2% general partner interest in PVR and all the incentive distribution rights, and an approximately 42% limited interest in PVR. We directly owned an additional 0.5% limited partner interest in PVR as of June 30, 2007. The following diagram depicts our ownership of PVG and PVR as of June 30, 2007:

18

Acquisitions and Investments

Oil and Gas Segment

On May 11, 2007, we acquired from a private seller property covering approximately 640 acres located in Jefferson Davis County, Mississippi, with estimated proved reserves of 11.2 Bcfe. The purchase price was $10.5 million in cash and was funded with long-term debt under our revolving credit facility. The assets have been recorded as a component of property and equipment; however, the purchase price allocation for this acquisition has not been finalized.

PVR Coal Segment

On June 11, 2007, PVR acquired from a private seller approximately 9 million tons of coal reserves. This property is located on approximately 1,700 acres in Jackson County, Illinois. The purchase price was $9.9 million in cash and was funded with long-term debt under PVR’s revolving credit facility.

On June 29, 2007, PVR acquired from a private seller the fee ownership or lease rights to approximately 51 million tons of coal reserves, along with a preparation plant and coal handling facilities. This property is located on approximately 17,000 acres in Webster and Hopkins Counties, Kentucky. The purchase price was $42.0 million in cash and was funded with long-term debt under PVR’s revolving credit facility. The assets have been recorded as a component of property and equipment; however, the purchase price allocation for this acquisition has not been finalized.

19

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 issuance of new PVG and PVR units. We expect that our cash needs and the cash needs of PVG and PVR will continue to be met independently of each other with a combination of these funding sources.

Cash Flows

Except where noted, the following discussion of cash flows and capital expenditures relates to our consolidated results.

The following table summarizes our cash flow statements for the six months ended June 30, 2007 and 2006, consolidating our segments (in thousands):

	Oil and Gas & Corporate			PVR Coal and PVR Midstream			Consolidated
For the six months ended June 30, 2007:
Net cash provided by operating activities	$	75,481		$	57,316		$	132,797
Cash flows from financing activities:
Dividends paid		(4,240	)		—			(4,240	)
Partnership distributions received (paid)		19,515			(42,980	)		(23,465	)
Debt borrowings, net		107,500			57,000			164,500
Proceeds from equity issuance		—			860			860
Other		6,704			—			6,704
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
	Oil and Gas & Corporate			PVR Coal and PVR Midstream			Consolidated
For the six months ended June 30, 2006:
Net cash provided by operating activities	$	99,381		$	50,519		$	149,900
Cash flows from financing activities:
Dividends paid		(4,197	)		—			(4,197	)
PVR distributions received (paid)		12,731			(31,048	)		(18,317	)
Debt borrowings, net		66,000			61,500			127,500
Other		734			—			734
Net cash provided by financing activities		75,268			30,452			105,720
Net cash provided by operating and financing activities		174,649			80,971			255,620
Net cash used in investing activities		(171,022	)		(96,705	)		(267,727	)
Net increase (decrease) in cash and cash equivalents	$	3,627		$	(15,734	)	$	(12,107	)

Cash provided by operating activities in the oil and gas and corporate segments decreased $23.9 million, or 24%, to $75.5 million for the six months ended June 30, 2007 from $99.4 million for the same period in 2006. The overall decrease in cash provided by operating activities from the oil and gas and corporate segments in the six months ended June 30, 2007 compared to the same period in 2006 was primarily due to decreased natural gas and crude oil prices.

20

Cash provided by operating activities in the PVR coal and PVR natural gas midstream segments increased $6.8 million, or 13%, to $57.3 million for the six months ended June 30, 2007 from $50.5 million for the same period in 2006. The overall increase in cash provided by operating activities for the six months ended June 30, 2007 compared to the same period in 2006 was primarily attributable to an increase in coal royalty revenues, an increase in natural gas midstream production and an overall increase in working capital.

Capital expenditures, which comprises the primary portion of cash used in investing activities, totaled $281.8 million for the six months ended June 30, 2007, compared to $306.7 million for the six months ended June 30, 2006. The following table sets forth capital expenditures by segment made during the periods indicated:

	Six Months Ended June 30,
	2007		2006
	(in thousands)
Oil and gas
Proved property acquisitions	$	8,507	$	72,531
Development drilling		147,343		65,984
Exploration drilling		27,704		18,735
Seismic		1,582		3,640
Lease acquisition and other		12,868		41,259
Pipeline, gathering, facilities		10,192		7,115
Total		208,196		209,264
Coal
Acquisitions		52,456		66,382
Expansion capital expenditures		52		7,691
Other property and equipment expenditures		85		43
Total		52,593		74,116
Natural gas midstream
Acquisitions, net of cash acquired		—		14,626
Expansion capital expenditures		12,540		3,392
Other property and equipment expenditures		4,635		4,278
Total		17,175		22,296
Other		3,802		1,038
Total capital expenditures	$	281,766	$	306,714

During the six months ended June 30, 2007, the oil and gas segment made aggregate capital expenditures of $208.2 million, primarily for development drilling and exploration drilling. During the six months ended June 30, 2006, the oil and gas segment made aggregate capital expenditures of $209.3 million primarily for development drilling, proved property acquisitions and exploration drilling. In both periods, the oil and gas segment’s capital expenditures were funded with cash provided by operating activities and borrowings under our revolving credit facility.

During the six months ended June 30, 2007, PVR made aggregate capital expenditures of $69.8 million primarily for coal reserve acquisitions and natural gas midstream gathering system expansion projects. During the six months ended June 30, 2006, PVR made aggregate capital expenditures of $96.4 million primarily for coal reserve acquisitions and the acquisition of pipeline and compression facilities. In both periods, PVR’s capital expenditures were funded with cash provided by operating activities and borrowings under PVR’s revolving credit facility.

21

We borrowed $107.5 million under our revolving credit facility in the six months ended June 30, 2007, compared to borrowings, net of repayments, of $66.0 million in the six months ended June 30, 2006. PVR borrowed $57.0 million, net of repayments, under the its revolving credit facility in the six months ended June 30, 2007, compared to borrowings, net of repayments, of $61.5 million for the six months ended June 30, 2006. As a result of our partner interests in PVG and PVR, we received cash distributions of $32.3 million in the six months ended June 30, 2007, compared to $12.7 million of cash distributions in the same period in 2006. Distributions increased $19.6 million primarily due to PVR increasing its distribution per unit from $0.35 to $0.41. Funds from both of these sources were primarily used for capital expenditures.

In July 2007, PVR declared a $0.42 per unit quarterly distribution for the three months ended June 30, 2007, or $1.68 per unit on an annualized basis. The distribution will be paid on August 14, 2007 to unitholders of record at the close of business on August 6, 2007. The portion of PVR’s distribution paid to PVG serves as the basis for PVG’s distribution to its unitholders, including us. In July 2007, PVG declared a $0.28 per unit quarterly distribution for the three months ended June 30, 2007, or $1.12 per unit on an annualized basis, of which we will receive $9.0 million as a result of our partner interests in PVG. This distribution will be paid on August 20, 2007 to unitholders of record at the close of business on August 6, 2007.

