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 September 30, 2008

or

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

For the transition period from              to             

Commission File Number: 1-13283

PENN VIRGINIA CORPORATION

(Exact name of registrant as specified in its charter)

Virginia	23-1184320
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
THREE RADNOR CORPORATE CENTER, SUITE 300 100 MATSONFORD ROAD RADNOR, PA 19087
(Address of principal executive offices) (Zip Code)

(610) 687-8900

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    x  Yes    ¨  No

Indicate by a check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x	Accelerated filer  ¨
Non-accelerated filer  ¨	(Do not check if a smaller reporting company) Smaller reporting company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes    x  No

As of November 5, 2008, 41,841,263 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

INDEX

		Page
PART I.	Financial Information
Item 1.	Financial Statements
	Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2008 and 2007	1
	Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007	2
	Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2008 and 2007	3
	Notes to Consolidated Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 4.	Controls and Procedures	58
PART II.	Other Information
Item 1.	Legal Proceedings	59
Item 1A.	Risk Factors	59
Item 6.	Exhibits	60

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 September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Revenues
Natural gas	$	101,911		$	65,310		$	295,636		$	193,961
Crude oil		13,764			6,299			37,442			14,985
Natural gas liquids		10,481			1,290			18,887			3,458
Natural gas midstream		184,914			100,370			494,260			310,095
Coal royalties		33,308			24,426			88,911			73,455
Gain on the sale of property and equipment		31,279			12,312			31,335			12,436
Other		9,955			5,751			28,690			16,036
Total revenues		385,612			215,758			995,161			624,426
Expenses
Cost of midstream gas purchased		155,564			76,192			408,247			251,000
Operating		23,437			17,602			66,653			47,557
Exploration		8,346			12,873			19,765			23,610
Taxes other than income		7,671			5,156			23,325			15,995
General and administrative		18,289			16,439			55,006			46,539
Impairment of oil and gas properties		—			2,405			—			2,405
Depreciation, depletion and amortization		49,978			33,207			133,481			89,823
Total expenses		263,285			163,874			706,477			476,929
Operating income		122,327			51,884			288,684			147,497
Other income (expense)
Interest expense		(11,938	)		(10,843	)		(31,600	)		(25,878	)
Other		(4,088	)		576			(782	)		2,536
Derivatives		125,132			(4,455	)		(4,387	)		(22,068	)
Income before minority interest and income taxes		231,433			37,162			251,915			102,087
Minority interest		28,276			9,135			52,252			27,659
Income tax expense		79,419			10,913			75,792			29,033
Net income	$	123,738		$	17,114		$	123,871		$	45,395
Net income per share, basic	$	2.95		$	0.45		$	2.96		$	1.20
Net income per share, diluted	$	2.90		$	0.45		$	2.94		$	1.19
Weighted average shares outstanding, basic		41,881			37,898			41,715			37,748
Weighted average shares outstanding, diluted		42,544			38,213			42,028			38,045

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

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS — unaudited

(in thousands, except share data)

	September 30, 2008			December 31, 2007
Assets
Current assets
Cash and cash equivalents	$	19,007		$	34,527
Accounts receivable		191,729			179,120
Deferred income taxes		2,002			16,273
Derivative assets		18,197			5,683
Other		20,238			8,469
Total current assets		251,173			244,072
Property and equipment
Oil and gas properties (successful efforts method)		1,963,136			1,525,728
Other property and equipment		1,051,126			859,380
		3,014,262			2,385,108
Accumulated depreciation, depletion and amortization		(614,808	)		(486,094	)
Net property and equipment		2,399,454			1,899,014
Equity investments		78,634			25,640
Goodwill		31,768			7,718
Intangibles, net		94,623			28,938
Derivative assets		6,019			310
Other assets		48,950			47,769
Total assets	$	2,910,621		$	2,253,461
Liabilities and Shareholders’ Equity
Current liabilities
Short-term borrowings	$	46,431		$	12,561
Accounts payable and accrued liabilities		209,674			205,127
Derivative liabilities		17,959			43,048
Income taxes payable		11,426			1,163
Total current liabilities		285,490			261,899
Other liabilities		55,761			54,169
Derivative liabilities		4,127			3,030
Deferred income taxes		267,187			193,950
Long-term debt of the Company		410,000			352,000
Long-term debt of PVR		558,100			399,153
Minority interests of subsidiaries		309,191			179,162
Shareholders’ equity
Preferred stock of $100 par value — 100,000 shares authorized; none issued		—			—
Common stock of $0.01 par value — 64,000,000 shares authorized; 41,870,477 and 41,408,497 shares issued and outstanding at September 30, 2008 and December 31, 2007		230			225
Paid-in capital		579,327			487,606
Retained earnings		449,057			332,223
Accumulated other comprehensive loss		(5,220	)		(7,936	)
Treasury stock — 90,308 and 77,924 shares common stock, at cost, on September 30, 2008 and December 31, 2007		(2,629	)		(2,020	)
Total shareholders’ equity		1,020,765			810,098
Total liabilities and shareholders’ equity	$	2,910,621		$	2,253,461

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

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS — unaudited

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Cash flows from operating activities
Net income	$	123,738		$	17,114		$	123,871		$	45,395
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		49,978			33,207			133,481			89,823
Derivative contracts:
Total derivative losses (gains)		(123,628	)		6,053			8,516			25,569
Cash received (paid) to settle derivatives		(19,755	)		586			(46,740	)		2,281
Deferred income taxes		62,050			9,218			61,545			21,902
Minority interest		28,276			9,135			52,252			27,659
Gain on the sale of property and equipment		(31,279	)		(12,312	)		(31,335	)		(12,436	)
Impairment of oil and gas properties		—			2,405			—			2,405
Dry hole and unproved leasehold expense		5,520			11,991			14,992			20,707
Other		2,622			1,523			1,504			2,918
Changes in operating assets and liabilities		(5,727	)		(2,736	)		(41,399	)		(17,242	)
Net cash provided by operating activities		91,795			76,184			276,687			208,981
Cash flows from investing activities
Acquisitions		(162,078	)		(162,794	)		(278,185	)		(239,018	)
Additions to property and equipment		(162,857	)		(109,685	)		(392,031	)		(308,987	)
Other		33,215			29,142			33,954			29,385
Net cash used in investing activities		(291,720	)		(243,337	)		(636,262	)		(518,620	)
Cash flows from financing activities
Dividends paid		(2,351	)		(2,130	)		(7,037	)		(6,370	)
Distributions paid to minority interest holders		(17,917	)		(12,937	)		(45,829	)		(36,402	)
Borrowings from bank indebtedness		46,431			—			46,431			—
Proceeds from Company borrowings		38,000			113,000			121,000			220,500
Repayments of Company borrowings		(63,000	)		(27,000	)		(63,000	)		(27,000	)
Proceeds from PVR borrowings		242,000			107,000			366,800			169,000
Repayments of PVR borrowings		(65,400	)		(18,000	)		(220,800	)		(23,000	)
Net proceeds from issuance of PVR partners’ capital		—			—			138,015			—
Other		(2,311	)		(188	)		8,475			7,376
Net cash provided by financing activities		175,452			159,745			344,055			304,104
Net decrease in cash and cash equivalents		(24,473	)		(7,408	)		(15,520	)		(5,535	)
Cash and cash equivalents — beginning of period		43,480			22,211			34,527			20,338
Cash and cash equivalents — end of period	$	19,007		$	14,803		$	19,007		$	14,803
Supplemental disclosures:
Cash paid for:
Interest (net of amounts capitalized)	$	8,599		$	13,630		$	26,490		$	28,397
Income taxes	$	2,791		$	162		$	4,970		$	464
Noncash investing activities: (see Note 4)
Issuance of PVR units for acquisition	$	15,171		$	—		$	15,171		$	—
PVG units given as consideration for acquisition	$	68,021		$	—		$	68,021		$	—
Other liabilities	$	4,673		$	—		$	4,673		$	—

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

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — unaudited

September 30, 2008

1. Nature of Operations

Penn Virginia Corporation (“Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company primarily engaged in the exploration, development and production of natural gas and oil in various onshore U.S. regions including East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast. We also indirectly own partner interests in Penn Virginia Resource Partners, L.P. (“PVR”), a publicly traded limited partnership formed by us in 2001. Our ownership interests in PVR are held principally through our general partner and 77% limited partner interests in Penn Virginia GP Holdings, L.P. (“PVG”), a publicly traded limited partnership formed by us in 2006. As of September 30, 2008, PVG owned an approximately 37% limited partner interest in PVR and 100% of the general partner of PVR, which holds a 2% general partner interest in PVR.

We are engaged in three primary business segments: (i) oil and gas, (ii) coal and natural resource management and (iii) natural gas midstream. We directly operate our oil and gas segment. PVR operates our coal and natural resource management and natural gas midstream segments. Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. Because PVG controls the general partner of PVR, the financial results of PVR are included in PVG’s condensed consolidated financial statements. However, PVG and PVR function with capital structures that are independent of each other and us, with each having publicly traded common units and PVR having its own debt instruments. PVG does not currently have any debt instruments.

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

PVR is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. PVR completed its initial public offering in October 2001. PVG derives its cash flow solely from cash distributions received from PVR. PVG completed its initial public offering in December 2006. PVG’s general partner is an indirect wholly owned subsidiary of ours.

PVR’s coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. PVR also earns revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees.

PVR’s natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. PVR owns and operates natural gas midstream assets located in Oklahoma and Texas. PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

3. Summary of Significant Accounting Policies

Our accounting policies are consistent with those described in our Annual Report on Form 10-K for the year ended December 31, 2007. Please refer to such Form 10-K for a further discussion of those policies.

Basis of Presentation

Our consolidated financial statements include the accounts of Penn Virginia, all of our wholly owned subsidiaries and PVG, of which we indirectly owned the sole general partner and an approximately 77% limited partner interest as of September 30, 2008. PVG GP, LLC, our indirect wholly owned subsidiary, serves as PVG’s sole general partner and controls PVG. Because PVG controls the general partner of PVR, the financial results of PVR are included in PVG’s condensed consolidated financial statements.

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Intercompany balances and transactions have been eliminated in consolidation. Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and Securities and Exchange Commission (“SEC”) regulations. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our consolidated financial statements have been included. 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, 2007. Operating results for the three and nine months ended September 30, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008.

Gain on Sale of Subsidiary Units

We account for PVR equity issuances as sales of minority interest. For each PVR equity issuance, we have calculated a gain under SEC Staff Accounting Bulletin No. 51 (or Topic 5-H), Accounting for Sales of Stock by a Subsidiary (“SAB 51”). SAB 51 provides guidance on accounting for the effect of issuances of a subsidiary’s stock on the parent’s investment in that subsidiary. In some situations, SAB 51 allows registrants to elect an accounting policy of recording gains or losses on issuances of stock by a subsidiary either in income or as a capital transaction. Accordingly, we adopted a policy of recording SAB 51 gains and losses directly to shareholders’ equity. As a result of PVR’s unit offering in May 2008, we recognized gains in consolidated shareholders’ equity totaling $39.7 million. See Note 6 – PVR Unit Offering. In addition, we recognized a $36.8 million gain in consolidated shareholders’ equity, net of the related income taxes of $23.2 million, on the sale of PVG units to PVR. PVR subsequently delivered these units as consideration in its acquisition of Lone Star Gathering L.P. See Note 4 — Acquisitions.

New Accounting Standards

In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51, which mandates that a noncontrolling (minority) interest shall be reported in the consolidated statement of financial position within equity, separately from the parent company’s equity. This statement amends ARB No. 51 and clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity. SFAS No. 160 also requires consolidated net income to include amounts attributable to both the parent and noncontrolling interest and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS No. 160 is effective for fiscal years and interim periods beginning after December 15, 2008. We are currently assessing the impact on our consolidated financial statements of adopting SFAS No. 160 effective January 1, 2009.

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

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

In June 2008, the FASB’s Emerging Issues Task Force (“EITF”) reached a consensus with regard to Issue Number 07-5, Determining Whether an Instrument (or Embedded Feature) is Indexed to an Entity’s Own Stock

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(“EITF 07-5”). Derivative contracts on a company’s own stock may be accounted for as equity instruments, rather than as assets and liabilities, only if the derivative contracts are indexed solely to the company’s stock and can be settled in shares. EITF 07-5 addresses whether provisions that introduce adjustment features (including contingent adjustment features) would preclude treating a derivative contract or an embedded derivative on a company’s own stock as indexed solely to the company’s stock. The EITF reached a consensus that contingent and other adjustment features are consistent with equity indexation if they are based on variables that would be inputs to a “plain vanilla” option or forward pricing model and they do not increase the contract’s exposure to those variables. EITF 07-5 is effective for fiscal years beginning after December 15, 2008. It must initially be applied by recording a cumulative-effect adjustment to opening retained earnings at the date of adoption for the effect of EITF 07-5 on outstanding instruments. We expect no effect on retained earnings as a result of adopting EITF 07-5.

4. Acquisitions

In July 2008, PVR completed the acquisition of substantially all of the assets of Lone Star Gathering, L.P. (“Lone Star Acquisition”). Lone Star’s assets are located in the southern portion of the Fort Worth Basin of North Texas, and include approximately 129 miles of gas gathering pipelines and approximately 240,000 acres dedicated by active producers. The Lone Star Acquisition expands the geographic scope of the PVR natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin. PVR acquired this business for approximately $164.3 million and a liability of $4.7 million, which represents the fair value of a $5.0 million guaranteed payment, plus contingent payments of $30.0 million and $25.0 million. Funding for the acquisition was provided by $80.7 million of borrowings under PVR’s revolving credit facility (the “PVR Revolver”), 2,009,995 PVG common units (which PVR purchased from two of our subsidiaries for $61.8 million) and 542,610 newly issued PVR common units. The contingent payments will be triggered if revenues from certain assets located in a defined geographic area reach certain targets by or before June 30, 2013 and will be funded in cash or PVR common units, at PVR’s election.

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

Based on our analysis of the fair value of these acquisitions, we did not deem either of these acquisitions to be material business combinations to our consolidated financial statements and, therefore, are not disclosing pro forma financial information in accordance with SFAS No. 141.

5. Sale of Oil and Gas Properties

In July 2008, we completed the sale of certain unproved oil and gas acreage in Louisiana for cash proceeds of $32.0 million and recognized a $30.5 million gain on that sale in the third quarter of 2008.

6. PVR Unit Offering

In May 2008, PVR issued to the public 5.15 million common units representing limited partner interests in PVR and received $138.0 million in net proceeds. PVG made contributions to PVR of $2.9 million to maintain its 2% general partner interest. PVR used the net proceeds to repay a portion of its borrowings under the PVR Revolver.

7. Fair Value Measurement of Financial Instruments

We adopted SFAS No. 157, Fair Value Measurements, effective January 1, 2008, for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP SFAS 157-2”), delays the application of SFAS No. 157 for

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nonfinancial assets and nonfinancial liabilities to fiscal years and interim periods beginning after November 15, 2008. Examples of nonfinancial assets for which this FASB Staff Position delays application of SFAS No. 157 include business combinations, impairment and initial recognition of asset retirement obligations. We are currently assessing the impact on the financial statements of adopting FSP SFAS 157-2 effective January 1, 2009.

SFAS No. 157 requires fair value measurements to be classified and disclosed in one of the following three categories:

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

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

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

The following table summarizes the valuation of our financial instruments by the above SFAS No. 157 categories as of September 30, 2008 (in thousands):

Description	Fair Value Measurements, September 30, 2008			Fair Value Measurement at September 30, 2008, Using
				Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Trading securities	$	5,463		$	5,463	$	—		$	—
Interest rate swap liability - current		(2,370	)		—		(2,370	)		—
Interest rate swap liability - noncurrent		(3,105	)		—		(3,105	)		—
Commodity derivative assets - current		18,197			—		18,197			—
Commodity derivative assets - noncurrent		6,019			—		6,019			—
Commodity derivative liability - current		(15,589	)		—		(15,589	)		—
Commodity derivative liability - noncurrent		(1,022	)		—		(1,022	)		—
Total	$	7,593		$	5,463	$	2,130		$	—

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

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

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

• Commodity derivative instruments: Our oil and gas commodity derivatives consist of costless collars, swaps and three-way option derivative contracts, while PVR utilizes costless collars, three-way collars and swap derivative contracts in its natural gas midstream segment. We determine the fair values of our oil and gas commodity derivative agreements based on third-party forward price quotes for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices. PVR determines the fair values of its commodity derivative agreements based on forward price quotes for the respective commodities. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. Each of these is a level 2 input. See Note 8 — Derivative Instruments.