Long-Term Debt

Revolving Credit Facility. We have a revolving credit facility (the “Revolver”) that is secured by a portion of our proved oil and gas reserves and matures in December 2010. Effective April 13, 2007, we amended the Revolver to increase the commitment from $300 million to $400 million and the borrowing base from $400 million to $450 million. Effective August 1, we amended the Revolver to increase the commitment from $400 million to $450 million. We had $328.5 million outstanding and $0.4 million letters of credit issued under the Revolver as of June 30, 2007, giving us $121.1 million of available borrowing capacity at that time. We have a one-time option to expand the Revolver by $50 million. The Revolver is governed by a borrowing base calculation and is redetermined semi-annually. We have the option to elect interest at (i) the London Inter Bank Offering Rate (“LIBOR”) plus a Eurodollar margin ranging from 1.00% to 1.75%, based on the percentage of the borrowing base outstanding 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 during the six months ended June 30, 2007 was 6.6%. In the six months ended June 30, 2007, we incurred commitment fees of $0.3 million on the unused portion of the Revolver. We capitalized $1.9 million of interest cost incurred in the six months ended June 30, 2007. The Revolver allows for the issuance of up to $20 million of letters of credit, of which $0.4 million were issued as of June 30, 2007.

The financial covenants under the Revolver require us to not exceed specified debt-to-EBITDAX 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, 2007, we were in compliance with all of our covenants under the Revolver.

Line of Credit. Until June 30, 2007, we had a $10 million line of credit with a financial institution. The line of credit had no borrowings against it as of June 30, 2007. We are negotiating an extension and an increase to this line of credit with the financial institution.

Revolver Interest Rate Swaps. We entered into interest rate swap agreements (the “Revolver Swaps”) to swap $50 million of outstanding borrowings under the Revolver from a variable rate to a weighted average fixed rate of 5.34% plus the applicable margin. 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 1.25% in effect as of June 30, 2007, the total interest rate on the $50 million portion of Revolver borrowings covered by the Revolver Swaps was 6.59% at June 30, 2007.

22

PVR Revolving Credit Facility. As of June 30, 2007, PVR had $205.2 million outstanding under its $300 million unsecured revolving credit facility (the “PVR Revolver”) that matures in December 2011. The PVR Revolver is available to PVR for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10 million sublimit for the issuance of letters of credit. PVR had outstanding letters of credit of $1.6 million as of June 30, 2007. In the six months ended June 30, 2007, PVR incurred commitment fees of $0.2 million on the unused portion of the PVR Revolver. PVR has a one-time option to expand the PVR Revolver by $150 million upon receipt by the credit facility’s administrative agent of commitments from one or more lenders. The interest rate under the PVR Revolver fluctuates based on its ratio of 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 the LIBOR plus an applicable margin ranging from 0.75% to 1.75% if PVR selects the LIBOR-based borrowing option.

The financial covenants under the PVR Revolver require PVR to not exceed specified levels of debt-to-consolidated EBITDA and consolidated EBITDA-to-interest expense ratios. At the current $300 million limit on the PVR Revolver, and given PVR’s outstanding balance of $205.2 million, net of $1.6 million of letters of credit, PVR could borrow up to $93.2 million without exercising its one-time option to expand the PVR Revolver. 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 PVR’s subsidiaries. As of June 30, 2007, PVR was in compliance with all of its covenants under the PVR Revolver.

PVR Senior Unsecured Notes. As of June 30, 2007, PVR owed $69.9 million under its senior unsecured notes (the “Notes”). The Notes bear interest at a fixed rate of 6.02% and mature in March 2013, with semi-annual principal and interest payments. The Notes are equal in right of payment with all of PVR’s other unsecured indebtedness, including the PVR Revolver. The Notes require PVR to obtain an annual confirmation of its credit rating, with a 1.00% increase in the interest rate payable on the Notes in the event its credit rating falls below investment grade. In March 2007, PVR’s investment grade credit rating was confirmed by Dominion Bond Rating Services. The Notes contain various covenants similar to those contained in the PVR Revolver. As of June 30, 2007, PVR was in compliance with all of its covenants under the Notes.

PVR Interest Rate Swaps. In September 2005, PVR entered into interest rate swap agreements (the “PVR Revolver Swaps”) with notional amounts totaling $60 million to establish fixed rates on the LIBOR-based portion of the outstanding balance of the PVR Revolver until March 2010. PVR pays a weighted average fixed rate of 4.22% on the notional amount plus the applicable margin, and the counterparties 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 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 0.75% in effect as June 30, 2007, the total interest rate on the $60 million portion of PVR Revolver borrowings covered by the PVR Revolver Swaps was 4.97% at June 30, 2007.

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 Appalachia, Mississippi, east Texas and the Mid-Continent with relatively moderate risk, potentially higher return development projects and exploration prospects in south Texas and south Louisiana. 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.

Including property acquisitions completed to date, we expect to make oil and gas segment capital expenditures of approximately $380 to $405 million in 2007. 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

23

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 2007 planned oil and gas capital expenditure program.

Part of PVR’s strategy is to make acquisitions and other capital expenditures which increase cash available for distribution to its unitholders. PVR’s ability to make these acquisitions in the future will depend in part on the availability of debt financing and on its ability to periodically use equity financing through the issuance of new common units, which will depend on various factors, including prevailing market conditions, interest rates and its financial condition and credit rating at the time. Including property acquisitions completed to date, PVR anticipates making capital expenditures in 2007 of approximately $54 million to $56 million for coal reserve acquisitions, coal services projects and other property and equipment and approximately $48 million to $52 million for natural gas midstream system expansion projects and maintenance capital expenditures. PVR intends to fund these capital expenditures with a combination of cash flows provided by operating activities and borrowings under the PVR Revolver. PVR makes quarterly cash distributions of its available cash, generally defined as all of its cash and cash equivalents on hand at the end of each quarter less cash reserves. PVR believes that it will continue to have adequate liquidity to fund future recurring operating and investing activities. Short-term cash requirements, such as operating expenses and quarterly distributions to PVR’s general partner and unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for asset acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities and the issuance of additional equity and debt securities.

We have budgeted other capital expenditures of approximately $6 million to $8 million in 2007 for administrative purposes, including the implementation of a new accounting software system.

Results of Operations

Selected Financial Data—Consolidated

The following table sets forth a summary of certain consolidated financial data for the periods indicated:

	Three Months Ended June 30,				Six Months Ended June 30,
	2007		2006		2007		2006
	(in thousands, except per share data)
Revenues	$	222,398	$	179,150	$	408,668	$	380,057
Expenses		165,324		129,211		313,055		281,452
Operating income	$	57,074	$	49,939	$	95,613	$	98,605
Net income	$	23,878	$	18,217	$	28,281	$	42,325
Earnings per share, basic	$	0.63	$	0.49	$	0.75	$	1.13
Earnings per share, diluted	$	0.63	$	0.48	$	0.74	$	1.12
Cash flows provided by operating activities	$	67,856	$	84,205	$	132,797	$	149,900

Operating income increased in the three months ended June 30, 2007 compared to the same period in 2006 primarily due to an increase in operating income from the oil and gas segment, partially offset by decreases in operating income from the coal and natural gas midstream segments. Operating income decreased in the six months ended June 30, 2007 compared to the same period in 2006 primarily due to decreases in operating income from the coal segment and corporate and other activities, partially offset by increases in operating income from the oil and gas and natural gas midstream segments.

Net income increased in the three months ended June 30, 2007 compared to the same period in 2006 primarily due to a $5.4 million decrease in derivative losses and an $8.5 million increase in operating income, partially offset by a $2.9 million increase in interest expense and the related increase in income tax expense. Net income decreased in the six months ended June 30, 2007 compared to the same period in 2006 primarily due to an $11.1 million increase in derivative losses, a $3.0 million decrease in operating income and a $4.9 million increase in interest expense, partially offset by the related decrease in income tax expense.

24

The assets, liabilities and earnings of PVG are fully consolidated in our financial statements, with the public unitholders’ interest (18% as of June 30, 2007) reflected as a minority interest. The assets, liabilities and earnings of PVR are fully consolidated in PVG’s financial statements, with the public unitholders’ interest (48%, after the effect of incentive distribution rights, as of June 30, 2007) reflected as minority interest in PVG’s financial statements.

Oil and Gas Segment

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006

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 periods indicated:

	Three Months Ended June 30,				% Change		Three Months Ended June 30,
	2007		2006				2007		2006
	(in thousands, except as noted)						(per Mcfe) (1)
Production
Natural gas (Mmcf)		9,381		6,926	35	%
Oil and condensate (thousand barrels)		113		95	19	%
Total production (Mmcfe)		10,060		7,496	34	%
Revenues
Natural gas	$	72,032	$	49,634	45	%	$	7.68	$	7.17
Oil and condensate		5,750		5,623	2	%		50.82		59.19
Other income		364		379	(4	)%
Total revenues		78,146		55,636	40	%		7.77		7.42
Expenses
Operating		10,024		6,608	52	%		1.00		0.88
Taxes other than income		4,647		3,382	37	%		0.46		0.45
General and administrative		3,502		2,984	17	%		0.35		0.40
Production costs		18,173		12,974	40	%		1.81		1.73
Exploration		5,667		5,510	3	%		0.56		0.74
Depreciation, depletion and amortization		18,632		12,737	46	%		1.85		1.70
Total expenses		42,472		31,221	36	%		4.22		4.17
Operating income	$	35,674	$	24,415	46	%	$	3.55	$	3.26

(1) Natural gas revenues are shown per Mcf, oil and condensate revenues are shown per Bbl, and all other amounts are shown per million cubic feet equivalent (“Mcfe”).

Production. Approximately 93% and 92% of production in the three months ended June 30, 2007 and 2006 was natural gas. Total production increased 34% to 10.1 Bcfe in the three months ended June 30, 2007 from 7.5 Bcfe in the same period in 2006. This increase was primarily due to increased natural gas production in the east Texas, Gulf Coast and Mid-Continent regions.

We drilled a total of 71 gross (54.0 net) development wells during the three months ended June 30, 2007 and no exploratory wells. All wells were successful except one gross (0.6 net) development well.

25

The following table summarizes total natural gas, oil and condensate production and total natural gas, oil and condensate revenues by region:

	Natural Gas, Oil and Condensate Production		Natural Gas, Oil and Condensate Revenues
	Three Months Ended June 30,		Three Months Ended June 30,
Region	2007	2006	2007		2006
	(MMcfe)		(in thousands)
Appalachia	3,123	3,231	$	24,196	$	23,873
Gulf Coast	2,608	1,763		21,137		11,795
Mississippi	1,837	1,564		14,416		10,952
East Texas	1,631	832		12,773		8,065
Mid-Continent	861	106		5,260		572
Total	10,060	7,496	$	77,782	$	55,257

Revenues. Natural gas revenues increased $17.6 million as a result of increased natural gas production and $4.8 million as a result of increased realized prices for natural gas. The average realized price received for natural gas during the three months ended June 30, 2007 was $7.68 per Mcf compared to $7.17 per Mcf during the same period in 2006, a 7% increase. Increased oil and condensate production was the primary reason for the $0.1 million increase in oil and condensate revenues.

Natural gas and oil and condensate revenues are derived from the sale of our oil and gas production, which is net of the effects of the settlement of derivative contracts that followed hedge accounting. Settlement of our derivative contracts that do not follow hedge accounting has no effect on our reported revenues. Beginning in May 2006, none of our derivative contracts follow hedge accounting. Our revenues may vary significantly from period to period as a result of changes in commodity prices or production volumes. As part of our risk management strategy, we use derivative financial instruments to hedge natural gas and, to a lesser extent, oil prices. The use of this risk management strategy has resulted in lower price realizations compared to physical sale prices in the last several years.

The following table shows a summary of the effects of derivative activities on revenues and realized prices for the three months ended June 30, 2007 and 2006:

	Three Months Ended June 30,
	2007		2006			2007		2006
	(in thousands)					(per Mcf)
Natural gas revenue, as reported	$	72,032	$	49,634		$	7.68	$	7.17
Derivatives (gains) losses included in natural gas revenues		68		(676	)		0.01		(0.10	)
Natural gas revenue before impact of derivatives		72,100		48,958			7.69		7.07
Cash settlements on natural gas derivatives		326		2,250			0.03		0.32
Natural gas revenues, adjusted for derivatives	$	72,426	$	51,208		$	7.72	$	7.39
						(per Bbl)
Crude oil revenue, as reported	$	5,750	$	5,623		$	50.88	$	59.19
Derivatives (gains) losses included in oil and condensate revenues		129		40			1.14		0.42
Oil and condensate revenue before impact of derivatives		5,879		5,663			52.02		59.61
Cash settlements on crude oil derivatives		51		—			0.45		—
Oil and condensate revenues, adjusted for derivatives	$	5,930	$	5,663		$	52.47	$	59.61

Expenses. Aggregate operating costs and expenses in the three months ended June 30, 2007 increased primarily due to increases in operating expenses, taxes other than income, general and administrative expenses and depreciation, depletion and amortization (“DD&A”) expenses.

Operating expenses increased from $6.6 million in the three months ended June 30, 2006 to $10.0 million in the same period in 2007, or 52%, primarily due to increased repair and maintenance charges, gathering, transportation and processing charges and compressor rental charges resulting from increased production in the east Texas and Appalachian regions. The acquisition of the Mid-Continent assets and the related well operating costs also contributed to the increase in operating expenses.

26

Taxes other than income increased from $3.4 million in the three months ended June 30, 2006 to $4.6 million in the same period in 2007. This increase was due primarily to the increase in production.

General and administrative expenses increased from $3.0 million in the three months ended June 30, 2006 to $3.5 million in the same period in 2007, or 17%, primarily due to increased payroll costs as a result of an additional office in our Mid-Continent region and new personnel.

Exploration expenses for the three months ended June 30, 2007 and 2006 consisted of the following:

	Three Months Ended June 30,
	2007		2006
	(in thousands)
Dry hole costs	$	2,329	$	2,649
Seismic		779		1,228
Unproved leasehold		2,001		1,333
Other		558		300
Total	$	5,667	$	5,510

Exploration expenses increased primarily due to an increase in unproved leasehold expenses, partially offset by decreases in dry hole costs and seismic costs. Dry hole costs decreased primarily due to the write-off of three wells in the Gulf Coast region in the three months ended June 30, 2006 compared to the write-off of one well in the Gulf Coast region and one well in the East Texas region in the same period of 2007. The timing of seismic data purchases caused seismic expenses to decrease. The increase in unproved leasehold expenses was due to the amortization of unproved properties acquired over the past year.

Oil and gas DD&A expenses increased due to the 34% increase in equivalent production and as a result of higher depletion rates. The average depletion rate increased from $1.70 per Mcfe in the three months ended June 30, 2006 to $1.85 per Mcfe in the three months ended June 30, 2007 as a result of a greater percentage of production coming from our 2006 acquisition of Mid-Continent properties and our relatively higher cost horizontal CBM and Cotton Valley wells.