• Interest rate swaps: We have entered into interest rate swap agreements (the “Revolver Swaps”) to establish fixed rates on a portion of the outstanding borrowings under our revolving credit facility (the

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“Revolver”). PVR has entered into interest rate swap agreements (the “PVR Revolver Swaps”) to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. Each of these is a level 2 input. See Note 8 — Derivative Instruments.

8. Derivative Instruments

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

Oil and Gas Segment Commodity Derivatives

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

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

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

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We determined the fair values of our oil and gas derivative agreements based on third-party forward price quotes for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of September 30, 2008, the credit risk of our counterparties and our own credit risk in accordance with SFAS No. 157. The following table sets forth our positions as of September 30, 2008:

	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
Fourth Quarter 2008 (1)	10,000			$	7.50	$	9.10	$	(2,220	)
	(in MMBtus)	(per MMBtu)
Natural Gas Three-Way Collars
Fourth Quarter 2008	67,500	$	5.89	$	8.55	$	11.26		3,050
First Quarter 2009	65,000	$	6.00	$	8.67	$	11.68		5,830
Second Quarter 2009	40,000	$	6.38	$	8.75	$	10.79		3,039
Third Quarter 2009	40,000	$	6.38	$	8.75	$	10.79		2,303
Fourth Quarter 2009	30,000	$	6.83	$	9.50	$	13.60		2,625
First Quarter 2010	30,000	$	6.83	$	9.50	$	13.60		1,862
	(in MMBtus)	(per MMBtu)
Natural Gas Basis Swaps
Fourth Quarter 2008	15,000			$	0.39				179
	(in barrels)	(per barrel)
Crude Oil Three-Way Collars
Fourth Quarter 2008	500	$	80.00	$	110.00	$	179.00		547
First Quarter 2009	500	$	80.00	$	110.00	$	179.00		576
Second Quarter 2009	500	$	80.00	$	110.00	$	179.00		551
Third Quarter 2009	500	$	80.00	$	110.00	$	179.00		517
Fourth Quarter 2009	500	$	80.00	$	110.00	$	179.00		481
Oil and gas segment commodity derivatives - net asset								$	19,340

(1) This position expires in October 2008.

At September 30, 2008, we reported a net derivative asset related to the oil and gas commodity derivatives of $19.3 million. See the Adoption of SFAS No. 161 section below for the impact of the oil and gas commodity derivatives on our consolidated statements of income.

PVR Natural Gas Midstream Segment Commodity Derivatives

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

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

A three-way collar contract consists of a collar contract as described above plus a put option contract sold by PVR with a price below the floor price of the collar. This additional put requires PVR to make a payment to the counterparty if the settlement price for any settlement period is below the put option price. By combining the collar

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contract with the additional put option, PVR is entitled to a net payment equal to the difference between the floor price of the collar contract and the additional put option price if the settlement price is equal to or less than the additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a collar contract only. This strategy enables PVR to increase the floor and the ceiling prices of the collar beyond the range of a traditional collar contract while defraying the associated cost with the sale of the additional put option.

PVR determines the fair values of its derivative agreements based on forward price quotes for the respective commodities as of September 30, 2008, the credit risks of the counterparties and PVR’s own credit risk. The following table sets forth PVR’s positions as of September 30, 2008 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:

	Average Volume Per Day	Weighted Average Price		Weighted Average Price Collars						Fair Value (in thousands)
				Additional Put Option		Put		Call
	(in MMBtu)	(per MMBtu)
Frac Spread
Fourth Quarter 2008	7,824	$	5.02							$	(2,805	)
	(in gallons)	(per gallon)
Ethane Sale Swap
Fourth Quarter 2008	34,440	$	0.4700								(706	)
	(in gallons)	(per gallon)
Propane Sale Swaps
Fourth Quarter 2008	26,040	$	0.7175								(1,751	)
	(in barrels)	(per barrel)
Crude Oil Sale Swaps
Fourth Quarter 2008	560	$	49.27								(2,611	)
	(in gallons)					(per gallon)
Natural Gasoline Collar
Fourth Quarter 2008	6,300					$	1.4800	$	1.6465		(266	)
	(in barrels)					(per barrel)
Crude Oil Collar
Fourth Quarter 2008	400					$	65.00	$	75.25		(936	)
	(in MMBtu)	(per MMBtu)
Natural Gas Sale Swaps
Fourth Quarter 2008	4,000	$	6.97								219
	(in barrels)					(per barrel)
Crude Oil Three-Way Collar
First Quarter 2009 through Fourth Quarter 2009	1,000			$	70.00	$	90.00	$	119.25		(1,128	)
	(in MMBtu)					(per MMBtu)
Frac Spread Collar
First Quarter 2009 through Fourth Quarter 2009	6,000					$	9.09	$	13.94		1,435
Settlements to be paid in subsequent period											(3,186	)
Natural gas midstream segment commodity derivatives - net liability										$	(11,735	)

At September 30, 2008, PVR reported a (i) net derivative liability related to the natural gas midstream segment of $11.7 million and (ii) loss in accumulated other comprehensive income (“AOCI”) of $0.9 million related to derivatives in the natural gas midstream segment, net of the related income tax benefit of $0.5 million, for which PVR discontinued hedge accounting in 2006. The $0.9 million loss, net of the related income tax benefit of $0.5 million, will be recorded in earnings through the end of 2008 as the hedged transactions settle. See the Adoption of SFAS No. 161 section below for the impact of the natural gas midstream commodity derivatives on our consolidated statements of income.

Interest Rate Swaps

We have entered into the Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver until December 2010. The notional amounts of the Revolver Swaps total $50.0 million. We will pay a weighted average fixed rate of 5.34% on the notional amount, and the counterparties will pay a variable rate equal to the three-month London Interbank Offered Rate (“LIBOR”). Settlements on the Revolver Swaps are

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recorded as interest expense. The Revolver Swaps are designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings as interest expense. We reported a (i) derivative liability of $2.1 million at September 30, 2008 and (ii) loss in AOCI of $1.4 million, net of the related income tax expense of $0.7 million, at September 30, 2008 related to the Revolver Swaps. In connection with periodic settlements, we recognized $0.3 million and $0.7 million in net hedging losses on the Revolver Swaps in interest expense for the three and nine months ended September 30, 2008.

Interest Rate Swaps—PVR

PVR has entered into the PVR Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. Until March 2010, the notional amounts of the PVR Revolver Swaps total $210.0 million, or approximately 38% of PVR’s total long term debt outstanding as of September 30, 2008, with PVR paying a weighted average fixed rate of 4.23% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From March 2010 to December 2011, the notional amounts of the Revolver Swaps total $150.0 million with PVR paying a weighted average fixed rate of 4.23% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. Settlements on the PVR Revolver Swaps are recorded as interest expense. Certain of the PVR Revolver Swaps are designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the transactions for the swaps that are designated as cash flow hedges are recorded each period in AOCI. PVR reported a (i) derivative liability of $3.4 million at September 30, 2008 and (ii) loss in AOCI of $1.3 million, net of the related income tax expense of $0.7 million, at September 30, 2008 related to the PVR Revolver Swaps. In connection with periodic settlements, PVR recognized $0.8 million and $1.2 million in net hedging losses in interest expense for the three and nine months ended September 30, 2008.

Adoption of SFAS No. 161

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

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

	Location of gain (loss) on derivatives recognized in income	Three Months Ended September 30,			Nine Months Ended September 30,
		2008			2008
Derivatives designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Interest expense	$	(1,179	)	$	(1,891	)
Decrease in net income resulting from derivatives designated as hedging instruments under SFAS No. 133		$	(1,179	)	$	(1,891	)
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivatives	$	(1,333	)	$	(1,333	)
Commodity contracts (1)	Natural gas midstream revenues		(1,987	)		(6,235	)
Commodity contracts (1)	Cost of midstream gas purchased		484			2,107
Commodity contracts	Derivatives		126,464			(3,055	)
Increase (decrease) in net income resulting from derivatives not designated as hedging instruments under SFAS No. 133		$	123,628		$	(8,516	)
Total increase (decrease) in net income resulting from derivatives		$	122,449		$	(10,407	)
Realized and unrealized derivative impact:
Cash paid for commodity contract settlements	Derivatives	$	(19,755	)	$	(46,740	)
Cash paid for interest rate contract settlements	Interest expense		(1,179	)		(1,891	)
Unrealized derivative gain	(2)		143,383			38,224
Increase (decrease) in net income		$	122,449		$	(10,407	)

(1) These amounts represent reclassifications from AOCI. Subsequent to the discontinuation of hedge accounting for commodity derivatives in 2006, amounts remaining in AOCI have been reclassified into earnings in the same period or periods during which the original hedge forecasted transaction affects earnings. The amount remaining in AOCI that will be reclassified to earnings in future periods is $0.9 million, net of related income taxes of $0.5 million.

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

Cash paid for commodity derivatives is included on the Derivatives line on our consolidated statement of income, and cash paid for interest rate swaps is included on the Interest expense line on our consolidated statement of income.

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

		Derivative Assets		Derivative Liabilities
	Balance Sheet Location	Estimated fair values as of September 30, 2008
Derivatives designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivative liabilities - current	$	—	$	1,063
Interest rate contracts	Derivative liabilities - noncurrent		—		1,351
Total derivatives designated as hedging instruments under SFAS No. 133		$	—	$	2,414
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivative liabilities - current	$	—	$	1,307
Interest rate contracts	Derivative liabilities - noncurrent		—		1,754
Commodity contracts	Derivative assets/liabilities - current		18,197		15,589
Commodity contracts	Derivative assets/liabilities - noncurrent		6,019		1,022
Total derivatives not designated as hedging instruments under SFAS No. 133		$	24,216	$	19,672
Total estimated fair value of derivative instruments		$	24,216	$	22,086

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

	Three Months Ended			Nine Months Ended
Source	September 30, 2008
Interest on borrowings	$	(11,251	)	$	(31,939	)
Capitalized interest (1)		492			2,230
Interest rate swaps		(1,179	)		(1,891	)
Total interest expense	$	(11,938	)	$	(31,600	)

(1) Capitalized interest for the nine months ended September 30, 2008 was primarily related to the construction of PVR’s natural gas gathering facilities. PVR had no capitalized interest in the three months ended September 30, 2008.

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

9. PVR Senior Notes Repayment and PVR Revolver Amendment

In July 2008, PVR paid an aggregate of $63.3 million to the holders of its Senior Unsecured Notes due 2013 (the “PVR Notes”) to repay 100% of the aggregate principal amount of the PVR Notes as provided in the Note Purchase Agreements governing the PVR Notes. This amount consisted of approximately $58.4 million aggregate principal amount outstanding on the PVR Notes, $1.1 million in accrued and unpaid interest on the PVR Notes through the prepayment date and $3.8 million in make-whole amounts due in connection with the prepayment of the PVR Notes. PVR repaid the PVR Notes with borrowings under the PVR Revolver.

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

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10. Income Taxes

The total liability for unrecognized tax benefits at September 30, 2008 was $5.5 million, including $4.1 million of tax positions which would change the effective tax rate if recognized. During the three and nine months ended September 30, 2008, the liability for unrecognized tax benefits decreased by $0.4 and $4.9 million relating to settlements with taxing authorities.

We are currently evaluating the filing status of a subsidiary in two states. If management and the states’ taxing authority determine that the subsidiary’s income is taxable in those states, we may be requested to pay taxes of approximately $2.8 million will be made within the next 12 months. We classified $2.8 million of the total liability for unrecognized tax benefits as a current liability on our consolidated balance sheet at September 30, 2008. This current liability represents our best estimate of the change in unrecognized tax benefits that we expect to incur within the next 12 months.

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

11. Earnings per Share

The following is a reconciliation of the numerators and denominators used in the calculation of basic and diluted earnings per share for the three and nine months ended September 30, 2008 and 2007:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(in thousands, except per share data)						(in thousands, except per share data)
Net income	$	123,738		$	17,114		$	123,871		$	45,395
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards		(219	)		(60	)		(418	)		(170	)
	$	123,519		$	17,054		$	123,453		$	45,225
Weighted average shares, basic		41,881			37,898			41,715			37,748
Effect of dilutive securities:
Convertible notes		279			—			—			—
Stock options		384			315			313			297
Weighted average shares, diluted		42,544			38,213			42,028			38,045
Net income per share, basic	$	2.95		$	0.45		$	2.96		$	1.20
Net income per share, diluted	$	2.90		$	0.45		$	2.94		$	1.19

12. Share-Based Compensation

Stock Compensation Plans

We recognized a total of $1.6 million and $1.0 million for the three months ended September 30, 2008 and 2007 and $4.3 million and $3.0 million for the nine months ended September 30, 2008 and 2007 of 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. The total income tax benefit recognized in our consolidated statements of income for our stock compensation plans was $0.6 million and $0.4 million for the three months ended September 30, 2008 and 2007 and $1.7 million and $1.2 million for the nine months ended September 30, 2008 and 2007.

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

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Restricted Stock. In February 2008, we also granted 39,354 shares of restricted stock with a weighted average grant date fair value of $42.27 per share. The restricted stock granted vests over a three-year period, with one-third vesting in each year. We recognize compensation expense on a straight-line basis over the vesting period.

PVR Long-Term Incentive Plan

PVR recognized a total of $0.8 million and $0.7 million for the three months ended September 30, 2008 and 2007 and $2.4 million and $1.8 million for the nine months ended September 30, 2008 and 2007 of compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under its long-term incentive plan. During the nine months ended September 30, 2008, PVR’s general partner granted 134,551 restricted units with a weighted average grant date fair value of $26.87 per unit to employees of Penn Virginia and its affiliates. During the same period, 70,007 restricted units with a weighted average grant date fair value of $27.27 per unit vested. The restricted units granted in 2008 vest over a three-year period, with one-third vesting in each year. PVR recognizes compensation expense on a straight-line basis over the vesting period.

13. Comprehensive Income

Comprehensive income represents changes in shareholders’ equity during the reporting period, including net income and charges directly to shareholders’ equity which are excluded from net income. The following table sets forth the components of comprehensive income for the three and nine months ended September 30, 2008 and 2007:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(in thousands)						(in thousands)
Net income	$	123,738		$	17,114		$	123,871		$	45,395
Unrealized holding losses on derivative activities, net of tax		(1,468	)		(1,215	)		(2,187	)		(505	)
Reclassification adjustment for derivative activities, net of tax		2,610			925			4,781			1,938
Pension plan adjustment		41			(35	)		122			(106	)
Comprehensive income	$	124,921		$	16,789		$	126,587		$	46,722

14. Suspended Well Costs

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

Two exploratory wells that were pending determination of proved reserves as of December 31, 2007 were subsequently determined to be unsuccessful. Accordingly, we charged $1.8 million to expense related to these wells during the nine months ended September 30, 2008.

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15. Commitments and Contingencies

Legal

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, liquidity or operations.

Drilling Commitments

In July 2008, we entered into two agreements to purchase oil and gas well drilling services from a third party, which is scheduled to commence in the second quarter of 2009. The agreements include early termination provisions that would require us to pay a penalty if we terminate the agreements after their execution but prior to the end of their three-year terms, unless certain events occur. The amount of the penalty is based on the number of days remaining in the three-year terms for both contracts. As of September 30, 2008, the total penalty amount would have been approximately $41.6 million if we had terminated both agreements on that date. Management intends to utilize drilling services under these agreements for the full three-year term and has no plans to terminate the agreements early.

Environmental Compliance

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

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

As of September 30, 2008 and December 31, 2007, PVR’s environmental liabilities included $1.2 million and $1.5 million, which represents PVR’s best estimate of the liabilities as of those dates related to its coal and natural resource management and natural gas midstream businesses. PVR has reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

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Mine Health and Safety Laws

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

16. Segment Information

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

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

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

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

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The following tables present a summary of certain financial information relating to our segments as of and for the three and nine months ended September 30, 2008 and 2007:

	Oil and Gas			PVR Coal and Natural Resource Management			PVR Natural Gas Midstream		Eliminations and Other			Consolidated
	(in thousands)
For the Three Months Ended September 30, 2008:
Revenues	$	157,364		$	41,858		$	186,609	$	(219	)	$	385,612
Intersegment revenues (1)		(639	)		(198	)		57,007		(56,170	)		—
Operating costs and expenses		35,072			6,571			221,779		(50,115	)		213,307
Depreciation, depletion and amortization		32,665			8,794			8,109		410			49,978
Operating income (loss)	$	88,988		$	26,295		$	13,728	$	(6,684	)		122,327
Interest expense													(11,938	)
Other													(4,088	)
Derivatives													125,132
Income before minority interest and taxes												$	231,433
Total assets	$	1,595,691		$	588,430		$	619,652	$	106,848		$	2,910,621
Equity investments (2)	$	—		$	25,459		$	53,175	$	—		$	78,634
Goodwill	$	—		$	—		$	31,768	$	—		$	31,768
Additions to property and equipment and acquisitions	$	213,573		$	497		$	110,606	$	259		$	324,935
For the Three Months Ended September 30, 2007:
Revenues	$	85,745		$	28,218		$	101,374	$	421		$	215,758
Intersegment revenues (1)		(414	)		198			414		(198	)		—
Operating costs and expenses		36,029			4,871			82,917		6,850			130,667
Depreciation, depletion and amortization		22,152			5,833			4,812		410			33,207
Operating income (loss)	$	27,150		$	17,712		$	14,059	$	(7,037	)		51,884
Interest expense													(10,843	)
Other													576
Derivatives													(4,455	)
Income before minority interest and taxes												$	37,162
Total assets	$	1,151,331		$	561,169		$	287,769	$	46,287		$	2,046,556
Equity investments	$	—		$	26,428		$	60	$	—		$	26,488
Goodwill	$	—		$	—		$	7,718	$	—		$	7,718
Additions to property and equipment and acquisitions	$	166,500		$	93,449		$	10,755	$	1,775		$	272,479

(1) Intersegment revenues represent gas gathering and processing transactions for the three months ended September 30, 2008 between the PVR natural gas midstream segment and the oil and gas segment. The PVR natural gas midstream segment gathered and processed the natural gas delivered by the oil and gas segment and then purchased the processed gas and NGLs from the oil and gas segment for $55.7 million to sell to third parties. Intersegment revenues also represent agent fees paid by the oil and gas segment to the PVR natural gas midstream segment for marketing certain natural gas production and rail car rental fees paid by a corporate affiliate to the PVR coal and natural resource management segment.

(2) The increase in equity investments is due to the 25% member interest in Thunder Creek that PVR acquired in 2008 for $51.6 million. See Note 4 — Acquisitions.

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	Oil and Gas			PVR Coal and Natural Resource Management			PVR Natural Gas Midstream		Eliminations and Other			Consolidated
	(in thousands)
For the Nine Months Ended September 30, 2008:
Revenues	$	385,100		$	111,604		$	499,009	$	(552	)	$	995,161
Intersegment revenues (1)		(1,709	)		(594	)		108,576		(106,273	)		—
Operating costs and expenses		97,484			20,417			541,270		(86,175	)		572,996
Depreciation, depletion and amortization		90,849			22,733			18,589		1,310			133,481
Operating income (loss)	$	195,058		$	67,860		$	47,726	$	(21,960	)		288,684
Interest expense													(31,600	)
Other													(782	)
Derivatives													(4,387	)
Income before minority interest and taxes												$	251,915
Total assets	$	1,595,691		$	588,430		$	619,652	$	106,848		$	2,910,621
Equity investments (2)	$	—		$	25,459		$	53,175	$	—		$	78,634
Goodwill	$	—		$	—		$	31,768	$	—		$	31,768
Additions to property and equipment and acquisitions	$	422,975		$	25,186		$	220,997	$	1,058		$	670,216
For the Nine Months Ended September 30, 2007:
Revenues	$	226,665		$	84,716		$	312,084	$	961		$	624,426
Intersegment revenues (1)		(1,154	)		594			1,154		(594	)		—
Operating costs and expenses		81,480			15,489			270,966		19,171			387,106
Depreciation, depletion and amortization		58,628			16,643			13,957		595			89,823
Operating income (loss)	$	85,403		$	53,178		$	28,315	$	(19,399	)		147,497
Interest expense													(25,878	)
Other													2,536
Derivatives													(22,068	)
Income before minority interest and taxes												$	102,087
Total assets	$	1,151,331		$	561,169		$	287,769	$	46,287		$	2,046,556
Equity investments	$	—		$	26,428		$	60	$	—		$	26,488
Goodwill	$	—		$	—		$	7,718	$	—		$	7,718
Additions to property and equipment and acquisitions	$	367,558		$	146,915		$	28,619	$	4,913		$	548,005

(1) Intersegment revenues represent gas gathering and processing transactions for the nine months ended September 30, 2008 between the PVR natural gas midstream segment and the oil and gas segment. The PVR natural gas midstream segment gathered and processed the natural gas delivered by the oil and gas segment and then purchased the processed gas and NGLs from the oil and gas segment for $105.5 million to sell to third parties. Intersegment revenues also represent agent fees paid by the oil and gas segment to the PVR natural gas midstream segment for marketing certain natural gas production and rail car rental fees paid by a corporate affiliate to the PVR coal and natural resource management segment.

(2) The increase in equity investments is due to the 25% member interest in Thunder Creek that PVR acquired in 2008 for $51.6 million. See Note 4 — Acquisitions.

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Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the financial condition and results of operations of Penn Virginia Corporation and its subsidiaries should be read in conjunction with our consolidated financial statements and the accompanying notes in Item 1, “Financial Statements.”

Overview of Business

We are an independent oil and gas company primarily engaged in the exploration, development and production of natural gas and oil in various onshore U.S. regions including East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast. We also indirectly own partner interests in PVR, which is engaged in the coal and natural resource management and natural gas midstream businesses. Our ownership interests in PVR are held principally through our ownership of the general partner and 77% limited partner interests in PVG. At September 30, 2008, PVG owned an approximately 37% limited partner interest in PVR and 100% of the general partner of PVR, which held a 2% general partner interest in PVR.

We are engaged in three primary business segments: (i) oil and gas, (ii) coal and natural resource management and (iii) natural gas midstream. We operate our oil and gas segment. PVR operates our coal and natural resource management and natural gas midstream segments and is consolidated by PVG because PVG controls PVR’s general partner. We consolidate PVG’s results into our financial statements because we control the general partner of PVG. Our operating income was $288.7 million in the nine months ended September 30, 2008, compared to $147.5 million in the same period of 2007. In the nine months ended September 30, 2008, the oil and gas segment contributed $195.1 million, or 68%, to operating income, the PVR coal and natural resource management segment contributed $67.9 million, or 24%, to operating income and the PVR natural gas midstream segment contributed $47.7 million, or 17%, to operating income.

The following table presents a summary of certain financial information relating to our segments for the nine months ended September 30, 2008 and 2007 (in thousands):

	Oil and Gas		PVR Coal and Natural Resource Management		PVR Natural Gas Midstream		Eliminations and Other			Consolidated
For the Nine Months Ended September 30, 2008:
Revenues	$	383,391	$	111,010	$	607,585	$	(106,825	)	$	995,161
Operating costs and expenses		97,484		20,417		541,270		(86,175	)		572,996
Depreciation, depletion and amortization		90,849		22,733		18,589		1,310			133,481
Operating income (loss)	$	195,058	$	67,860	$	47,726	$	(21,960	)	$	288,684
For the Nine Months Ended September 30, 2007:
Revenues	$	225,511	$	85,310	$	313,238	$	367		$	624,426
Operating costs and expenses		81,480		15,489		270,966		19,171			387,106
Depreciation, depletion and amortization		58,628		16,643		13,957		595			89,823
Operating income (loss)	$	85,403	$	53,178	$	28,315	$	(19,399	)	$	147,497

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We have grown by making acquisitions in all three of our business segments and by organic growth on our and PVR’s properties. Readily available access to debt and equity capital and credit availability have been and continue to be critical factors in our and PVR’s ability to grow. The current deterioration in global financial markets and the consequential adverse effect on credit availability is adversely impacting our and PVR’s access to new capital and credit availability. Depending on the longevity and ultimate severity of this deterioration, our and PVR’s ability to make acquisitions may be significantly adversely affected, as may PVR’s ability to make cash distributions to its limited partners and to PVG, the owner of its general partner. See Part II, Item 1A — Risk Factors in this Quarterly Report on Form 10-Q.

Oil and Gas Segment

We have a geographically diverse asset base with core areas of operation in East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast regions of the United States. As of December 31, 2007, we had proved natural gas and oil reserves of approximately 680 Bcfe, of which 87% were natural gas and 59% were proved developed. In the nine months ended September 30, 2008, we produced 33.7 Bcfe, a 13% increase compared to 29.9 Bcfe in the same period of 2007.

We continue to expand our presence in unconventional plays, such as the Cotton Valley play in East Texas, the Selma Chalk play in Mississippi and coalbed methane in Appalachia and the Mid-Continent. We expect to continue to increase our proved reserves and production through our active development drilling programs in each of these areas.

Our aggressive growth profile in our oil and gas segment has been accomplished primarily by drilling oil and natural gas wells in our operating areas and, to a lesser extent, by making acquisitions of both producing properties and undeveloped leases. This growth profile has required us to spend capital in excess of our cash flow from operations, and readily available access to debt and equity capital were and continue to be a critical factor in our ability to grow. The current deterioration in global financial markets and the consequential adverse effect on credit availability is adversely impacting access to new capital and expanded credit availability. We currently have internal cash flows and available credit facility borrowings that we believe supports growth through 2009. However, depending on the longevity and ultimate severity of the global financial and credit markets deterioration, we may ultimately need to limit our capital spending to more closely mirror internally generated cash flow, which may materially adversely effect how aggressively we can grow. See Part II, Item 1A — Risk Factors in this Quarterly Report on Form 10-Q.

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

PVR Coal and Natural Resource Management Segment

As of December 31, 2007, PVR owned or controlled 818 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. PVR enters into long-term leases with experienced, third-party mine operators, providing them the right to mine its coal reserves in exchange for royalty payments. PVR actively works with its lessees to develop efficient methods to exploit the reserves and to maximize production from the properties. PVR does not operate any mines. In the nine months ended September 30, 2008, PVR’s lessees produced 25.0 million tons of coal from its properties and paid PVR coal royalties revenues of $88.9 million, for an average royalty per ton of $3.56. Approximately 85% of PVR’s coal royalties revenues in the nine months ended September 30, 2008 were derived from coal mined on PVR’s properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of PVR’s coal royalties revenues for the respective periods was derived from coal mined on PVR’s properties under leases containing fixed royalty rates that escalate annually.

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

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

The future impact of the current deterioration of the global financial and credit markets on coal production levels and prices is uncertain. Depending on the longevity and ultimate severity of the deterioration, demand for coal may decline, which could adversely effect production and pricing for coal mined by PVR’s lessees, and, consequently, adversely effect the royalty income received by PVR and PVR’s ability to make cash distributions. See Part II, Item 1A — Risk Factors in this Quarterly Report on Form 10-Q.

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

PVR Natural Gas Midstream Segment

PVR owns and operates natural gas midstream assets located in Oklahoma and Texas. These assets included approximately 4,059 miles of natural gas gathering pipelines as of September 30, 2008. We also owned five natural gas processing facilities having 300 MMcfd of total capacity as of September 30, 2008. PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines. In addition, PVR owns a 25% member interest in Thunder Creek Gas Services, LLC (“Thunder Creek”), a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin.

For the nine months ended September 30, 2008, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 68.9 Bcf, or approximately 252 MMcfd. For the nine months ended September 30, 2008, one of PVR’s natural gas midstream customers accounted for 26% of PVR’s natural gas midstream segment revenues and 16% of our total consolidated revenues.

Revenues, profitability and the future rate of growth of PVR’s natural gas midstream segment are highly dependent on market demand and prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market uncertainty.

PVR continually seeks new supplies of natural gas to offset the natural declines in production from the wells currently connected to its systems and to increase system throughput volumes. New natural gas supplies are obtained for all of PVR’s systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors’ systems.

The current deterioration in global financial and credit markets will likely result in a decrease in worldwide demand for oil and domestic demand for natural gas and NGLs. Depending on the longevity and ultimate severity of the deterioration, NGL production from PVR’s processing plants could decrease and adversely effect PVR’s natural gas midstream processing income and PVR’s ability make cash distributions. See Part II, Item 1A — Risk Factors in this Quarterly Report on Form 10-Q.

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Eliminations and Other

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

Ownership of and Relationship with PVG and PVR

Penn Virginia, PVG and PVR are publicly traded on the New York Stock Exchange under the symbols “PVA,” “PVG” and “PVR.” Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. Because PVG controls the general partner of PVR, the financial results of PVR are included in PVG’s condensed consolidated financial statements. However, PVG and PVR function with capital structures that are independent of each other and us, with each having publicly traded common units and PVR having its own debt instruments. PVG does not currently have any debt instruments. While we report consolidated financial results of PVR’s coal and natural resource management and natural gas midstream businesses, the only cash we received from those businesses is in the form of cash distributions from PVG.

As of September 30, 2008, we owned the general partner of PVG and an approximately 77% limited partner interest in PVG. As a result of PVR’s unit offering, we recognized a gain in shareholders’ equity and PVG recognized gains in its partners’ capital. See Note 3 — Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements.” PVG also owns 100% of the general partner of PVR, which holds a 2% general partner interest in PVR, and all the incentive distribution rights. As a result of PVR’s unit offering in 2008, PVG’s ownership interest in PVR decreased from 42% to 37%. See Note 6 — PVR Unit Offering in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements.” We directly owned an additional 0.2% limited partner interest in PVR as of September 30, 2008. The following diagram depicts our ownership of PVG and PVR as of September 30, 2008:

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Liquidity and Capital Resources

Although results are consolidated for financial reporting, Penn Virginia, PVG and PVR operate with independent capital structures. Since PVR’s inception in 2001 and PVG’s inception in 2006, with the exception of cash distributions paid to us by PVG and PVR, the cash needs of each entity have been met independently with a combination of operating cash flows, credit facility borrowings and the issuance of Penn Virginia shares, PVG units 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.

With respect to Penn Virginia (excluding the sources and uses of capital by PVG and PVR), we satisfy our working capital requirements and fund our capital expenditures, debt service obligations and dividend payments using cash generated from our operations, borrowings under our revolving credit facility (the “Revolver”) and proceeds from equity offerings. We believe that the cash generated from our operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled debt payments and dividend payments. Our ability to satisfy our obligations and planned expenditures will depend on our future operating performance, which will be affected by, among other things, prevailing economic conditions in the commodity markets of oil and natural gas, some of which are beyond our control. In addition, depending on the longevity and ultimate severity of the current deterioration of the global financial and credit markets, our ability to grow may be significantly adversely effected. See Part II, Item 1A — Risk Factors in this Quarterly Report on Form 10-Q.

PVR satisfies its working capital requirements and funds its capital expenditures, debt service obligations and distributions to unitholders using cash generated from operations, borrowings under its revolving credit facility (the “PVR Revolver”) and proceeds from equity offerings. We believe that the cash generated from PVR’s operations and its borrowing capacity will be sufficient to meet its working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled debt payments and distribution payments. PVR’s ability to satisfy its obligations and planned expenditures will depend upon its future operating performance, which will be affected by, among other things, prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond PVR’s control. In addition, depending on the longevity and ultimate severity of the current deterioration of the global financial and credit markets, PVR’s ability to grow through acquisitions may be adversely effected, which could in turn adversely effect its ability to make cash distributions to its limited partners and to PVG, the owner of its general partner. See Part II, Item 1A — Risk Factors in this Quarterly Report on Form 10-Q.

Cash Flows

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

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

For The Nine Months Ended September 30, 2008:	Oil and Gas & Corporate			PVR			Consolidated
Net cash provided by operating activities	$	181,920		$	94,767		$	276,687
Cash flows from financing activities:
Dividends paid		(7,037	)		—			(7,037	)
Distributions received (paid)		34,370			(80,199	)		(45,829	)
Debt borrowings, net		104,431			146,000			250,431
Proceeds received from (paid for) issuance of PVR partners’ capital		(2,943	)		140,958			138,015
Other		12,549			(4,074	)		8,475
Net cash provided by financing activities		141,370			202,685			344,055
Net cash provided by operating and financing activities		323,290			297,452			620,742
Net cash used in investing activities		(329,986	)		(306,276	)		(636,262	)
Net decrease in cash and cash equivalents	$	(6,696	)	$	(8,824	)	$	(15,520	)
For the Nine Months Ended September 30, 2007:	Oil and Gas & Corporate			PVR			Consolidated
Net cash provided by operating activities	$	122,645		$	86,336		$	208,981
Cash flows from financing activities:
Dividends paid		(6,370	)		—			(6,370	)
Distributions received (paid)		29,451			(65,853	)		(36,402	)
Debt borrowings, net		193,500			146,000			339,500
Other		6,516			860			7,376
Net cash provided by financing activities		223,097			81,007			304,104
Net cash provided by operating and financing activities		345,742			167,343			513,085
Net cash used in investing activities		(343,283	)		(175,337	)		(518,620	)
Net increase (decrease) in cash and cash equivalents	$	2,459		$	(7,994	)	$	(5,535	)

Cash provided by operating activities of the oil and gas segment and corporate activities increased by $59.3 million, or 48%, from $122.6 million in the nine months ended September 30, 2007 to $181.9 million in the same period of 2008. This increase was primarily attributable to an increase in the oil and gas segment’s operating income.