27

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

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 periods indicated:

	Six Months Ended June 30,				% Change		Six Months Ended June 30,
	2007		2006				2007		2006
	(in thousands, except as noted)						(per Mcfe) (1)
Production
Natural gas (Mmcf)		17,465		13,677	28	%
Oil and condensate (thousand barrels)		220		186	18	%
Total production (Mmcfe)		18,786		14,793	27	%
Revenues
Natural gas	$	128,651	$	109,844	17	%	$	7.37	$	8.03
Oil and condensate		10,854		10,414	4	%		49.30		55.99
Other income		675		1,119	(40	)%
Total revenues		140,180		121,377	15	%		7.46		8.21
Expenses
Operating		18,943		11,607	63	%		1.01		0.78
Taxes other than income		8,869		7,412	20	%		0.47		0.50
General and administrative		6,902		5,468	26	%		0.37		0.37
Production costs		34,714		24,487	42	%		1.85		1.66
Exploration		10,737		13,401	(20	)%		0.57		0.91
Depreciation, depletion and amortization		36,476		25,390	44	%		1.94		1.72
Total expenses		81,927		63,278	29	%		4.36		4.28
Operating income	$	58,253	$	58,099	0	%	$	3.10	$	3.93

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

Production. Approximately 93% of production in the six months ended June 30, 2007 and 2006 was natural gas. Total production increased by 27% percent to 18.8 Bcfe in the six months ended June 30, 2007 from 14.8 Bcfe in the same period in 2006. This increase was primarily due to increased natural gas production in the east Texas, Gulf Coast, Mid-Continent and Mississippi regions.

We drilled a total of 145 gross (108.8 net) wells during the six months ended June 30, 2007, including 138 gross (105.8 net) development wells and seven gross (3.0 net) exploratory wells. All wells were successful except two gross (1.6 net) development wells and two gross (1.2 net) exploratory wells.

28

The following table summarizes total natural gas, oil and condensate production and total natural gas, oil and condensate revenues by region:

	Natural Gas, Oil and Condensate Production		Natural Gas, Oil and Condensate Revenues
	Six Months Ended June 30,		Six Months Ended June 30,
Region	2007	2006	2007		2006
	(MMcfe)		(in thousands)
Appalachia	6,049	6,475	$	44,974	$	53,236
Gulf Coast	4,202	3,399		32,854		25,949
Mississippi	3,648	3,088		27,055		25,190
East Texas	3,215	1,725		24,437		15,311
Mid-Continent	1,672	106		10,185		572
Total	18,786	14,793	$	139,505	$	120,258

Revenues. Increased natural gas production resulted in a $30.4 million increase in natural gas revenues, which was partially offset by an $11.6 million decrease in natural gas revenues resulting from decreased realized prices for natural gas. The average realized price received for natural gas during the six months ended June 30, 2007 was $7.37 per Mcf compared to $8.03 per Mcf during the same period in 2006, an 8% decrease. Increased oil and condensate production was the primary reason for the $0.4 million increase in oil and condensate revenues.

Natural gas, oil and condensate revenues are derived from the sale of our oil and gas production, which is net of the effects of the settlement of derivative contracts that followed hedge accounting. Settlement of our derivative contracts that do not follow hedge accounting has no effect on our reported revenues. Beginning in May 2006, none of our derivative contracts follow hedge accounting. Our revenues may vary significantly from period to period as a result of changes in commodity prices or production volumes. As part of our risk management strategy, we use derivative financial instruments to hedge natural gas and, to a lesser extent, oil prices. The use of this risk management strategy has resulted in lower price realizations compared to physical sale prices in the last several years.

The following table shows a summary of the effects of derivative activities on revenues and realized prices for the six months ended June 30, 2007 and 2006:

	Six Months Ended June 30,
	2007			2006			2007			2006
	(in thousands)						(per Mcf)
Natural gas revenue, as reported	$	128,651		$	109,844		$	7.37		$	8.03
Derivatives (gains) losses included in natural gas revenues		(482	)		417			(0.03	)		0.03
Natural gas revenue before impact of derivatives		128,169			110,261			7.34			8.06
Cash settlements on natural gas derivatives		5,873			2,033			0.34			0.15
Natural gas revenues, adjusted for derivatives	$	134,042		$	112,294		$	7.67		$	8.21
							(per Bbl)
Crude oil revenue, as reported	$	10,854		$	10,414		$	49.30		$	55.99
Derivatives (gains) losses included in oil and condensate revenues		256			230			1.16			1.24
Oil and condensate revenue before impact of derivatives		11,110			10,644			50.46			57.23
Cash settlements on crude oil derivatives		87			(190	)		0.40			(1.02	)
Oil and condensate revenues, adjusted for derivatives	$	11,197		$	10,454		$	50.86		$	56.20

29

Expenses. Aggregate operating costs and expenses in the six months ended June 30, 2007 increased primarily due to increases in operating expenses, taxes other than income, general and administrative expenses and DD&A expenses, partially offset by a decrease in exploration expenses.

Operating expenses increased from $11.6 million in the six months ended June 30, 2006 to $18.9 million in the same period in 2007, or 63%, primarily due to increased repair and maintenance charges, gathering, transportation and processing charges and compressor rental charges resulting from increased production in the east Texas and Mississippi regions. The acquisition of the Mid-Continent assets and the related well operating costs also contributed to the increase in the operating expenses.

Taxes other than income increased from $7.4 million in the six months ended June 30, 2006 to $8.9 million in the same period in 2007. This increase was primarily due to an increase in production, partially offset by a severance tax refund in the Cotton Valley region.

General and administrative expenses increased from $5.5 million in the six months ended June 30, 2006 to $6.9 million in the same period in 2007, or 26%, primarily due to payroll costs as a result of an additional office in our Mid-Continent region and new personnel.

Exploration expenses for the six months ended June 30, 2007 and 2006 consisted of the following:

	Six Months Ended June 30,
	2007		2006
	(in thousands)
Dry hole costs	$	3,727	$	5,836
Seismic		1,582		3,639
Unproved leasehold		4,737		2,508
Other		691		1,418
Total	$	10,737	$	13,401

Exploration expenses decreased primarily due to decreases in dry hole costs, seismic and other costs, partially offset by an increase in unproved leasehold expenses. Dry hole costs decreased primarily due to the write-off of five wells in the Gulf Coast region in the six months ended June 30, 2007 compared to the write-off of two wells in the Gulf Coast region, one well in the Appalachian region and one well in the East Texas region in the same period of 2006. The timing of seismic data purchases caused seismic expenses to decrease. The increase in unproved leasehold expenses was due to the amortization of unproved properties acquired over the past year. The decrease in other costs was primarily due to delay rentals incurred. Delay rentals are cash payments made to the mineral rights owner (lessor) by us for the privilege of postponing the commencement of drilling operations on the leased property beyond the initial term of the lease.

Oil and gas DD&A expenses increased due to the 27% increase in equivalent production and as a result of higher depletion rates. The average depletion rate increased from $1.72 per Mcfe in the six months ended June 30, 2006 to $1.94 per Mcfe in the six months ended June 30, 2007 as a result of a greater percentage of production coming from our 2006 acquisition of Mid-Continent properties and our relatively higher cost horizontal CBM and Cotton Valley wells.