Cash provided by operating activities for PVR increased by $8.5 million, or 10%, from $86.3 million in the nine months ended September 30, 2007 to $94.8 million in the same period of 2008. This increase was primarily attributable to the increases in operating income in the coal and natural resource management and natural gas midstream segments, partially offset by increased cash paid for derivative settlements in the natural gas midstream segment.

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Capital Expenditures

Capital expenditures, which comprise the primary portion of cash used in investing activities, totaled $793.5 million in the nine months ended September 30, 2008, compared to $555.5 million in the same period of 2007. The following table sets forth capital expenditures by segment during the nine months ended September 30, 2008 and 2007:

	Nine Months Ended September 30,
	2008		2007
	(in thousands)
Oil and gas
Proved property acquisitions	$	—	$	62,803
Development drilling		320,754		230,396
Exploration drilling		18,080		34,733
Seismic		2,697		2,213
Lease acquisition and other		87,460		30,653
Pipeline, gathering and facilities		28,015		14,593
Total		457,006		375,391
Coal and natural resource management
Acquisitions		25,014		145,878
Expansion capital		—		85
Other property and equipment		173		79
Total		25,187		146,042
Natural gas midstream
Acquisitions (1)		254,132		—
Expansion capital		45,138		21,738
Other property and equipment		10,824		7,370
Total		310,094		29,108
Other		1,189		4,913
Total capital expenditures	$	793,476	$	555,454

(1) Natural gas midstream segment acquisitions in the nine months ended September 30, 2008 include newly issued PVR units valued at $15.2 million; PVG units, which PVR purchased from us, valued at $68.0 million; and a $4.7 million guaranteed payment which will be paid in 2009. All of this was given as consideration in the acquisition of Lone Star Gathering, L.P. (the “Lone Star Acquisition”). See Note 4 — “Acquisitions” in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements.”

In the nine months ended September 30, 2008, the oil and gas segment made aggregate capital expenditures of $457.0 million primarily for development drilling and unproved property acquisitions in East Texas. In the nine months ended September 30, 2007, the oil and gas segment made aggregate capital expenditures of $375.4 million primarily for development drilling, proved property acquisitions, exploration drilling and lease acquisitions in East Texas and in the Mid-Continent region.

In the nine months ended September 30, 2008, we drilled a successful horizontal Lower Bossier Shale well in Harrison County, Texas. Based on this successful horizontal test, we have four drilling rigs currently drilling horizontal Lower Bossier Shale wells.

In the nine months ended September 30, 2008, PVR’s natural gas midstream segment made aggregate capital expenditures of $310.1 million, primarily related to PVR’s 25% member interest acquisition of Thunder Creek, the Lone Star Acquisition, pipeline assets in the Anadarko Basin of Oklahoma and Texas and expansion capital expenditures related to the Spearman Natural Gas Processing Plant in the Texas Panhandle (“Spearman plant”) and Crossroads Natural Gas Processing Plant in East Texas (“Crossroads plant”). In the nine months ended September 30, 2008, PVR’s coal and natural resource management segment made aggregate capital expenditures of $25.2 million, primarily to acquire approximately 29 million tons of coal reserves and an estimated 56 million board feet of hardwood timber in western Virginia and eastern Kentucky. In the nine months ended September 30, 2007, PVR’s natural gas midstream segment made aggregate capital expenditures of $29.1 million, primarily for natural gas midstream system expansion projects and the acquisition of pipeline and compression facilities. In the nine months ended September 30, 2007, PVR’s coal and natural resource management segment made aggregate capital expenditures of $146.0 million, primarily related to acquisitions of coal reserves, forestlands, a preparation plant and coal handling facilities. In the nine months ended September 30, 2008 and 2007, these acquisitions were funded by borrowings under the PVR Revolver.

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Other capital expenditures of $4.9 million in the nine months ended September 30, 2007 were primarily due to the implementation of a software system.

We funded oil and gas and other capital expenditures in the nine months ended September 30, 2008 and 2007 with borrowings under the Revolver and cash provided by operating activities. PVR funded its coal and natural resource management and natural gas midstream capital expenditures in the nine months ended September 30, 2008 primarily with cash provided by operating activities, borrowings under the PVR Revolver and through the issuance of additional PVR common units.

We had $58.0 million of net borrowings under the Revolver in the nine months ended September 30, 2008, consisting of borrowings under the Revolver of $121.0 million and repayments under the Revolver of $63.0 million. We had net borrowings of $193.5 million under the Revolver in the nine months ended September 30, 2007, consisting of borrowings under the Revolver of $220.5 million and repayments under the Revolver of $27.0 million. As a result of our partner interests in PVG and PVR, we received cash distributions of $32.2 million in the nine months ended September 30, 2008, compared to $19.9 million of cash distributions in the nine months ended September 30, 2007. Distributions increased $12.3 million primarily due to PVG increasing its distribution per unit from $0.28 per unit to $0.36 per unit and PVR increasing its distribution from $0.42 per unit to $0.46 per unit. Funds from both of these sources were primarily used for capital expenditures.

PVR had net borrowings of $146.0 million in the nine months ended September 30, 2008, comprised of net borrowings of $210.4 million under the PVR Revolver and net repayments of $64.4 million under its Senior Unsecured Notes due 2013 (the “PVR Notes”). PVR received net proceeds of $138.0 million from the sale of its common units in a public offering in 2008. These proceeds were partially offset by total capital expenditures of $335.3 million in the nine months ended September 30, 2008. This is compared to $146.0 million of net borrowings in the nine months ended September 30, 2007, comprised of net borrowings of $157.0 million under the PVR Revolver and net repayments of $11.0 million under the PVR Notes. Funds from the borrowings in the nine months ended September 30, 2007 were primarily used for capital expenditures.

In October 2008, PVG declared a $0.38 per unit quarterly distribution for the three months ended September 30, 2008, or $1.52 per unit on an annualized basis, of which we will receive $11.4 million. We will receive these distributions as a result of our limited partner interest in PVG. The portion of PVR’s distribution paid to PVG serves as the basis for PVG’s distribution to its unitholders, including us.

Long-Term Debt

Revolving Credit Facility. As of September 30, 2008, we had $180.0 million outstanding under the Revolver. At the current $479.0 million limit on the Revolver, and given our outstanding balance of $180.0 million, net of $0.3 million of letters of credit, we could borrow up to $298.7 million at September 30, 2008. The Revolver, which matures in December 2010, is secured by a portion of our proved oil and gas reserves. The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions, and includes a $20.0 million sublimit for the issuance of letters of credit. We had outstanding letters of credit of $0.3 million as of September 30, 2008. In the nine months ended September 30, 2008, we incurred commitment fees of $0.6 million on the unused portion of the Revolver. We capitalized $1.6 million of interest cost incurred in the nine months ended September 30, 2008. The Revolver is governed by a borrowing base calculation and is redetermined semi-annually. We have the option to elect interest at (i) the London Interbank Offered Rate (“LIBOR”), plus a margin

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ranging from 1.00% to 1.75%, based on the ratio of our outstanding borrowings to the borrowing base or (ii) the greater of the prime rate or federal funds rate plus a margin of up to 0.50%. The weighted average interest rate on borrowings outstanding under the Revolver during the nine months ended September 30, 2008 was 4.28%.

The financial covenants under the Revolver require us not to exceed specified ratios. We are required to maintain a Debt-to-EBITDAX ratio of no more than 3.5-to-1.0 and an EBITDAX-to-interest expense ratio of no less than 2.5-to-1.0. At September 30, 2008, our Debt-to-EBITDAX ratio was 1.5-to-1.0 and our EBITDAX-to-interest expense ratio was 15.9-to-1.0. EBITDAX is defined as our Net Income before the effects of Interest Expense, Interest Income, Income Tax Expense, Depreciation, Depletion and Amortization expense (“DD&A”) and Exploration expense. In addition, the financial covenants 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 September 30, 2008, we were in compliance with all of our covenants under the Revolver.

Convertible Notes. As of September 30, 2008, we had $230.0 million outstanding of Convertible Senior Subordinated Notes due 2012 (the “Convertible Notes”). The Convertible Notes bear interest at a rate of 4.50% per year payable semiannually in arrears on May 15 and November 15 of each year.

The Convertible Notes are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.3160 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment, and, if not converted or repurchased earlier, will mature on November 15, 2012. Holders of Convertible Notes may convert their Convertible Notes at their option prior to the close of business on the business day immediately preceding September 15, 2012 only under the following circumstances: (i) during any fiscal quarter if the last reported sale price per share of common stock for at least 20 trading days (whether or not consecutive) in the 30 consecutive trading days ending on the last trading day of the immediately preceding fiscal quarter is greater than or equal to 130% of the then applicable conversion price on each such trading day; (ii) during the five business day period after any ten consecutive trading day period in which the trading price per $1,000 principal amount of the Convertible Notes for each day of such period was less than 98% of the product of the last reported sale price per share of common stock and the applicable conversion rate on each such day; or (iii) upon the occurrence of certain corporate events set forth in the indenture governing the Convertible Notes. On and after September 15, 2012 until the close of business on the third business day immediately preceding November 15, 2012, holders of the Convertible Notes may convert their Convertible Notes at any time, regardless of the foregoing circumstances.

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

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

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

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

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

On October 3, 2008, one of the Option Counterparties, Lehman Brothers OTC Derivatives Inc. (“Lehman OTC”), joined other Lehman Brothers entities and filed for bankruptcy protection. We had purchased 22.5% of the Note Hedges from Lehman OTC (the “Lehman Note Hedges”) for approximately $8.3 million, and we had sold 22.5% of the Warrants to Lehman OTC for approximately $4.1 million. If the Lehman Note Hedges are rejected or terminated in connection with the Lehman OTC bankruptcy, we would have a claim against Lehman OTC and possibly Lehman Brothers Inc. as guarantor for the damages and/or close-out values resulting from any such rejection or termination. While we intend to pursue any claim for damages and/or close-out values resulting from the rejection or termination of the Lehman Note Hedges, at this point in the Lehman bankruptcy cases it is not possible to determine with accuracy the ultimate recovery, if any, that we may realize on potential claims against Lehman OTC or its affiliated guarantor resulting from any rejection or termination of the Lehman Note Hedges. We also do not know at this point whether Lehman OTC will assume or reject the Lehman Note Hedges, and therefore cannot predict whether Lehman OTC intends to perform its obligations under the Lehman Note Hedges. If Lehman OTC does not perform such obligations and the price of our common stock exceeds the $57.75 conversion price (as adjusted) of the Notes, our existing shareholders would experience dilution at the time or times the Notes are converted. The extent of any such dilution would depend, among other things, on the then prevailing market price of our common stock and the number of shares of common stock then outstanding, but we believe the impact will not be material and will not affect our income statement presentation. We are not otherwise exposed to counterparty risk related to the bankruptcies of Lehman Brothers Inc. or its affiliates and do not believe that the Lehman bankruptcies will have a material adverse effect on our financial condition or results of operations.

Interest Rate Swaps. We have entered into interest rate swap agreements (the “Revolver Swaps”) to establish fixed rates on a portion of the outstanding borrowings under the Revolver until December 2010. The notional amounts of the Revolver Swaps total $50.0 million. We will pay a weighted average fixed rate of 5.34% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the Revolver Swaps are recorded as interest expense. The Revolver Swaps were designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings in interest expense. After considering the applicable margin of 1.0% in effect as of September 30, 2008, the total interest rate on the $50.0 million portion of Revolver borrowings covered by the Revolver Swaps was 6.34% at September 30, 2008.

PVR Revolver. In August 2008, PVR increased the size of the PVR Revolver from $600 million to $700.0 million and secured the Revolver with substantially all of its assets. Net of outstanding borrowings and letters of credit, PVR had remaining borrowing capacity of $140.3 million on the PVR Revolver as of September 30, 2008. The PVR Revolver matures in December 2011 and is available to PVR for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10.0 million sublimit for the issuance of letters of credit. As of September 30, 2008, PVR had $558.1 million of borrowings outstanding under the PVR Revolver and outstanding letters of credit of $1.6 million. In the nine months ended September 30, 2008, PVR incurred commitment fees of $0.4 million on the unused portion of the PVR Revolver. The interest rate under the PVR Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 0.75% if we select the base rate borrowing option under the PVR Revolver or at a rate

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derived from LIBOR, plus an applicable margin ranging from 0.75% to 1.75% if PVR selects the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the PVR Revolver in the nine months ended September 30, 2008 was 4.89%.

The financial covenants under the PVR Revolver require PVR not to exceed specified ratios. PVR is required to maintain a debt-to-consolidated EBITDA ratio (the “Leverage Ratio”) of less than 5.25-to-1 and consolidated EBITDA-to-interest expense ratio of greater than 2.5-to-1 (the “Interest Coverage Ratio”). At September 30, 2008, PVR’s Leverage Ratio was 3.40-to-1.0 and PVR’s Interest Coverage Ratio was 5.44-to-1.0. 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 PVR’s 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 September 30, 2008, PVR was in compliance with all of the covenants under the PVR Revolver.

PVR Notes. In July 2008, PVR paid an aggregate of $63.3 million to the holders of the PVR Notes to prepay 100% of the aggregate principal amount of the PVR Notes as provided in the Note Purchase Agreements governing the PVR Notes. This amount consisted of approximately $58.4 million aggregate principal amount outstanding on the PVR Notes, $1.1 million in accrued and unpaid interest on the PVR Notes through the prepayment date and $3.8 million in make-whole amounts due in connection with the prepayment of the PVR Notes. The PVR Notes were repaid with borrowings under the PVR Revolver.

PVR Interest Rate Swaps. PVR has entered into interest rate swap agreements (the “PVR Revolver Swaps”) to establish fixed rates on a portion of the outstanding borrowings under the Revolver. Until March 2010, the notional amounts of the PVR Revolver Swaps total $210.0 million, or approximately 38% of PVR’s total long-term debt outstanding as of September 30, 2008, with PVR paying a weighted average fixed rate of 4.23% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From March 2010 to December 2011, the notional amounts of the PVR Revolver Swaps total $150.0 million, with PVR paying a weighted average fixed rate of 4.23% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. These swap agreements have been entered into with four financial institution counterparties, with no counterparty having more than 36% of the open positions. We are not aware of any specific concerns regarding PVR’s counterparties’ ability to make payments under any of the swap agreements. After considering the applicable margin of 1.75% in effect as of September 30, 2008, the total interest rate on the $210.0 million portion of PVR Revolver borrowings covered by the PVR Revolver Swaps was 5.98% at September 30, 2008.

PVR Unit Offering

In 2008, PVR issued 5.15 million common units to the public representing limited partner interests in PVR and received $138.0 million in net proceeds. PVG made contributions to PVR of $2.9 million in order to maintain its 2% general partner interest. The net proceeds were used to repay a portion of PVR’s borrowings under the PVR Revolver.

Future Capital Needs and Commitments

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

For the remainder of 2008, in addition to the acquisitions mentioned above, we anticipate making oil and gas segment capital expenditures, excluding acquisitions, of approximately $130.0 million to $150.0 million. These expenditures are expected to require capital in excess of our operating cash flow and cash distributions received from PVG and PVR,

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and the shortfall will be funded from the Revolver as needed. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on industry conditions and the availability of capital. We believe our cash flow from operating activities and sources of debt financing are sufficient to fund our 2008 planned oil and gas capital expenditure program. For future periods, we continue to assess funding needs for our growth opportunities in the context of our presently available debt capacity. We expect to use a combination of cash flows from operating activities, borrowings under the Revolver and issuance of additional debt and equity securities to our growth. However, if recent disruption in the worldwide credit and capital markets continues into the future, our ability to grow will probably become limited. We cannot be certain that we will be able to issue our debt or equity securities on terms or in the proportions that we anticipate, or at all, and we may be unable to finance our Revolver when it expires in 2010. In addition, we may be unable to obtain adequate funding under our Revolver because our lending counterparties may be unwilling or unable to meet their funding obligations.

Currently, PVG has no capital requirements for PVR. PVR’s short-term cash requirements for operating expenses and quarterly distributions to PVG and unitholders are expected to be funded through operating cash flows. For the remainder of 2008, PVR anticipates making capital expenditures of $30.0 million to $40.0 million, the majority of which will be incurred in the PVR natural gas midstream segment. PVR intends to fund these capital expenditures with a combination of cash flows provided by operating activities and borrowings under the PVR Revolver. Long-term cash requirements for PVR’s long-term strategy of 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 debt and equity securities. Future financing will depend on various factors, including prevailing market conditions, interest rates and our financial condition and credit rating. The current disruption in the worldwide financial markets has made access to new debt and equity capital very difficult in the short term. If this situation continues for an extended period, PVR’s ability to issue debt and equity securities and to make acquisitions in the future may be limited, as will its ability to increase cash distributions to limited partners and to PVG.

Results of Operations

Selected Financial Data—Consolidated

The following table sets forth a summary of certain consolidated financial data for the three and nine months ended September 30, 2008 and 2007:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(in thousands, except per share data)				(in thousands, except per share data)
Revenues	$	385,612	$	215,758	$	995,161	$	624,426
Expenses	$	263,285	$	163,874	$	706,477	$	476,929
Operating income	$	122,327	$	51,884	$	288,684	$	147,497
Net income	$	123,738	$	17,114	$	123,871	$	45,395
Earnings per share, basic	$	2.95	$	0.45	$	2.96	$	1.20
Earnings per share, diluted	$	2.90	$	0.45	$	2.94	$	1.19
Cash flows provided by operating activities	$	91,795	$	76,184	$	276,687	$	208,981

Operating income increased by $70.4 million in the three months ended September 30, 2008 compared to the same period of 2007 primarily due to the $36.6 million increase in natural gas revenues, the $31.3 million gain on the sales of property and equipment, partially offset by the $16.8 million increase in DD&A. Operating income increased by $141.2 million in the nine months ended September 30, 2008 compared to the same period of 2007 primarily due to the $101.7 million increase in natural gas revenues, the $31.3 million gain on the sales of property and equipment and a $26.9 million increase in consolidated gross margin, partially offset by the $43.7 million increase in DD&A.

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Net income increased by $106.6 million in the three months ended September 30, 2008 compared to the same period of 2007 primarily due to the increase in operating income and the $129.6 million change in derivatives, partially offset by the corresponding increases in minority interest and income tax expense. Net income increased by $78.5 million in the nine months ended September 30, 2008 compared to the same period of 2007 primarily due to the increase in operating income and the $17.7 million change in derivatives, partially offset by the corresponding increase in minority interest income tax expense.

The assets, liabilities and earnings of PVG are fully consolidated in our financial statements, with the public unitholders’ interest (23% as of September 30, 2008) reflected as a minority interest in our consolidated financial statements. The assets, liabilities and earnings of PVR are fully consolidated in PVG’s financial statements, with the interest that PVG does not own (61%, after the effect of incentive distribution rights, as of September 30, 2008) reflected as a minority interest in PVG’s condensed consolidated financial statements.

Oil and Gas Segment

Three Months Ended September 30, 2008 Compared With the Three Months Ended September 30, 2007

The following table sets forth a summary of certain financial and other data for our oil and gas segment and the percentage change for the three months ended September 30, 2008 and 2007:

	Three Months Ended September 30,				%		Three Months Ended September 30,
	2008		2007		Change		2008		2007
	(in thousands, except as noted)						(per Mcfe) (1)
Financial Highlights
Revenues
Natural gas	$	101,911	$	65,310	56	%	$	10.14	$	6.28
Crude oil		13,764		6,299	119	%		117.64		72.40
NGL		10,481		1,290	712	%		66.76		44.48
Gain on the sale of property and equipment		30,509		12,312	148	%
Other income		60		120	(50	)%
Total revenues		156,725		85,331	84	%		13.41		7.69
Expenses
Operating		15,067		12,247	23	%		1.29		1.10
Taxes other than income		6,537		4,380	49	%		0.56		0.39
General and administrative		5,123		4,124	24	%		0.44		0.37
Production costs		26,727		20,751	29	%		2.29		1.86
Exploration		8,346		12,873	(35	)%		0.71		1.16
Impairment of oil and gas properties		—		2,405	(100	)%		—		0.22
Depreciation, depletion and amortization		32,665		22,152	47	%		2.79		2.00
Total expenses		67,738		58,181	16	%		5.79		5.24
Operating income	$	88,987	$	27,150	228	%	$	7.62	$	2.45
Production
Natural gas (MMcf)		10,046		10,407	(3	)%
Crude oil (MBbl)		117		87	34	%
NGL (MBbl)		157		29	441	%
Total production (MMcfe)		11,690		11,102	5	%

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

Production. Approximately 86% and 94% of production in the three months ended September 30, 2008 and 2007 was natural gas. Total production remained relatively constant from the three months ended September 30, 2007 to the same period of 2008.

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

	Natural Gas, Crude Oil and NGL Production		Natural Gas, Crude Oil and NGL Revenues
	Three Months Ended September 30,		Three Months Ended September 30,
Region	2008	2007	2008		2007
	(MMcfe)		(in thousands)
East Texas	3,764	2,092	$	40,630	$	12,999
Mid-Continent	1,609	1,255		15,494		6,880
Appalachia	2,830	3,376		30,514		21,843
Mississippi	1,837	2,015		19,942		13,551
Gulf Coast	1,650	2,364		19,576		17,626
Total	11,690	11,102	$	126,156	$	72,899

The increased production in the East Texas region is due primarily to aggressive drilling and continued development in the region. In addition, the increased production in East Texas is due to additional processing for sales points which were previously sold as wet gas, but are now processed through the Crossroads facility. The increase in production in the Mid-Continent region is due primarily to high production wells in the Mill Creek area, higher coalbed methane production and high production wells in the Granite Wash area. The decrease in the Appalachian region is due primarily to the sale of oil and gas royalty interests to PVR in October 2007, depletion of conventional wells and horizontal coalbed methane wells. The decrease in production in the Gulf Coast region is due primarily to decreased natural gas production resulting from depletion of a prospect within that region.

Revenues. Natural gas revenues increased by $36.6 million, or 56%, from $65.3 million in the three months ended September 30, 2007 to $101.9 million in the same period of 2008. Of the $36.6 million increase, $38.9 million was the result of increased realized prices for natural gas, partially offset by a $2.3 million decrease resulting from decreased natural gas production. Our average realized price received for natural gas increased by $3.86 per Mcf, or 61%, from $6.28 per Mcf in the three months ended September 30, 2007 to $10.14 per Mcf in the same period of 2008.

Crude oil revenues increased by $7.5 million, or 119%, from $6.3 million in the three months ended September 30, 2007 to $13.8 million in the same period of 2008. Of the $7.5 million increase, $5.3 million was the result of higher realized prices for crude oil and $2.2 million was the result of increased crude oil production. Our average realized price received for crude oil increased by $45.24 per Bbl, or 63%, from $72.40 per Bbl in the three months ended September 30, 2007 to $117.64 per Bbl in the same period of 2008.

NGL revenues increased by $9.2 million, or 712%, from $1.3 million in the three months ended September 30, 2007 to $10.5 million in the same period of 2008. Of the $9.2 million increase, $5.7 million was the result of increased NGL production from the operation of a new gas processing plant in East Texas and $3.5 million was the result of higher realized prices for NGLs. Our average realized price received for NGLs increased by $22.28 per Bbl, or 50%, from $44.48 per Bbl in the three months ended September 30, 2007 to $66.76 per Bbl in the same period of 2008.

In July 2008, we completed the sale of certain unproved oil and gas acreage in Louisiana for cash proceeds of $32.0 million and recognized a $30.5 million gain on that sale in the third quarter of 2008.

Settlement of our derivative contracts that do not follow hedge accounting has no effect on our reported revenues. Our revenues may vary significantly from period to period as a result of changes in commodity prices or production volumes. As part of our risk management strategy, we use derivative financial instruments to hedge natural gas and, to a lesser extent, oil prices.

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

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

	Three Months Ended September 30,
	2008			2007			2008			2007
	(in thousands)						(per Mcf)
Natural gas revenues, as reported	$	101,911		$	65,310		$	10.14		$	6.28
Derivatives losses included in natural gas revenues		—			166			—			0.02
Natural gas revenues before impact of derivatives		101,911			65,476			10.14			6.30
Cash settlements on natural gas derivatives		(4,818	)		5,372			(0.48	)		0.52
Natural gas revenues, adjusted for derivatives	$	97,093		$	70,848		$	9.66		$	6.82
	(in thousands)						(per Bbl)
Crude oil revenues, as reported	$	13,764		$	6,299		$	117.64		$	72.40
Derivatives losses included in crude oil revenues		—			126			—			1.45
Crude oil revenues before impact of derivatives		13,764			6,425			117.64			73.85
Cash settlements on crude oil derivatives		(883	)		(84	)		(7.55	)		(0.97	)
Crude oil revenues, adjusted for derivatives	$	12,881		$	6,341		$	110.09		$	72.88

Expenses. Aggregate operating costs and expenses increased by $9.5 million, or 16%, from $58.2 million in the three months ended September 30, 2007 to $67.7 million in the same period of 2008, primarily due to increases in operating expenses, taxes other than income, general and administrative expenses, and DD&A, partially offset by a decrease in exploration expense.

Operating expenses increased by $2.9 million, or 23%, from $12.2 million, or $1.10 per Mcfe, in the three months ended September 30, 2007 to $15.1 million, or $1.29 per Mcfe, in the same period of 2008. This increase is due primarily to increased compressor rentals in the East Texas region due to volume growth, where our drilling program is highly active; and increased processing fees related to the Crossroads plant. In addition, we incurred increased discrete operating expenses related to increased sales volume in the three months ended September 30, 2008.

Taxes other than income increased by $2.1 million, or 49%, from $4.4 million in the three months ended September 30, 2007 to $6.5 million in the same period of 2008 primarily due to increased severance taxes related to higher commodity prices and increased production, as well as increased ad valorem taxes due to growth in East Texas and in the Appalachian regions horizontal coalbed methane production.

General and administrative expenses increased by $1.0 million, or 24%, from $4.1 million in the three months ended September 30, 2007 to $5.1 million in the same period of 2008 primarily due to increased staffing costs in the East Texas and Mid-Continent regions.

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

	Three Months Ended September 30,
	2008		2007
	(in thousands)
Dry hole costs	$	959	$	6,318
Geological and geophysical		1,668		627
Unproved leasehold		4,562		5,664
Other		1,157		264
Total	$	8,346	$	12,873

Exploration expenses decreased by $4.6 million, or 35%, from $12.9 million in the three months ended September 30, 2007 to $8.3 million in the same period of 2008. The decrease in dry hole costs was primarily due to the write-off of one exploratory well in the East Texas region and one exploratory well in the Gulf Coast region in the three months ended September 30, 2007, compared to the write-off of one exploratory well in the Gulf Coast region in the three months ended September 30, 2008. Geological and geophysical expenses increased primarily due to increased seismic purchases in the Mississippi and Gulf Coast regions. The decrease in unproved leasehold expenses is due primarily to the $2.7 million write-off of a prospect in the Mid-Continent region that we incurred in the three months ended September 30, 2007. The increase in other expenses was primarily related to additional delay rentals in the Gulf Coast region caused by the renewal of leases in the certain prospects.

We recorded $2.4 million of impairment charges in the three months ended September 30, 2007 related to changes in estimates of the reserve bases of fields in the Gulf Coast and Mid-Continent regions. No reserves were impaired in the three months ended September 30, 2008.

DD&A expenses increased by $10.5 million, or 47%, from $22.2 million in the three months ended September 30, 2007 to $32.7 million in the same period of 2008, primarily due to the increase in equivalent production and higher depletion rates. Our average depletion rate increased by $0.79 per Mcfe, or 40%, from $2.00 per Mcfe in the three months ended September 30, 2007 to $2.79 per Mcfe in the same period of 2008 due to higher drilling costs in the East Texas, Gulf Coast and Mid-Continent regions. The higher drilling costs were due primarily to increased rig day rates, increased steel costs and our increased drilling efforts in those regions.

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Nine Months Ended September 30, 2008 Compared With the Nine Months Ended September 30, 2007

The following table sets forth a summary of certain financial and other data for our oil and gas segment and the percentage change for the nine months ended September 30, 2008 and 2007:

	Nine Months Ended September 30,				%		Nine Months Ended September 30,
	2008		2007		Change		2008		2007
	(in thousands, except as noted)						(per Mcfe) (1)
Financial Highlights
Revenues
Natural gas	$	295,636	$	193,961	52	%	$	9.90	$	6.96
Crude oil		37,442		14,985	150	%		113.12	$	62.44
NGL		18,887		3,458	446	%		62.96		36.02
Gain on the sale of property and equipment		30,543		12,239	150	%
Other income		883		868	2	%
Total revenues		383,391		225,511	70	%		11.39		7.55
Expenses
Operating		43,370		31,190	39	%		1.29		1.04
Taxes other than income		19,480		13,249	47	%		0.58		0.44
General and administrative		14,870		11,026	35	%		0.44		0.37
Production costs		77,720		55,465	40	%		2.31		1.85
Exploration		19,765		23,610	(16	)%		0.59		0.79
Impairment of oil and gas properties		—		2,405	(100	)%		—		0.08
Depreciation, depletion and amortization		90,849		58,628	55	%		2.70		1.96
Total expenses		188,334		140,108	34	%		5.60		4.68
Operating income	$	195,057	$	85,403	128	%	$	5.79	$	2.87
Production
Natural gas (MMcf)		29,869		27,872	7	%
Crude oil (MBbl)		331		240	38	%
NGL (MBbl)		300		96	213	%
Total production (MMcfe)		33,655		29,888	13	%

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

Production. Approximately 89% and 93% of production in the nine months ended September 30, 2008 and 2007 was natural gas. Total production increased by 3.8 Bcfe, or 13%, from 29.9 Bcfe in the nine months ended September 30, 2007 to 33.7 Bcfe in the same period of 2008, primarily due to increased production in the East Texas and Mid-Continent regions, partially offset by decreased production in the Gulf Coast region.

In the nine months ended September 30, 2008, we drilled a successful horizontal Lower Bossier Shale well in Harrison County, Texas. Based on this successful horizontal test, we have four drilling rigs currently drilling horizontal Lower Bossier Shale wells.

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

	Natural Gas, Crude Oil and NGL Production		Natural Gas, Crude Oil and NGL Revenues
	Nine Months Ended September 30,		Nine Months Ended September 30,
Region	2008	2007	2008		2007
	(MMcfe)		(in thousands)
East Texas	9,986	5,307	$	108,427	$	37,436
Mid-Continent	4,724	2,927		44,915		17,065
Appalachia	8,575	9,425		86,488		66,817
Mississippi	5,462	5,663		56,161		40,606
Gulf Coast	4,908	6,566		55,974		50,480
Total	33,655	29,888	$	351,965	$	212,404

The increased production in the East Texas region is due primarily to aggressive drilling and continued development in the region. In addition, the increased production in East Texas is due to additional processing for sales points which were previously sold as wet gas, but are now processed through the Crossroads facility. The increase in production in the Mid-Continent region is due primarily to high production wells in the Mill Creek area, higher coalbed methane production and high production wells in the Granite Wash area. The decrease in the Appalachian region is due primarily to the sale of oil and gas royalty interests to PVR in October 2007. The decrease in production in the Gulf Coast region is due primarily to decreased natural gas production resulting from depletion of certain prospects within that region.

Revenues. Natural gas revenues increased by $101.6 million, or 52%, from $194.0 million in the nine months ended September 30, 2007 to $295.6 million in the same period of 2008. Of the $101.6 million increase, $87.7 million was the result of increased realized prices for natural gas and $13.9 million was the result of increased natural gas production from drilling. Our average realized price received for natural gas increased by $2.94 per Mcf, or 42%, from $6.96 per Mcf in the nine months ended September 30, 2007 to $9.90 per Mcf in the same period of 2008.

Crude oil revenues increased by $22.4 million, or 150%, from $15.0 million in the nine months ended September 30, 2007 to $37.4 million in the same period of 2008. Of the $22.4 million increase, $16.8 million was the result of higher realized prices for crude oil and $5.6 million was the result of increased crude oil production. Our average realized price received for crude oil increased by $50.68 per Bbl, or 81%, from $62.44 per Bbl in the nine months ended September 30, 2007 to $113.12 per Bbl in the same period of 2008.