30

PVR Coal Segment

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006

The following table sets forth a summary of certain financial and other data for PVR’s coal segment and the percentage change for the periods indicated:

	Three Months Ended June 30,				% Change
	2007		2006
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	24,029	$	24,254	(1	)%
Coal services		2,092		1,404	49	%
Other		2,289		2,240	2	%
Total revenues		28,410		27,898	2	%
Expenses
Operating		2,514		1,253	101	%
Taxes other than income		267		101	164	%
General and administrative		2,743		2,468	11	%
Depreciation, depletion and amortization		5,320		4,747	12	%
Total expenses		10,844		8,569	27	%
Operating income	$	17,566	$	19,329	(9	)%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,060		7,966	1	%
Average royalty per ton ($/ton)	$	2.98	$	3.04	(2	)%

Revenues. Coal royalty revenues remained relatively constant from the three months ended June 30, 2006 to the same period in 2007. Tons produced by PVR’s lessees increased from 8.0 million tons in the three months ended June 30, 2006 to 8.1 million tons in the same period of 2007, and PVR’s average gross royalty per ton decreased from $3.04 for the three months ended June 30, 2006 to $2.98 for the same period in 2007. The decrease in average royalty per ton was primarily due to a decrease in the price of coal. 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 occurs as its lessees’ contracts are renegotiated. The coal reserves in West Virginia that PVR acquired in May 2006 resulted in $1.3 million of coal royalty revenues in the three months ended June 30, 2007.

Coal services revenues increased to $2.1 million for the three months ended June 30, 2007 from $1.4 million for the same period in 2006, or 49%, primarily due to the completed construction of a coal services facility in Knott County, Kentucky, which began operations in October 2006. This facility contributed $0.4 million to coal services revenues in the three months ended June 30, 2007. We believe these types of fee-based infrastructure assets provide good investment and cash flow opportunities, and we continue to look for additional investments of this type, as well as other primarily fee-based assets.

31

The following table summarizes coal production and coal royalty revenues by property:

	Coal Production		Coal Royalty Revenues
	Three Months Ended June 30		Three Months Ended June 30
Property	2007	2006	2007		2006
	(tons in thousands)		(in thousands)
Central Appalachia	5,018	5,041	$	18,274	$	19,253
Northern Appalachia	1,080	1,340		1,654		1,985
Illinois Basin	502	625		1,180		1,211
San Juan Basin	1,460	960		2,921		1,805
Total	8,060	7,966	$	24,029	$	24,254

Expenses. Operating expenses increased to $2.5 million for the three months ended June 30, 2007 from $1.3 million for the same period in 2006, or 101%, primarily due to increased production on PVR’s subleased Central Appalachian properties. Fluctuations in production on subleased properties have a direct impact on royalty expense. General and administrative expenses increased by 11% to $2.7 million primarily due to increased payroll costs. DD&A expense increased by 12% to $5.3 million primarily due to the completed construction of a coal services facility in Knott County, Kentucky, which began operations in October 2006.

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

The following table sets forth a summary of certain financial and other data for PVR’s coal segment and the percentage change for the periods indicated:

	Six Months Ended June 30,				% Change
	2007		2006
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	49,029	$	46,676	5	%
Coal services		3,693		2,830	30	%
Other		4,172		3,720	12	%
Total revenues		56,894		53,226	7	%
Expenses
Operating		4,669		2,221	110	%
Taxes other than income		590		411	44	%
General and administrative		5,359		4,699	14	%
Depreciation, depletion and amortization		10,810		9,499	14	%
Total expenses		21,428		16,830	27	%
Operating income	$	35,466	$	36,396	(3	)%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		16,344		15,686	4	%
Average royalty per ton ($/ton)	$	3.00	$	2.98	1	%

Revenues. Coal royalty revenues increased to $49.0 million for the six months ended June 30, 2007 from $46.7 million for the same period in 2006, or 5%, due to an increase in production by PVR’s lessees and an increase in average royalty per ton. Tons produced by PVR’s lessees increased from 15.7 million tons in the six months ended June 30, 2006 to 16.3 million tons in the same period in 2007, and PVR’s average gross royalty per ton increased from $2.98 for the six months ended June 30, 2006 to $3.00 for the same period in 2007. The increase in the average royalty per ton was primarily due to an increase in the price of coal . 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

32

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 coal reserves in West Virginia that PVR acquired in May 2006 resulted in $2.8 million of coal royalty revenues in the six months ended June 30, 2007.

Coal services revenues increased to $3.7 million for the six months ended June 30, 2007 from $2.8 million for the same period in 2006, or 30%, primarily due to the completed construction of a coal services facility in Knott County, Kentucky, which began operations in October 2006. This facility contributed $0.8 million to coal services revenues in the six months ended June 30, 2007. We believe these types of fee-based infrastructure assets provide good investment and cash flow opportunities, and we continue to look for additional investments of this type, as well as other primarily fee-based assets.

The following table summarizes coal production and coal royalty revenues by property:

	Coal Production		Coal Royalty Revenues
	Six Months Ended June 30		Six Months Ended June 30
Property	2007	2006	2007		2006
	(tons in thousands)		(in thousands)
Central Appalachia	9,975	9,439	$	37,184	$	35,921
Northern Appalachia	2,450	2,624		3,757		3,853
Illinois Basin	1,120	1,341		2,487		2,611
San Juan Basin	2,799	2,282		5,601		4,291
Total	16,344	15,686	$	49,029	$	46,676

Expenses. Operating expenses increased to $4.7 million for the six months ended June 30, 2007 from $2.2 million for the same period in 2006, or 110%, primarily due to production on PVR’s subleased Central Appalachian properties. Fluctuations in production on subleased properties have a direct impact on royalty expense. General and administrative expenses increased by 14% to $5.4 million primarily due to increased payroll costs. DD&A expense increased by 14% to $10.8 million primarily due to the completed construction of a coal services facility in Knott County, Kentucky, which began operations in October 2006.

33

PVR Natural Gas Midstream Segment

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006

The following table sets forth a summary of certain financial and other data for PVR’s natural gas midstream segment and the percentage change for the periods indicated:

	Three Months Ended June 30,
	2007		2006		% Change
	(in thousands)
Financial Highlights
Revenues
Residue gas	$	69,383	$	58,158	19	%
Natural gas liquids		41,162		34,191	20	%
Condensate		3,158		2,570	23	%
Gathering and transportation fees		704		431	63	%
Total natural gas midstream revenues		114,407		95,350	20	%
Producer services		1,327		215	517	%
Total revenues		115,734		95,565	21	%
Expenses
Cost of midstream gas purchased		95,077		75,692	26	%
Operating		2,983		2,842	5	%
Taxes other than income		336		337	(0	)%
General and administrative		3,020		2,665	13	%
Depreciation and amortization		4,502		4,069	11	%
Total operating expenses		105,918		85,605	24	%
Operating income	$	9,816	$	9,960	(1	)%
Operating Statistics
System throughput volumes (MMcf)		16,870		14,466	17	%
Gross processing margin	$	19,330	$	19,658	(2	)%

Revenues. Natural gas midstream revenues increased to $114.4 million for the three months ended June 30, 2007 from $95.4 million for the same period in 2006, or 20%, due to a more favorable pricing environment combined with increased system throughput volumes. 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, gathering and other fees primarily from natural gas volumes connected to our gas processing plants and the purchase and resale of natural gas not connected to our gathering systems and processing plants.

Producer services revenues increased by $1.1 million during the three months ended June 30, 2007 as compared to the same period in 2006 due to an increase in marketed gas volumes.

Expenses. Operating costs and expenses primarily consisted of the cost of midstream gas purchased and also included operating expenses, taxes other than income, general and administrative expenses and depreciation and amortization.

Cost of midstream gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage of proceeds and keep-whole contracts. Cost of midstream gas purchased increased primarily due to increased system throughput volumes.