NGL revenues increased by $15.4 million, or 446%, from $3.5 million in the nine months ended September 30, 2007 to $18.9 million in the same period of 2008. Of the $15.4 million increase, $8.1 million was the result of higher realized prices for NGLs and $7.3 million was the result of increased NGL production. Our average realized price received for NGLs increased by $26.94 per Bbl, or 75%, from $36.02 per Bbl in the nine months ended September 30, 2007 to $62.96 per Bbl in the same period of 2008.

In July 2008, we completed the sale of certain oil and gas properties in Louisiana for cash proceeds of $32.0 million and recognized a $30.5 million gain on that sale in the third quarter of 2008.

Settlement of our derivative contracts that do not follow hedge accounting has no effect on our reported revenues. Our revenues may vary significantly from period to period as a result of changes in commodity prices or production volumes. As part of our risk management strategy, we use derivative financial instruments to hedge natural gas and, to a lesser extent, oil prices.

As a result of our discontinuance of hedge accounting for our commodity derivatives, in 2007 we reclassified the remaining amounts in accumulated other comprehensive income to earnings. As a result, in the nine months ended September 30, 2008, no derivatives gains or losses were reported as part of natural gas, crude oil and NGL revenues.

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

	Nine Months Ended September 30,
	2008			2007			2008			2007
	(in thousands)						(per Mcf)
Natural gas revenues, as reported	$	295,636		$	193,961		$	9.90		$	6.96
Derivatives gains included in natural gas revenues		—			(315	)		—			(0.01	)
Natural gas revenues before impact of derivatives		295,636			193,646			9.90			6.95
Cash settlements on natural gas derivatives		(12,265	)		11,241			(0.41	)		0.40
Natural gas revenues, adjusted for derivatives	$	283,371		$	204,887		$	9.49		$	7.35
	(in thousands)						(per Bbl)
Crude oil revenues, as reported	$	37,442		$	14,985		$	113.12		$	62.44
Derivatives losses included in crude oil revenues		—			383			—			1.60
Crude oil revenues before impact of derivatives		37,442			15,368			113.12			64.04
Cash settlements on crude oil derivatives		(1,196	)		3			(3.62	)		0.01
Crude oil revenues, adjusted for derivatives	$	36,246		$	15,371		$	109.50		$	64.05

Expenses. Aggregate operating costs and expenses increased by $48.2 million, or 34%, from $140.1 million in the nine months ended September 30, 2007 to $188.3 million in the same period of 2008, primarily due to increased operating expenses, taxes other than income, general and administrative expenses and DD&A, partially offset by a decrease in exploration expense.

Operating expenses increased by $12.2 million, or 39%, from $31.2 million, or $1.04 per Mcfe, in the nine months ended September 30, 2007 to $43.4 million, or $1.29 per Mcfe, in the same period of 2008. This increase is due primarily to increased compressor rentals in East Texas and in the Mid-Continent region; increased water disposal costs in East Texas related to increased production and internal facilities being constructed; increased repairs and maintenance expenses in the Mississippi, Mid-Continent and East Texas regions; and increased processing fees related to the Crossroads plant.

Taxes other than income increased by $6.2 million, or 47%, from $13.3 million in the nine months ended September 30, 2007 to $19.5 million in the same period of 2008, primarily due to an increase in severance and ad valorem taxes related to higher commodity prices and increased production.

General and administrative expenses increased by $3.9 million, or 35%, from $11.0 million in the nine months ended September 30, 2007 to $14.9 million in the same period of 2008, primarily due to increased staffing costs in the East Texas and Mid-Continent regions.

Exploration expenses in the nine months ended September 30, 2008 and 2007 consisted of the following:

	Nine Months Ended September 30,
	2008		2007
	(in thousands)
Dry hole costs	$	3,790	$	10,045
Geological and geophysical		2,697		2,209
Unproved leasehold		11,202		10,401
Other		2,076		955
Total	$	19,765	$	23,610

Exploration expenses decreased by $3.8 million, or 16%, from $23.6 million, in the nine months ended September 30, 2007 to $19.8 million in the same period of 2008. The decrease in dry hole costs was primarily due

38

to the write-off of three exploratory wells in the Gulf Coast region and one exploratory well in the East Texas region in the nine months ended September 30, 2007, compared to the write-off of one exploratory well in the Gulf Coast region in the nine months ended September 30, 2008. Geological and geophysical expenses increased due to seismic expenses incurred primarily in Mississippi and Northeast Texas. Unproved leasehold expenses increased in the Mid-Continent and Gulf Coast regions primarily due to expiring leases on certain of our prospects. Other expenses increased due to increased delay rentals in the Gulf Coast region primarily related to lease renewals on our prospects.

We recorded $2.4 million of impairment charges in the nine months ended September 30, 2007 related to changes in estimates of the reserve bases of fields in the Gulf Coast and Mid-Continent regions. No reserves were impaired in the nine months ended September 30, 2008.

DD&A expenses increased by $32.3 million, or 55%, from $58.6 million in the nine months ended September 30, 2007 to $90.9 million in the same period of 2008, primarily due to the increase in equivalent production and higher depletion rates. Our average depletion rate increased by $0.74 per Mcfe, or 38%, from $1.96 per Mcfe in the nine months ended September 30, 2007 to $2.70 per Mcfe in the same period of 2008 due to higher drilling costs and production in the East Texas and Mid-Continent regions. The higher drilling costs were due primarily to increased rig day rates and increased steel costs.

39

PVR Coal and Natural Resource Management Segment

Three Months Ended September 30, 2008 Compared With the Three Months Ended September 30, 2007

The following table sets forth a summary of certain financial and other data for the PVR coal and natural resource management segment and the percentage change for the three months ended September 30, 2008 and 2007:

	Three Months Ended September 30,						% Change
	2008			2007
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	33,308		$	24,426		36	%
Coal services		1,815			1,955		(7	)%
Timber		1,911			113		1591	%
Oil and gas royalty		1,940			264		635	%
Other		2,686			1,658		62	%
Total revenues		41,660			28,416		47	%
Expenses
Coal royalties expense		2,125			979		117	%
Other operating		752			1,020		(26	)%
Taxes other than income		373			242		54	%
General and administrative		3,321			2,630		26	%
Depreciation, depletion and amortization		8,794			5,833		51	%
Total expenses		15,365			10,704		44	%
Operating income	$	26,295		$	17,712		48	%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,496			8,842		(4	)%
Average royalties revenues per ton ($/ton)	$	3.92		$	2.76		42	%
Less royalties expense per ton ($/ton)		(0.25	)		(0.11	)	127	%
Average net coal royalties per ton ($/ton)	$	3.67		$	2.65		38	%

Revenues. Coal royalties revenues increased by $8.9 million, or 36%, from $24.4 million in the three months ended September 30, 2007 to $33.3 million in the same period of 2008. Coal royalties expense increased by $1.1 million, or 117%, from $1.0 million in the three months ended September 30, 2007 to $2.1 million in the same period of 2008, primarily due to increases in production on subleased property. The average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, increased by $1.02 per ton, or 38%, from $2.65 per ton in the three months ended September 30, 2007 to $3.67 per ton in the same period of 2008. The increase in the average net coal royalty per ton was due primarily to the higher royalty revenues per ton received in Central Appalachia. The increase in royalty revenues per ton received in Central Appalachia was due primarily to higher average sales price of coal in this region.

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

	Coal Production		Coal Royalties Revenues						Coal Royalties Per Ton
	Three Months Ended September 30,		Three Months Ended September 30,						Three Months Ended September 30,
Property	2008	2007	2008			2007			2008			2007
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	4,815	4,660	$	25,184		$	16,799		$	5.23		$	3.60
Northern Appalachia	983	1,337		1,931			2,051			1.96			1.53
Illinois Basin	1,110	1,293		2,923			2,470			2.63			1.91
San Juan Basin	1,588	1,552		3,270			3,106			2.06			2.00
Total	8,496	8,842	$	33,308		$	24,426		$	3.92		$	2.76
Less coal royalties expense (1)				(2,125	)		(979	)		(0.25	)		(0.11	)
Net coal royalties revenues			$	31,183		$	23,447		$	3.67		$	2.65

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

Coal production in Northern Appalachia decreased by 0.3 million tons, or 26%, from 1.3 million tons in the three months ended September 30, 2007 to 1.0 million tons in the same period of 2008. This decrease is primarily due to adverse longwall mining conditions. Coal production in the Illinois Basin decreased by 0.2 million tons, or 14%, from 1.3 million tons in the three months ended September 30, 2007 to 1.1 million tons in the same period of 2008. This decrease is primarily due to the closing of a mine in that region in 2008. Coal production in Central Appalachia and the San Juan Basin remained relatively constant from the three months ended September 30, 2007 to the same period of 2008.

Coal services revenues remained relatively constant in the three months ended September 30, 2007 to the same period of 2008. Timber revenues increased by $1.8 million, or 1,591%, from $0.1 million in the three months ended September 30, 2007 to $1.9 million in the same period of 2008, due to the effects of the September 2007 forestland acquisition. Oil and gas royalty revenues increased by $1.6 million, or 635%, from $0.3 million in the three months ended September 30, 2007 to $1.9 million in the same period of 2008, due to the increased royalties resulting from the October 2007 oil and gas royalty interest acquisition. Other revenues increased by $1.0 million, or 62%, from $1.7 million in the three months ended September 30, 2007 to $2.7 million in the same period of 2008 primarily due to a $0.8 million gain on the sale of coal reserves.

Expenses. Other operating expenses decreased by $0.2 million, or 26%, from $1.0 million in the three months ended September 30, 2007 to $0.8 million in the same period of 2008, primarily due to decreased core-hole drilling. Taxes other than income remained relatively constant in the three months ended September 30, 2007 to the same period of 2008. General and administrative expenses increased by $0.7 million, or 26%, from $2.6 million in the three months ended September 30, 2007 to $3.3 million in the same period of 2008, primarily due to increased staffing costs. DD&A expenses increased by $3.0 million, or 51%, from $5.8 million in the three months ended September 30, 2007 to $8.8 million in the same period of 2008, primarily due to increased depletion resulting from the September 2007 forestland acquisition and the October 2007 oil and gas royalty interest acquisition.

41

Nine Months Ended September 30, 2008 Compared With the Nine Months Ended September 30, 2007

The following table sets forth a summary of certain financial and other data for the PVR coal and natural resource management segment and the percentage change for the nine months ended September 30, 2008 and 2007:

	Nine Months Ended September 30,						% Change
	2008			2007
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	88,911		$	73,455		21	%
Coal services		5,518			5,648		(2	)%
Timber		5,328			530		905	%
Oil and gas royalty		4,730			847		458	%
Other		6,523			4,830		35	%
Total revenues		111,010			85,310		30	%
Expenses
Coal royalties expense		8,034			4,582		75	%
Other operating		1,488			2,086		(29	)%
Taxes other than income		1,115			832		34	%
General and administrative		9,780			7,989		22	%
Depreciation, depletion and amortization		22,733			16,643		37	%
Total expenses		43,150			32,132		34	%
Operating income	$	67,860		$	53,178		28	%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		24,975			25,186		(1	)%
Average royalties revenues per ton ( $/ton)	$	3.56		$	2.92		22	%
Less royalties expense per ton ($/ton)		(0.32	)		(0.18	)	78	%
Average net coal royalties per ton ($/ton)	$	3.24		$	2.74		18	%

Revenues. Coal royalties revenues increased by $15.4 million, or 21%, from $73.5 million in the nine months ended September 30, 2007 to $88.9 million in the same period of 2008. Coal royalties expense increased by $3.4 million, or 75%, from $4.6 million in the nine months ended September 30, 2007 to $8.0 million in the same period of 2008, due primarily to the increase in production on subleased property. The average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, increased by $0.50 per ton, or 18%, from $2.74 per ton in the nine months ended September 30, 2007 to $3.24 per ton in the same period of 2008. The increase in the average net coal royalty per ton was due primarily to the higher royalty revenues per ton received in Central Appalachia. The increase in royalty revenues per ton received in Central Appalachia was due primarily to higher average sales prices for coal in this region.

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

	Coal Production		Coal Royalties Revenues						Coal Royalties Per Ton
	Nine Months Ended September 30,		Nine Months Ended September 30,						Nine Months Ended September 30,
Property	2008	2007	2008			2007			2008			2007
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	14,770	14,635	$	68,213		$	53,983		$	4.62		$	3.69
Northern Appalachia	2,767	3,787		4,922			5,808			1.78			1.53
Illinois Basin	3,262	2,413		7,173			4,957			2.20			2.05
San Juan Basin	4,176	4,351		8,603			8,707			2.06			2.00
Total	24,975	25,186	$	88,911		$	73,455		$	3.56		$	2.92
Less coal royalties expense (1)				(8,034	)		(4,582	)		(0.32	)		(0.18	)
Net coal royalties revenues			$	80,877		$	68,873		$	3.24		$	2.74

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

Coal production in Northern Appalachia decreased by 1.0 million tons, or 27%, from 3.8 million tons in the nine months ended September 30, 2007 to 2.8 million tons in the same period of 2008. This decrease was due primarily to adverse longwall mining conditions. Coal production in the Illinois Basin increased by 0.9 million tons, or 35%, from 2.4 million tons in the nine months ended September 30, 2007 to 3.3 million tons in the same period of 2008. This increase was due primarily to nine months of production in 2008 on the coal reserves that we acquired in June 2007. Coal production in Central Appalachia and in the San Juan Basin remained relatively constant from the nine months ended September 30, 2007 to the same period of 2008.

Coal services revenues remained relatively constant from the nine months ended September 30, 2007 to the same period of 2008. Timber revenues increased by $4.8 million, or 905%, from $0.5 million in the nine months ended September 30, 2007 to $5.3 million in the same period of 2008 primarily due to the effects of the September 2007 forestland acquisition. Oil and gas royalty revenues increased by $3.9 million, or 458%, from $0.8 million in the nine months ended September 30, 2007 to $4.7 million in the same period of 2008 primarily due to the increased royalties resulting from the October 2007 oil and gas royalty interest acquisition. Other revenues increased by $1.7 million, or 35%, from $4.8 million in the nine months ended September 30, 2007 to $6.5 million in the same period of 2008, primarily due to increased wheelage attributable to better longwall production and increased coal sales prices compared to the same period of 2007 and a $0.8 million gain on the sale of coal reserves.

Expenses. Other operating expenses decreased by $0.6 million, or 29%, from $2.1 million in the nine months ended September 30, 2007 to $1.5 million in the same period of 2008, primarily due to a decrease in core-hole drilling. Taxes other than income increased by $0.3 million, or 34%, from $0.8 million in the nine months ended September 30, 2007 to $1.1 million in the same period of 2008, primarily due to increased severance taxes resulting from the September 2007 forestland acquisition and the October 2007 oil and gas royalty interest acquisition. General and administrative expenses increased by $1.8 million, or 22%, from $8.0 million in the nine months ended September 30, 2007 to $9.8 million in the same period of 2008, primarily due to increased staffing costs as well as increased accounting and auditing fees. DD&A expenses increased by $6.1 million, or 37%, from $16.6 million in the nine months ended September 30, 2007 to $22.7 million in the same period of 2008 primarily due to increased depletion resulting from the September 2007 forestland acquisition and the October 2007 oil and gas royalty interest acquisition.

43

PVR Natural Gas Midstream Segment

Three Months Ended September 30, 2008 Compared With the Three Months Ended September 30, 2007

The following table sets forth a summary of certain financial and other data for the PVR natural gas midstream segment and the percentage change for the three months ended September 30, 2008 and 2007:

	Three Months Ended September 30,
	2008			2007			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	158,709		$	52,343		203	%
Natural gas liquids		72,349			42,510		70	%
Condensate		7,202			3,251		122	%
Gathering, processing and transportation fees		3,022			2,266		33	%
Total natural gas midstream revenues (1)		241,282			100,370		140	%
Equity earnings in equity investment		981			—		—
Producer services		1,353			1,418		(5	)%
Total revenues		243,616			101,788		139	%
Expenses
Cost of midstream gas purchased (1)		211,262			76,192		177	%
Operating		6,164			3,225		91	%
Taxes other than income		596			424		41	%
General and administrative		3,757			3,076		22	%
Depreciation and amortization		8,109			4,812		69	%
Total operating expenses		229,888			87,729		162	%
Operating income	$	13,728		$	14,059		(2	)%
Operating Statistics
System throughput volumes (MMcf)		27,744			17,844		55	%
System throughput volumes (MMcfd)		302			194		56	%
Gross margin	$	30,020		$	24,178		24	%
Impact of derivatives		(12,551	)		(3,398	)	269	%
Gross margin, adjusted for impact of derivatives	$	17,469		$	20,780		(16	)%
Gross margin ($/Mcf)	$	1.08		$	1.35		(20	)%
Impact of derivatives ($/Mcf)		(0.45	)		(0.19	)	137	%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.63		$	1.16		(46	)%

(1) In the three months ended September 30, 2008, PVR recorded $55.7 million of natural gas midstream revenue and $55.7 million for the cost of midstream gas purchased related to the purchase of natural gas from Penn Virginia Oil & Gas, L.P. (“PVOG”) and the subsequent sale of that gas to third parties. These transactions do not impact the gross margin.

Gross Margin. PVR’s gross margin is the difference between natural gas midstream revenues and the cost of midstream gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to PVR’s gas processing plants. Cost of midstream gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts.

Natural gas midstream revenues increased by $140.9 million, or 140%, from $100.4 million in the three months ended September 30, 2007 to $241.3 million in the same period of 2008. Cost of midstream gas purchased

44

increased by $135.1 million, or 177%, from $76.2 million in the three months ended September 30, 2007 to $211.3 million in the same period of 2008. The gross margin increased by $5.8 million, or 24%, from $24.2 million in the three months ended September 30, 2007 to $30.0 million in the same period of 2008. The gross margin increase was a result of increased commodity pricing, increased system throughput volume and higher fractionation, or “frac” spreads during the three months ended September 30, 2008 compared to the same period of 2007. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis.

System throughput volumes increased by 108 MMcfd, or 56%, from 194 MMcfd in the three months ended September 30, 2007 to 302 MMcfd in the same period of 2008. This increase in throughput volumes is due primarily to the Crossroads plant in East Texas, which became fully operational in 2008, and to the Lone Star Acquisition, which PVR consummated in the third quarter of 2008. Also, the continued successful development by producers operating in the vicinity of PVR’s systems, as well as PVR’s success in contracting and connecting new supply contributed to the increase in throughput volume.

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

During the three months ended September 30, 2008, PVR generated a majority of its gross margin from contractual arrangements under which the margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. Adjusted for the impact of derivative financial instruments, the gross margin decreased by $3.3 million, or 16%, from $20.8 million for the three months ended September 30, 2007 to $17.5 million for the same period of 2008. On a per Mcf basis, the gross margin adjusted for the impact of derivatives decreased by $0.53, or 46%, from $1.16 per Mcf in the three months ended September 30, 2007 to $0.63 per Mcf in the same period of 2008. The decrease in gross margin on a per Mcf basis was due to increased fee-based volumes associated with the Lone Star Acquisition and Crossroads plant.

The following factors played a role in the decrease in gross margin adjusted for the impact of derivatives. At PVR’s Beaver/Spearman complex, which accounts for the majority of PVR’s system throughput volumes and processed natural gas, PVR’s gross margin decreased related to NGL production and transportation issues during the three months ended September 30, 2008. During this time, PVR experienced pipeline curtailments and fractionation facilities began allocating fractionation capacity, which forced PVR to store a portion of its NGL production. These curtailments and allocations occurred downstream and were not related to PVR’s facilities. Additionally, NGLs produced during the month of September were curtailed due to flooding and damage caused by Hurricane Ike. Many of the chemical plants on the Texas and Louisiana coast remained down during the weeks following the hurricane and were unable to take fractionated products. This resulted in the curtailment of NGLs by the fractionation facilities causing PVR to reduce recoveries of NGLs from the natural gas stream. Both of these factors caused a corresponding decrease in gross margin. PVR expects all of the storage inventory at the end of the third quarter to be sold during the fourth quarter. In addition, the downstream fractionators and chemical plants are anticipated to continue their return to normal operations throughout the quarter. These factors as well as increased fee-based volumes associated with the Lone Star Acquisition and Crossroads plant contributed to the decrease in gross margin on a per Mcf basis.

Producer Services. Producer services revenues remained relatively constant from the three months ended September 30, 2007 to the same period of 2008.

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

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

Operating expenses increased by $3.0 million, or 91%, from $3.2 million in the three months ended September 30, 2007 to $6.2 million in the same period of 2008, primarily due to expenses related to PVR’s expanding footprint

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in areas of operation, including acquisitions by PVR and the addition of the Spearman and Crossroads plants. These expenses include increased repairs and maintenance expenses, increased compressor rentals, chemical and treating expenses and increased employee expenses. Taxes other than income increased by $0.2 million, or 41%, from $0.4 million in the three months ended September 30, 2007 to $0.6 million in the same period of 2008, primarily due to increased property taxes related to PVR’s acquisitions and expansion projects. General and administrative expenses increased by $0.7 million, or 22%, from $3.1 million in the three months ended September 30, 2007 to $3.8 million in the same period of 2008, primarily due to increased staffing costs and accounting and auditing fees incurred. Depreciation and amortization expenses increased by $3.3 million, or 69%, from $4.8 million in the three months ended September 30, 2007 to $8.1 million in the same period of 2008. This increase is primarily due to PVR’s acquisitions, which include the Lone Star Acquisition, and expansion capital incurred, which includes the Spearman and Crossroads plants.

Nine Months Ended September 30, 2008 Compared With the Nine Months Ended September 30, 2007

The following table sets forth a summary of certain financial and other data for the PVR natural gas midstream segment and the percentage change for the nine months ended September 30, 2008 and 2007:

	Nine Months Ended September 30,
	2008			2007			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	373,913		$	181,407		106	%
Natural gas liquids		199,053			115,660		72	%
Condensate		21,870			9,324		135	%
Gathering, processing and transportation fees		6,291			3,704		70	%
Total natural gas midstream revenues (1)		601,127			310,095		94	%
Equity earnings in equity investment		1,537			—			—
Producer services		4,921			3,143		57	%
Total revenues		607,585			313,238		94	%
Expenses
Cost of midstream gas purchased (1)		513,778			251,000		105	%
Operating		15,031			9,567		57	%
Taxes other than income		1,902			1,280		49	%
General and administrative		10,559			9,119		16	%
Depreciation and amortization		18,589			13,957		33	%
Total operating expenses		559,859			284,923		96	%
Operating income	$	47,726		$	28,315		69	%
Operating Statistics
System throughput volumes (MMcf)		68,915			50,763		36	%
System throughput volumes (MMcfd)		252			186		35	%
Gross margin	$	87,349		$	59,095		48	%
Impact of derivatives		(29,151	)		(5,531	)	427	%
Gross margin, adjusted for impact of derivatives	$	58,198		$	53,564		9	%
Gross margin ($/Mcf)	$	1.27		$	1.16		9	%
Impact of derivatives ($/Mcf)		(0.42	)		(0.11	)	282	%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.85		$	1.05		(19	)%

(1) In the nine months ended September 30, 2008, PVR recorded $105.5 million of natural gas midstream revenue and $105.5 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG and the subsequent sale of that gas to third parties. These transactions do not impact the gross margin.

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Gross Margin. Natural gas midstream revenues increased by $291.0 million, or 94%, from $310.1 million in the nine months ended September 30, 2007 to $601.1 million in the same period of 2008. Cost of midstream gas purchased increased by $262.8 million, or 105%, from $251.0 million in the nine months ended September 30, 2007 to $513.8 million in the same period of 2008. The gross margin increased by $28.2 million, or 48%, from $59.1 million in the nine months ended September 30, 2007 to $87.3 million in the same period of 2008. The gross margin increase was a result of increased commodity pricing, increased system throughput volume production and higher fractionation, or “frac” spreads during the nine months ended September 30, 2008 compared to the same period of 2007. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis.

System throughput volumes increased by 66 MMcfd, or 35%, from 186 MMcfd in the nine months ended September 30, 2007 to 252 MMcfd in the same period of 2008. This increase in throughput volumes is due primarily to the Crossroads plant in East Texas, which became fully operational in 2008, and to the Lone Star Acquisition, which PVR consummated in the third quarter of 2008. Also, the continued successful development by producers operating in the vicinity of our systems, as well as PVR’s success in contracting and connecting new supply contributed to the increase in throughput volume.

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

During the nine months ended September 30, 2008, PVR generated a majority of the gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. Adjusted for the impact of derivative financial instruments, the gross margin increased by $4.6 million, or 9%, from $53.6 million for the nine months ended September 30, 2007 to $58.2 million for the same period of 2008. On a per Mcf basis, the gross margin adjusted for the impact of derivatives decreased by $0.20, or 19%, from $1.05 per Mcf in the nine months ended September 30, 2007 to $0.85 in the same period of 2008. The decrease in gross margin on a per Mcf basis was due to increased fee-based volumes associated with the Lone Star Acquisition and Crossroads plant.

The following factors played a role in the decrease in gross margin adjusted for the impact of derivatives. At PVR’s Beaver/Spearman complex, which accounts for the majority of PVR’s system throughput volumes and processed natural gas, PVR’s gross margin decreased related to NGL production and transportation issues during the nine months ended September 30, 2008. During this time, PVR experienced pipeline curtailments and fractionation facilities began allocating fractionation capacity, which forced PVR to store a portion of its NGL production. These curtailments and allocations occurred downstream and were not related to PVR’s facilities. Additionally, NGLs produced during the month of September were curtailed due to flooding and damage caused by Hurricane Ike. Many of the chemical plants on the Texas and Louisiana coast remained down during the weeks following the hurricane and were unable to take fractionated products. This resulted in the curtailment of NGLs by the fractionation facilities causing PVR to reduce recoveries of NGLs from the natural gas stream. Both of these factors caused a corresponding decrease in gross margin. PVR expects all of the storage inventory at the end of the third quarter to be sold during the fourth quarter. In addition, the downstream fractionators and chemical plants are anticipated to continue their return to normal operations throughout the quarter. These factors as well as increased fee-based volumes associated with the Lone Star Acquisition and Crossroads plant contributed to the decrease in gross margin on a per Mcf basis.

Producer Services. Producer services revenues increased by $1.8 million, or 57%, from $3.1 million in the nine months ended September 30, 2007 to $4.9 million in the same period of 2008 primarily due to an increase in collected agent fees for the marketing of ours and others’ natural gas production.

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

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

Operating expenses increased by $5.4 million, or 57%, from $9.6 million in the nine months ended September 30, 2007 to $15.0 million in the same period of 2008, primarily due to expenses related to PVR’s expanding footprint in areas of operation, including acquisitions by PVR and the addition of the Spearman and Crossroads plants. These expenses include increased repairs and maintenance expenses, increased compressor rentals, chemical and treating expenses and increased employee expenses. Taxes other than income increased by $0.6 million, or 49%, from $1.3 million in the nine months ended September 30, 2007 to $1.9 million in the same period of 2008, primarily due to increased property taxes resulting from PVR’s acquisitions and from the construction of the Spearman and Crossroads plants, and is also due to increased payroll taxes resulting from increased staffing. General and administrative expenses increased by $1.5 million, or 16%, from $9.1 million in the nine months ended September 30, 2007 to $10.6 million in the same period of 2008 primarily due to increased staffing costs and due to accounting and auditing fees incurred. Depreciation and amortization expenses increased by $4.6 million, or 33%, from $14.0 million in the nine months ended September 30, 2007 to $18.6 million in the same period of 2008. This increase is primarily due to PVR’s acquisitions, which include the Lone Star Acquisition, and expansion capital incurred, which includes the Spearman and Crossroads plants.

Eliminations and Other

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

Corporate Operating Expenses. Corporate operating expenses primarily consist of general and administrative expenses other than from our oil and gas segment, the PVR coal and natural resource management and the PVR natural gas midstream segments. Corporate operating expenses remained relatively constant from the three months ended September 30, 2007 to the same period of 2008. Corporate operating expenses increased by $4.0 million, or 20%, from $19.8 million in the nine months ended September 30, 2007 to $23.8 million in the same period of 2008. These increases are primarily due to increased general and administrative expenses resulting from wage increases, increased consulting expenses and the recognition of additional stock-based compensation expenses. We also recognized higher depreciation expense in the nine months ended September 30, 2007 compared to the same period of 2008 due to amounts capitalized as part of a software implementation.

Interest Expense. Our consolidated interest expense increased by $1.1 million, or 10%, from $10.8 million in the three months ended September 30, 2007 to $11.9 million in the same period of 2008. Our consolidated interest expense increased by $5.7 million, or 22%, from $25.9 million in the nine months ended September 30, 2007 to $31.6 million in the same period of 2008. Our consolidated interest expense is comprised of the following:

	Three Months Ended September 30,						% Change		Nine Months Ended September 30,						% Change
Source	2008			2007					2008			2007
	(in thousands)								(in thousands)
Penn Virginia borrowings	$	(5,045	)	$	(7,213	)			$	(15,111	)	$	(17,003	)
Penn Virginia capitalized interest		492			1,048					1,555			2,965
Penn Virginia interest rate swaps		(325	)		—					(678	)		2
PVR borrowings		(6,206	)		(4,852	)				(16,828	)		(12,360	)
PVR capitalized interest		—			—					675			—
PVR interest rate swaps		(854	)		174					(1,213	)		518
Total interest expense	$	(11,938	)	$	(10,843	)	10	%	$	(31,600	)	$	(25,878	)	22	%

Total interest expense related to our borrowings, capitalized interest and interest rate swaps decreased by $1.3 million, or 21%, from $6.2 million in the three months ended September 30, 2007 to $4.9 million in the same period of 2008. This decrease is due primarily to a decrease in the effective interest rate from the three months ended September 30, 2007 to the same period of 2008. Our oil and gas segment also capitalized $0.5 million and $1.0

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million of interest in the three months ended September 30, 2008 and 2007. The borrowings and the capitalized interest for both periods were related to our oil and gas segment drilling program and unproved properties where it is anticipated exploratory and development testing will occur. In connection with periodic settlements, we recognized $0.3 million in net hedging losses on the Revolver Swaps in interest expense for the three months ended September 30, 2008.

Total interest expense related to our borrowings, capitalized interest and interest rate swaps remained relatively constant from the nine months ended September 30, 2007 to the same period of 2008. Our oil and gas segment capitalized $1.6 million and $3.0 million of interest in the nine months ended September 30, 2008 and 2007. Both the borrowings and the capitalized interest for both periods were related to our oil and gas segment drilling proram and unproved properties where it is anticipated exploratory and development testing will occur. In addition, the borrowings were also related to the $62.8 million in proved property acquisitions that we made in 2007. In connection with periodic settlements, we recognized $0.7 million in net hedging losses on the Revolver Swaps in interest expense for the nine months ended September 30, 2008.

PVR’s interest expense increased by $2.4 million, or 51%, from $4.7 million in the three months ended September 30, 2007 to $7.1 million in the same period of 2008. This increase is primarily due to the increase in PVR’s average debt balance, which increased from $295.7 million for the three months ended September 30, 2007 to $510.1 million for the same period of 2008. The increase in PVR’s average debt balance is due primarily to acquisitions and expansion activity. PVR had no capitalized interest in the three months ended September 30, 2008 and 2007. In connection with periodic settlements, PVR recognized $0.9 million in net hedging losses on the PVR Revolver Swaps in interest expense for the three months ended September 30, 2008.

PVR’s interest expense increased by $5.6 million, or 47%, from $11.8 million in the nine months ended September 30, 2007 to $17.4 million in the same period of 2008. This increase is primarily due to the increase in PVR’s average debt balance, which increased from $253.8 million for the nine months ended September 30, 2007 to $454.3 million for the same period of 2008. The increase in PVR’s average debt balance is due primarily to acquisitions and expansion activity. PVR also capitalized $0.7 million of interest costs in the nine months ended September 30, 2008 related to the construction of the Spearman and Crossroads plants. PVR had no capitalized interest in the nine months ended September 30, 2007. In connection with periodic settlements, PVR recognized $1.2 million in net hedging losses on the PVR Revolver Swaps in interest expense for the nine months ended September 30, 2008.

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

In the three months ended September 30, 2008, consolidated derivative gains were $125.1 million for changes in fair value. Cash paid for settlements totaled $19.8 million for the three months ended September 30, 2008. The derivative expenses in the three months ended September 30, 2007 were $4.5 million for changes in fair value. Cash received for settlements totaled $0.6 million for the three months ended September 30, 2007.

In the nine months ended September 30, 2008, consolidated derivative expenses were $4.4 million for changes in fair value. Cash paid for settlements totaled $46.7 million for the nine months ended September 30, 2008. The derivative expenses in the nine months ended September 30, 2007 were $22.1 million for changes in fair value. Cash received for settlements totaled $2.3 million for the nine months ended September 30, 2007.