The gross processing margin for PVR’s natural gas midstream operations remained relatively constant from the three months ended June 30, 2006 to the same period in 2007. System throughput volumes at PVR’s gas processing plants and gathering systems increased to 185 MMcfd for the three months ended June 30, 2007 from 159 MMcfd

34

for the same period in 2006, an increase of 26 MMcfd, or 16%, primarily due to higher average daily system throughput volumes resulting from pipeline acquisitions, successful drilling of local producers and expansion of PVR’s current facilities. PVR’s natural gas midstream business generates revenues primarily from gas purchase and processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. During the three months ended June 30, 2007, PVR’s natural gas midstream business generated a majority of its gross margin from contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased.

The following table shows a summary of the effects of derivative activities on natural gas midstream processing margin:

	Three Months Ended June 30,
	2007			2006
	(in thousands)
Gross processing margin, as reported	$	19,330		$	19,658
Derivatives (gains) losses included in gross processing margin		1,285			711
Gross processing margin before impact of derivatives		20,615			20,369
Cash settlements on derivatives		(2,189	)		(5,139	)
Gross processing margin, adjusted for derivatives	$	18,426		$	15,230

Depreciation and amortization expenses increased primarily due to increased expenses associated with the pipeline obtained as part of a June 2006 acquisition.

35

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

The following table sets forth a summary of certain financial and other data for PVR’s natural gas midstream segment and the percentage change for the periods indicated:

	Six Months Ended June 30,
	2007		2006		% Change
	(in thousands)
Financial Highlights
Revenues
Residue gas	$	129,064	$	136,688	(6	)%
Natural gas liquids		73,150		62,228	18	%
Condensate		6,073		4,842	25	%
Gathering and transportation fees		1,438		773	86	%
Total natural gas midstream revenues		209,725		204,531	3	%
Producer services		1,725		870	98	%
Total revenues		211,450		205,401	3	%
Expenses
Cost of midstream gas purchased		174,808		174,343	0	%
Operating		6,342		5,351	19	%
Taxes other than income		856		725	18	%
General and administrative		6,043		5,705	6	%
Depreciation and amortization		9,145		8,138	12	%
Total operating expenses		197,194		194,262	2	%
Operating income	$	14,256	$	11,139	28	%
Operating Statistics
System throughput volumes (MMcf)		32,919		28,648	15	%
Gross processing margin	$	34,917	$	30,188	16	%

Revenues. Natural gas midstream revenues increased to $209.7 million for the six months ended June 30, 2007 from $204.5 million for the same period in 2006, or 3%, due to a more favorable pricing environment combined with increased system throughput volumes. 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, gathering and other fees primarily from natural gas volumes connected to our gas processing plants and the purchase and resale of natural gas not connected to our gathering systems and processing plants.

Expenses. Operating costs and expenses primarily consisted of the cost of midstream gas purchased and also included operating expenses, taxes other than income, general and administrative expenses and depreciation and amortization.

Cost of midstream gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage of proceeds and keep-whole contracts. Cost of midstream gas purchased increased slightly primarily due to an increase in system throughput volumes. This increase in system throughput volumes was partially offset by a $4.6 million non-cash charge recorded to reserves in the six months ended June 30, 2006 for amounts related to balances assumed as part of the acquisition of our natural gas midstream business in 2005.

The gross processing margin for PVR’s natural gas midstream operations increased 16%, from $30.2 million in the six months ended June 30, 2006 to $34.9 million in the six months ended June 30, 2007. This increase was

36

due primarily to a more favorable pricing environment in the six months ended 2007 compared to the same period in 2006. System throughput volumes at PVR’s gas processing plants and gathering systems increased to 182 MMcfd for the six months ended June 30, 2007 from 158 in the same period in 2006, an increase of 24 MMcfd, or 15%, primarily due to pipeline acquisitions, successful drilling of local producers and expansion of our current facilities. PVR’s natural gas midstream business generates revenues primarily from gas purchase and processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. During the six months ended June 30, 2007, PVR’s natural gas midstream business generated a majority of its gross margin from contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased.

The following table shows a summary of the effects of derivative activities on natural gas midstream processing margin:

	Six Months Ended June 30,
	2007			2006
	(in thousands)
Gross processing margin, as reported	$	34,917		$	30,188
Derivatives (gains) losses included in gross processing margin		2,128			450
Gross processing margin before impact of derivatives		37,045			30,638
Cash settlements on derivatives		(4,261	)		(8,061	)
Gross processing margin, adjusted for derivatives	$	32,784		$	22,577

Depreciation and amortization expenses increased primarily due to increased expenses associated with the pipeline obtained as part of a June 2006 acquisition.

Corporate and Other

Corporate and other results primarily consist of oversight and administrative functions.

Expenses. Corporate operating expenses increased by $2.3 million, or 61%, from $3.8 million in the three months ended June 30, 2006 to $6.1 million in the three months ended June 30, 2007, and by $5.4 million, or 76%, from $7.1 million in the six months ended June 30, 2006 to $12.5 million in the six months ended June 30, 2007. These increases were primarily related to increased general and administrative expenses, which included higher payroll costs as a result of wages increases, new personnel and the granting of stock-based compensation in 2007.

Interest Expense. Interest expense increased from $5.4 million in the three months ended June 30, 2006 to $8.3 million in the same period in 2007, or 54%. Interest expense increased from $10.2 million for the six months ended June 30, 2006 to $15.0 million in the same period in 2007, or 48%. The increases in interest expense in both periods were primarily due to interest incurred on additional borrowings under the Revolver to finance the acquisition of our Mid-Continent oil and gas properties, as well as additional drilling and development on our current oil and gas properties, partially offset by a $0.8 million and $1.3 million decrease in PVR’s interest expense for the three months and six months ended June 30, 2007. PVR used the proceeds from the sale of common units and Class B units in December 2006 to pay down $114.6 million of the PVR Revolver. We capitalized interest costs amounting to $1.0 million and $0.5 million for the three months ended June 30, 2007 and 2006, and $1.9 and $0.9 million for the six months ended June 30, 2007 and 2006, because the borrowings funded the preparation of unproved oil and gas properties for their development.

Derivatives. Derivative losses decreased to $0.9 million for the three months ended June 30, 2007 from $6.4 million for the same period in 2006, or 86%. The derivative losses for the three months ended June 30, 2007 consisted of a $6.7 million gain on oil and gas derivatives and a $7.6 million loss on natural gas midstream derivatives. Derivative losses increased to $17.6 million for the six months ended June 30, 2007 from $6.5 million for the same period in 2006, or 169%. The derivative losses for the six months ended June 30, 2007 consisted of a $7.4 million loss on oil and gas derivatives and a $10.2 million loss on natural gas midstream derivatives. The changes in both periods were primarily due to mark-to-market adjustments.

37

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.

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 our control, such as energy costs and inflation or deflation of oil field service costs. Additionally, we perform impairment tests pursuant to Statement of Financial Accounting Standards (“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.

Depreciation and depletion of oil and gas producing properties is determined by the units-of-production method and could change with revisions to estimated proved recoverable reserves.

Coal properties are depleted 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 annually and may result in adjustments to coal reserves and depletion rates that are recognized prospectively.

Oil and Gas Revenues

Revenues associated with sales of natural gas, crude oil, condensate and NGLs are recorded when title passes to the customer. Natural gas sales revenues from properties in which we have an interest with other producers are recognized 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. Any amount received in excess of our share is treated as deferred revenues. If we take less than we are entitled to take, the under-delivery is recorded 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

38

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, accruals for revenues and accounts receivable are made 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. Any differences, which we do not expect to be significant, between the actual amounts ultimately received and the original estimates are recorded in the period they become finalized.

Natural Gas Midstream Revenues

Revenues from the sale of NGLs and residue gas are recognized when the NGLs and residue gas produced at PVR’s gas processing plants are sold. Gathering and transportation revenues are recognized 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, accruals for revenues and accounts receivable and the related cost of midstream gas purchased and accounts payable are made based on estimates of natural gas purchased and NGLs and natural gas sold, and our financial results include estimates of production and revenues for the period of actual production. Any differences, which we do not expect to be significant, between the actual amounts ultimately received or paid and the original estimates are recorded in the period they become finalized.

Coal Royalty Revenues

Coal royalty revenues are recognized 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 revenue information until approximately 30 days following the month of production. Therefore, PVR’s financial results include estimated revenues and accounts receivable for the month of production. Any differences, which we do not expect to be significant, between the actual amounts ultimately received and the original estimates are recorded in the period they become finalized.

Derivative Activities

We and PVR have historically entered into derivative financial instruments that would qualify for hedge accounting under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Hedge accounting affects the timing of revenue recognition and cost of midstream gas purchased in our consolidated statements of income, as a majority of the gain or loss from a contract qualifying as a cash flow hedge is deferred until the related hedged transaction settles. Because during the first quarter of 2006 a large portion of our natural gas derivatives and NGL derivatives no longer qualified for hedge accounting and to increase clarity in our consolidated financial statements, we elected to discontinue hedge accounting prospectively for our remaining and future commodity derivatives beginning May 1, 2006. Consequently, from that date forward, we began recognizing mark-to-market gains and losses 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 could experience significant changes in the estimate of derivative gain or loss recognized in revenues and cost of midstream gas purchased due to swings in the value of these contracts. These fluctuations could be significant in a volatile pricing environment.

The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income (“AOCI”), will be reported in earnings through 2008 as the original hedged transactions settle. In the oil and gas segment, we expect to recognize hedging losses of $0.5 million for the remainder of 2007 for amounts currently included in AOCI. In the PVR natural gas midstream segment, PVR expects to recognize hedging losses of $2.5 million for the remainder of 2007 and $5.5 million for 2008 for amounts currently included in AOCI. This change in reporting will have no impact on our reported cash flows, although future results of operations will be affected by the potential volatility of mark-to-market gains and losses which fluctuate with changes in NGL, oil and gas prices.

39

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 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, 2007, the costs attributable to unproved properties were approximately $106.3 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 relatively 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.

Environmental Matters

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

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

As of June 30, 2007, PVR’s environmental liabilities included $1.5 million, which represents PVR’s best estimate of its liabilities as of that date related to its coal 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.

40

To dispose of mining overburden generated by their surface mining activities, PVR’s lessees need to obtain government approvals, including Federal Clean Water Act (“CWA”) Section 404 permits to construct valley fills and sediment control ponds. Two CWA Section 404 permits issued to Alex Energy, Inc. (“Alex Energy”), one of PVR’s surface coal mine lessees in West Virginia, were recently challenged in a lawsuit, Ohio Valley Environmental Coalition (“OVEC”) v. United States Army Corps of Engineers. On March 23, 2007, the U.S. District Court for the Southern District of West Virginia rescinded and remanded the permit authorizing several valley fills and sediment ponds that may be constructed at the Republic No. 2 Mine and enjoined Alex Energy from taking any further actions under this permit. The district court has yet to rule on whether the other CWA Section 404 permit for the construction of valley fills and associated sediment ponds at the Republic No. 1 Mine was also invalidly issued. Although portions of the Republic No. 2 Mine continue to operate based on a subsequent order allowing the mine to fully utilize and complete some of its partially constructed valley fills, the construction of new valley fills at other portions of the Republic No. 2 Mine is enjoined pending a final outcome of this litigation. On June 13, 2007, the district court also issued a declaratory judgment indicating that the mining companies subject to the OVEC decision may also be required to obtain new, separate CWA Section 402 permit authorizations for the stream segments located between the toes of their valley fills and their respective sediment pond embankments.

The district court’s March 23, 2007 decision is currently on appeal to the U.S. Court of Appeals for the Fourth Circuit. While PVR is still reviewing the district court’s ruling, its lessees may not be able to obtain or may experience delays in securing additional CWA Section 404 permits for surface mining operations. Unless the OVEC decision is overturned or further limited in subsequent proceedings, the ruling and its collateral consequences could ultimately have an adverse effect on PVR’s coal royalty revenues.

Recent Accounting Pronouncements

See Note 2 in the Notes to Consolidated Financial Statements for a description of recent accounting pronouncements.

Forward-Looking Statements

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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, crude oil, NGLs and coal;

• the cost of finding and successfully developing oil and gas reserves;

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

• energy prices generally and specifically, the price of natural gas, crude oil, NGLs and coal;

• the relationship between natural gas and NGL prices;

• the price of coal and its comparison to the price of natural gas and crude oil;

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

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

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

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

• non-performance by third party operators in wells in which we own an interest;

• 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 recoverable proved oil and gas reserves and coal reserves;

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

• hazards or operating risks incidental to our business and to PVR’s coal or midstream business;

• PVR’s ability to successfully manage its relatively new natural gas midstream business;

• PVR’s ability to acquire new coal reserves or natural gas midstream assets on satisfactory terms;

• the price for which PVR can acquire coal reserves;

• PVR’s ability to continually find and contract for new sources of natural gas supply for its midstream business;

• PVR’s ability to retain existing or acquire new natural gas midstream customers;

41

• PVR’s ability to lease new and existing coal reserves;

• the ability of PVR’s lessees to produce sufficient quantities of coal on an economic basis from PVR’s reserves;

• the ability of PVR’s lessees to obtain favorable contracts for coal produced from its reserves;

• PVR’s exposure to the credit risk of its coal lessees and natural gas midstream customers;

• hazards or operating risks incidental to natural gas midstream operations;

• unanticipated geological problems;

• the dependence of PVR’s natural gas midstream business on having connections to third party pipelines;

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

• the failure of equipment or processes to operate in accordance with specifications or expectations;

• the failure of PVR’s infrastructure and its lessees’ mining equipment or processes to operate in accordance with specifications or expectations;

• delays in anticipated start-up dates of our oil and natural gas production and PVR’s lessees’ mining operations and related coal infrastructure projects;

• 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;

• the risks associated with having or not having price risk management programs;

• labor relations and costs;

• 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 and interest rates) and political conditions (including the impact of potential terrorist attacks);

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

• PVR’s ability to expand its natural gas midstream business by constructing new gathering systems, pipelines and processing facilities on an economic basis and in a timely manner;

• coal handling joint venture operations;

• changes in financial market conditions;

• 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 year ended December 31, 2006.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2006. 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 NGL, crude oil, natural gas and coal price risks and interest rate risk.

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

42

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 value of our price risk management assets is significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

For the six months ended June 30, 2007, we reported a net $17.6 million derivative loss for mark-to-market adjustments. Because during the first quarter of 2006 a large portion of our natural gas derivatives and NGL derivatives no longer qualified for hedge accounting and to increase clarity in our consolidated financial statements, we elected to discontinue hedge accounting prospectively for our remaining and future commodity derivatives beginning May 1, 2006. Consequently, from that date forward, we began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (shareholders’ equity). The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in future earnings through 2008 as the original hedged transactions settle. We expect to recognize hedging losses of $0.5 million for the remainder of 2007 related to oil and gas segment transactions. PVR expects to recognize hedging losses of $2.5 million for the remainder of 2007 and $5.5 million for 2008 related to PVR natural gas midstream segment transactions. The discontinuation of hedge accounting will have no impact on our reported cash flows, although future results of operations will be affected by the potential volatility of mark-to-market gains and losses which fluctuate with changes in NGL, oil and gas prices. See the discussion and tables in Note 6 in the Notes to Consolidated Financial Statements for a description of our derivative program.

43

The following tables list our open mark-to-market derivative agreements and their fair values as of June 30, 2007:

Oil and Gas Segment Derivatives

	Average Volume Per Day	Weighted Average Price						Estimated Fair Value
		Additional Put Option		Floor		Ceiling
	(in Mmbtus)	(per Mmbtu)						(in thousands)
Natural Gas Costless Collars
Third Quarter 2007	15,000			$	7.33	$	12.93		947
Fourth Quarter 2007	11,685			$	8.28	$	15.78		1,375
First Quarter 2008	10,000			$	9.00	$	17.95		1,094
	(in Mmbtus)	(per Mmbtu)
Natural Gas Three-way Collars
Third Quarter 2007	33,000	$	5.00	$	7.39	$	9.05		1,973
Fourth Quarter 2007	26,370	$	5.25	$	7.74	$	11.14		1,616
First Quarter 2008	22,500	$	5.44	$	8.00	$	12.64		522
Second Quarter 2008	22,500	$	5.00	$	7.11	$	9.09		(398	)
Third Quarter 2008	22,500	$	5.00	$	7.11	$	9.09		(400	)
Fourth Quarter 2008	15,870	$	5.21	$	7.58	$	10.73		(139	)
First Quarter 2009	10,000	$	5.50	$	8.00	$	12.60		(76	)
	(in barrels)	(per barrel)
Crude Oil Costless Collars
Third Quarter 2007	200			$	60.00	$	72.20		(30	)
Fourth Quarter 2007	200			$	60.00	$	72.20		(57	)
	(in barrels)	(per barrel)
Crude Oil Swaps
Third Quarter 2007	300			$	69.00				(54	)
Fourth Quarter 2007	300			$	69.00				(68	)
Oil and gas segment commodity derivatives—net asset								$	6,307

44

PVR Midstream Segment Derivatives

	Average Volume Per Day	Weighted Average Price		Weighted Average Collars				Estimated Fair Value
				Put		Call
	(in gallons)	(per gallon)						(in thousands)
Ethane Swaps
Third Quarter 2007 through Fourth Quarter 2007	34,440	$	0.5050					$	(1,421	)
First Quarter 2008 through Fourth Quarter 2008	34,440	$	0.4700						(2,344	)
	(in gallons)	(per gallon)
Propane Swaps
Third Quarter 2007 through Fourth Quarter 2007	26,040	$	0.7550						(1,952	)
First Quarter 2008 through Fourth Quarter 2008	26,040	$	0.7175						(3,820	)
	(in barrels)	(per barrel)
Crude Oil Swaps
Third Quarter 2007 through Fourth Quarter 2007	560	$	50.80						(2,071	)
First Quarter 2008 through Fourth Quarter 2008	560	$	49.27						(4,473	)
	(in MMbtu)	(per MMbtu)
Natural Gas Swaps
Third Quarter 2007 through Fourth Quarter 2008	4,000	$	6.97						2,258
	(in gallons / in barrels)	(per gallon / per barrel)
Natural Gasoline Swap/Crude Oil Swap
Third Quarter 2007 through Fourth Quarter 2007	23,520 / 560	$	1.265 / 57.12						(294	)
	(in gallons)			(per gallon)
Ethane Collar
Third Quarter 2007 through Fourth Quarter 2007	5,000			$	0.6100	$	0.7125		(52	)
	(in gallons)			(per gallon)
Propane Collar
Third Quarter 2007 through Fourth Quarter 2007	9,000			$	1.0300	$	1.1640		(72	)
	(in gallons)			(per gallon)
Natural Gasoline Collar
Third Quarter 2007 through Fourth Quarter 2008	6,300			$	1.4800	$	1.6465		(380	)
	(in barrels)			(per barrel)
Crude Oil Collar
First Quarter 2008 through Fourth Quarter 2008	400			$	65.00	$	75.25		(226	)
	(in MMbtu)	(per MMbtu)
Frac Spread
Third Quarter 2007 through Fourth Quarter 2007	7,128	$	4.299						(2,196	)
Settlements to be paid in subsequent period									(1,026	)
Natural gas midstream segment commodity derivatives—net liability								$	(18,069	)

Interest Rate Risk

As of June 30, 2007, we had $328.5 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Revolver Swaps in August 2006 to effectively convert the interest rate on $50 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. The interest rate swaps are accounted for as cash flow hedges in accordance with SFAS No. 133. A 1% increase in short-term interest rates on the floating rate debt outstanding under the Revolver (net of amounts fixed through hedging transactions) at June 30, 2007 would cost us approximately $2.8 million in additional interest expense.

        As of June 30, 2007, PVR had $205.2 million of outstanding indebtedness under the PVR Revolver, which carries a variable interest rate throughout its term. PVR entered into the PVR Revolver Swaps in September 2005 to effectively convert the interest rate on $60 million of the amount outstanding under the PVR Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.22% 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, 2007 would cost PVR approximately $1.5 million in additional interest expense.

Ite m 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, 2007. Our disclosure controls and

45

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, 2007, such disclosure controls and procedures were effective.

(b) Changes in Internal Control over Financial Reporting

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

In July 2007, we migrated our financial accounting and reporting system to a new enterprise resource planning (“ERP”) system. In connection with the implementation of our ERP system, we could experience control and implementation issues impacting our financial reporting. In the event that the preceding occurs, we may implement additional manual procedures to address these financial reporting issues. We will continue to monitor and test the new system as part of our evaluation of our internal control over financial reporting for 2007.

46

PART II. OTHER INFORMATION

Items 1, 1A, 2, 3 and 5 are not applicable and have been omitted.

Item 4 Submission of Matters to a Vote of Security Holders

Our Annual Meeting of Shareholders was held on May 8, 2007. Two proposals were voted on at the meeting. The results of voting on each proposal are as follows:

Proposal 1: Election of Directors:

	For	Withheld
Edward B. Cloues, II	9,070,005	7,759,405
A. James Dearlove	9,082,545	7,746,865
Robert Garrett	9,080,775	7,748,635
Keith D. Horton	9,081,579	7,747,831
Steven W. Krablin	9,064,137	7,765,273
Marsha R. Perelman	9,070,525	7,758,885
Philippe van Marcke de Lummen	9,072,309	7,757,101
Gary K. Wright	8,375,301	8,454,109

Proposal 2: Amendment and Restatement of the Penn Virginia Corporation Second Amended and Restated 1999 Employee Stock Incentive Plan:

For	Against	Abstain	Broker Non-Vote
12,512,617	2,558,666	351,620	1,406,507

Item 6 Exhibits

12.1	Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.
31.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification Pursuant to 18 U.S.C. Section 1350, 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.

47

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 2, 2007	By:	/s/ Frank A. Pici
			Frank A. Pici
			Executive Vice President and Chief Financial Officer
Date:	August 2, 2007	By:	/s/ Forrest W. McNair
			Forrest W. McNair
			Vice President and Controller

48