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Our consolidated derivative activity is summarized below:

	Three Months Ended September 30,						%		Nine Months Ended September 30,						%
	2008			2007			Change		2008			2007			Change
	(in thousands)								(in thousands)
Oil and gas segment unrealized derivative gain (loss)	$	115,091		$	987		11561	%	$	15,498		$	(12,385	)	(225	)%
Oil and gas segment realized gain (loss)		(5,701	)		5,288		(208	)%		(13,461	)		11,244		(220	)%
PVR unrealized derivative gain (loss)		29,796			(6,028	)	(594	)%		26,855			(11,964	)	(324	)%
PVR realized loss		(14,054	)		(4,702	)	199	%		(33,279	)		(8,963	)	271	%
Total derivative gain (loss)	$	125,132		$	(4,455	)	(2909	)%	$	(4,387	)	$	(22,068	)	(80	)%

Minority Interest. Minority interest primarily represents PVR’s net income allocated to the limited partner units owned by the public. In the three months ended September 30, 2007 and 2008, minority interest reduced our consolidated income from operations by $28.3 million and $9.1 million. In the nine months ended September 30, 2007 and 2008, minority interest reduced our consolidated income from operations by $52.3 million and $27.7 million. The increase in minority interest for the three months ended September 30, 2008 compared to the same period in 2007 was primarily due to the increase in PVR’s net income from $16.7 million to $44.6 million. The increase in minority interest for the nine months ended September 30, 2008 and 2007 was primarily due to the increase in PVR’s net income from $49.7 million to $88.6 million.

Summary of Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. We consider the following to be the most critical accounting policies which involve the judgment of our management.

Oil and Gas Reserves

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

Proved reserves are the estimated quantities of crude oil, condensate and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those quantities that require additional capital investment through drilling or well recompletion techniques.

There are several factors which could change our estimates of oil and gas reserves. Significant rises or declines in product prices could lead to changes in the amount of reserves as production activities become more or less economical. An additional factor that could result in a change of recorded reserves is the reservoir decline rates differing from those assumed when the reserves were initially recorded. Estimation of future production and development costs is also subject to change partially due to factors beyond our control, such as energy costs and inflation or deflation of oil field service costs. Additionally, we perform impairment tests pursuant to SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, when significant events occur, such as a market move to a lower price environment or a material revision to our reserve estimates.

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Oil and Gas Revenues

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

Natural Gas Midstream Revenues

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

Coal Royalties Revenues

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

Depletion

We determine depreciation and depletion of oil and gas producing properties by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves.

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

Derivative Activities

Until 2006, we used hedge accounting for commodity derivative financial instruments as allowed under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Our commodity derivative financial instruments initially qualified as cash flow hedges, and changes in fair value from these contracts were deferred in accumulated other comprehensive income until the hedged transactions settled. When we discontinued hedge accounting for commodity derivatives in 2006, a net loss remained in accumulated other comprehensive income. As

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the hedged transactions settled in 2006 and 2007, we and PVR recognized the deferred changes in fair value in revenues and cost of gas purchased in our consolidated statements of income. As of September 30, 2008, PVR had $0.9 million of losses remaining in accumulated other comprehensive income, net of related income taxes of $0.5 million. PVR will recognize these hedging losses during the remainder of 2008 as the hedged transactions settle.

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

Equity Investments

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

Oil and Gas Properties

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

A portion of the carrying value of our oil and gas properties is attributable to unproved properties. At September 30, 2008, the costs attributable to unproved properties were $189.1 million. We regularly assess on a property-by-property basis the impairment of individual unproved properties whose acquisition costs are relatively significant. Unproved properties whose acquisition costs are not relatively significant are amortized in the aggregate over the lesser of five years or the average remaining lease term. As exploration work progresses and the reserves on significant properties are proven, capitalized costs of these properties will be subject to depreciation and depletion. If the exploration work is unsuccessful, the capitalized costs of the properties related to the unsuccessful work will be expensed. The timing of any write-downs of these unproven properties, if warranted, depends upon the nature, timing and extent of future exploration and development activities and their results.

Fair Value Measurements

We adopted SFAS No. 157, Fair Value Measurements, effective January 1, 2008, for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. FASB Staff Position FAS

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157-2, Effective Date of FASB Statement No. 157, delays the application of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities to fiscal years and interim periods beginning after November 15, 2008.

SFAS No. 157 requires fair value measurements to be classified and disclosed in one of the following three categories:

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

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

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

We use the following methods and assumptions to estimate the fair values of financial instruments:

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

• Commodity derivative instruments: Our oil and gas commodity derivatives consist of costless collars, swaps and three-way option derivative contracts, while PVR utilizes costless collars, three-way collars and swap derivative contracts in its natural gas midstream segment. We determine the fair values of our oil and gas commodity derivative agreements based on third-party forward price quotes for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices. PVR determines the fair values its commodity derivative agreements based on forward price quotes for the respective commodities. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. Each of these is a level 2 input. See Note 8 — Derivative Instruments in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements.”

• Interest rate swaps: We have entered into the Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. PVR has entered into interest the PVR Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. Each of these is a level 2 input. See Note 8 — Derivative Instruments in the Notes to Consolidated Financial Statements in Item 1, “Financial Statements.”

Gain on Sale of Subsidiary Units

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

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

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

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

As of September 30, 2008 and December 31, 2007, PVR’s environmental liabilities included $1.2 million and $1.5 million, which represents PVR’s best estimate of the liabilities as of those dates related to its coal and natural resource management and natural gas midstream businesses. PVR has reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

Recent Accounting Pronouncements

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

Forward-Looking Statements

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

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

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

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

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

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

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

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

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

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

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

• operating risks, including unanticipated geological problems, incidental to our business and to PVR’s coal or natural gas midstream business;

• PVR’s ability to acquire new coal reserves or natural gas midstream assets and new sources of natural gas supply and connections to third-party pipelines on satisfactory terms;

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

• the ability of PVR’s lessees to produce sufficient quantities of coal on an economic basis from PVR’s reserves and obtain favorable contracts for such production;

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

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

• environmental risks affecting the drilling and producing of oil and gas wells, the mining of coal reserves or the production, gathering and processing of natural gas;

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

• hedging results;

• accidents;

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

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

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

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

• other risks set forth in Item 1A, “Risk Factors,” of this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2007. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

Item 3 Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are natural gas, NGL, crude oil and coal price risks and interest rate risk.

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

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As a result of our and PVR’s price risk management and interest rate risk management activities as discussed below, we are also exposed to counterparty risk with financial institutions with whom we enter into these risk management positions. Sensitivity to these risks have heightened due to the recent disruption in the domestic and international credit markets. We did not believe we had significant risk in the financial stability of our counterparties at the time of this report.

Price Risk Management

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

For the nine months ended September 30, 2008, we reported consolidated net derivative expenses of $3.1 million. Until 2006, we used hedge accounting for commodity derivative financial instruments as allowed under SFAS No. 133. Our commodity derivative financial instruments initially qualified as cash flow hedges, and changes in fair value from these contracts were deferred in accumulated other comprehensive income until the hedged transactions settled. When we discontinued hedge accounting in 2006, a net loss remained in accumulated other comprehensive income. As the hedged transactions settled in 2006 and 2007, we and PVR recognized the deferred changes in fair value in revenues and cost of gas purchased in our consolidated statements of income. As of September 30, 2008, PVR had $0.9 million of net losses remaining in accumulated other comprehensive income, net of related income taxes of $0.5 million. PVR will recognize these hedging losses during the remainder of 2008 as the hedged transactions settle.

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

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Oil and Gas Segment

The following tables list our derivative agreements and their fair values as of September 30, 2008:

		Weighted Average Price						Estimated Fair Value (in thousands)
	Average Volume Per Day	Additional Put Option		Floor		Ceiling
	(in MMBtus)	(per MMBtu)
Natural Gas Costless Collars
Fourth Quarter 2008 (1)	10,000			$	7.50	$	9.10	$	(2,220	)
	(in MMBtus)	(per MMBtu)
Natural Gas Three-Way Collars
Fourth Quarter 2008	67,500	$	5.89	$	8.55	$	11.26		3,050
First Quarter 2009	65,000	$	6.00	$	8.67	$	11.68		5,830
Second Quarter 2009	40,000	$	6.38	$	8.75	$	10.79		3,039
Third Quarter 2009	40,000	$	6.38	$	8.75	$	10.79		2,303
Fourth Quarter 2009	30,000	$	6.83	$	9.50	$	13.60		2,625
First Quarter 2010	30,000	$	6.83	$	9.50	$	13.60		1,862
	(in MMBtus)	(per MMBtu)
Natural Gas Basis Swaps
Fourth Quarter 2008	15,000			$	0.39				179
	(in barrels)	(per barrel)
Crude Oil Three-Way Collars
Fourth Quarter 2008	500	$	80.00	$	110.00	$	179.00		547
First Quarter 2009	500	$	80.00	$	110.00	$	179.00		576
Second Quarter 2009	500	$	80.00	$	110.00	$	179.00		551
Third Quarter 2009	500	$	80.00	$	110.00	$	179.00		517
Fourth Quarter 2009	500	$	80.00	$	110.00	$	179.00		481
Oil and gas segment commodity derivatives - net asset								$	19,340

(1) This position expires in October 2008.

Our management estimates that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, oil and gas segment operating income for the last three months of 2008 would increase or decrease by approximately $1.4 million. In addition, our management estimates that for every $5.00 per barrel increase or decrease in the oil prices, oil and gas segment operating income would increase or decrease by approximately $1.8 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at forecasted levels. These estimated changes in gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

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PVR Natural Gas Midstream Segment

The following table lists PVR’s derivative agreements and their fair values as of September 30, 2008:

				Weighted Average Price Collars						Fair Value (in thousands)
	Average Volume Per Day	Weighted Average Price		Additional Put Option		Put		Call
	(in MMBtu)	(per MMBtu)
Frac Spread
Fourth Quarter 2008	7,824	$	5.02							$	(2,805	)
	(in gallons)	(per gallon)
Ethane Sale Swap
Fourth Quarter 2008	34,440	$	0.4700								(706	)
	(in gallons)	(per gallon)
Propane Sale Swaps
Fourth Quarter 2008	26,040	$	0.7175								(1,751	)
	(in barrels)	(per barrel)
Crude Oil Sale Swaps
Fourth Quarter 2008	560	$	49.27								(2,611	)
	(in gallons)					(per gallon)
Natural Gasoline Collar
Fourth Quarter 2008	6,300					$	1.4800	$	1.6465		(266	)
	(in barrels)					(per barrel)
Crude Oil Collar
Fourth Quarter 2008	400					$	65.00	$	75.25		(936	)
	(in MMBtu)	(per MMBtu)
Natural Gas Sale Swaps
Fourth Quarter 2008	4,000	$	6.97								219
	(in barrels)					(per barrel)
Crude Oil Three-Way Collar
First Quarter 2009 through Fourth Quarter 2009	1,000			$	70.00	$	90.00	$	119.25		(1,128	)
	(in MMBtu)					(per MMBtu)
Frac Spread Collar
First Quarter 2009 through Fourth Quarter 2009	6,000					$	9.09	$	13.94		1,435
Settlements to be paid in subsequent period											(3,186	)
Natural gas midstream segment commodity derivatives - net liability										$	(11,735	)

Our management estimates that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, natural gas midstream gross margin and operating income for the last three months of 2008 would increase or decrease by approximately $1.4 million. In addition, our management estimates that for every $5.00 per barrel increase or decrease in the oil price, natural gas midstream gross margin and operating income would increase or decrease by approximately $1.8 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at forecasted levels. These estimated changes in gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk Management

As of September 30, 2008, we had $180.0 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Revolver Swaps to effectively convert the interest rate on $50.0 million of the amount outstanding under the Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 5.34% plus the applicable margin until December 2010. The Revolver Swaps are accounted for as cash flow hedges in accordance with SFAS No. 133. A 1% increase in short-term interest rates on the floating rate debt outstanding under the Revolver (net of amounts fixed through hedging transactions) at September 30, 2008 would cost us approximately $1.3 million in additional interest expense.

As of September 30, 2008, PVR had $558.1 million of outstanding indebtedness under the PVR Revolver, which carries a variable interest rate throughout its term. PVR entered into the PVR Revolver Swaps to effectively convert the interest rate on $210.0 million of the amount outstanding under the PVR Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.23% plus the applicable margin until March 2010. From March 2010 to December 2011, the PVR Revolver Swaps will effectively convert the interest rate on $150.0 million of the amount outstanding under the PVR Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.23% 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 September 30, 2008 would cost us approximately $3.5 million in additional interest expense.

Item 4 Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of September 30, 2008. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of September 30, 2008, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

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

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PART II. OTHER INFORMATION

Item 1 Legal Proceedings

Loadout LLC (“Loadout”), a subsidiary of PVR, holds permits to mine at the Nellis Surface Mine in Boone County, West Virginia. The permits have been assigned to a mine operator who leases the property for mining, Coal River Mining, LLC (“Coal River”). The U.S. Army Corps of Engineers (“Corps”) issued a permit (the “Permit”) under Section 404 of the federal Clean Water Act to Loadout on April 16, 2008, authorizing the placement of fill material into certain waters of the United States in conjunction with the construction of four valley fills, three sediment pond embankments and one haul road at the Nellis Mine. On April 23, 2008, the plaintiffs in the suit Ohio Valley Environmental Coalition v. U.S. Army Corps of Engineers, No. 3:05-0784 (S.D. W. Va.) (the “OVEC suit”) filed a complaint and motion for a temporary restraining order (“TRO”) seeking to suspend or revoke the Permit, alleging, among other things, violations by the Corps of the National Environmental Policy Act and Clean Water Act. The plaintiffs subsequently filed a motion to withdraw their motion for a TRO, pending good-faith negotiations between the plaintiffs, Loadout, and Coal River to reach an agreement over the Permit. In September, those parties terminated negotiations without resolution, and in October, Loadout and Coal River filed a (i) formal reply in the OVEC suit, arguing against the addition of Loadout and Coal River as defendants and (ii) separate declaratory action to validate the issuance of the Permit. Because of the limited volume of projected coal to be produced from the Nellis Surface Mine relative to total production from all our holdings, it is not expected that either a settlement of this matter or a possible delay in proceeding with mining pending litigation would materially affect our business interests.

Item 1A Risk Factors

The following is an update to Item 1A — Risk Factors contained in our 2007 Annual Report on Form 10-K. For additional risk factors that could cause actual results to differ materially from those anticipated, please refer to our 2007 Annual Report

on Form 10-K.

The current deterioration of the credit and capital markets may adversely impact our ability to obtain financing on acceptable terms or obtain funding under the Revolver. This may hinder or prevent us from implementing our development plan, completing acquisitions or otherwise meeting our future capital needs.

Global financial markets have been experiencing extreme volatility and disruption, and the debt and equity capital markets have been exceedingly distressed. These issues have made, and will likely continue to make, it difficult to obtain financing. In particular, the cost of raising money in the equity capital markets has increased substantially while the availability of funds from those markets has diminished significantly. The current global economic downturn may adversely impact our ability to issue additional equity in the future at prices which will not be dilutive to our existing shareholders or preclude us from issuing equity at all.

Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers. Moreover, even if lenders and institutional investors are willing and able to provide adequate funding, interest rates may rise in the future and therefore increase the cost of borrowing we incur on any of our floating rate debt. In addition, we may be unable to obtain adequate funding under the Revolver because (i) our lending counterparties may be unwilling or unable to meet their funding obligations or (ii) our borrowing base is re-determined twice a year and may decrease as a result of lower oil or natural gas prices and declines in reserves.

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, it might adversely affect our development plan as currently anticipated and our ability to complete acquisitions each of which could have a material adverse effect on our production, revenues and results of operations.

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Item 6 Exhibits

10.1	Penn Virginia Corporation Fifth Amended and Restated 1999 Employee Stock Incentive Plan.
10.2	Amended and Restated Executive Change of Control Severance Agreement dated October 17, 2008 between Penn Virginia Corporation and A. James Dearlove (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on October 22, 2008).
10.3	Amended and Restated Executive Change of Control Severance Agreement dated October 17, 2008 between Penn Virginia Corporation and Frank A. Pici (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on October 22, 2008).
10.4	Amended and Restated Executive Change of Control Severance Agreement dated October 17, 2008 between Penn Virginia Corporation and Nancy M. Snyder (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed on October 22, 2008).
10.5	Amended and Restated Executive Change of Control Severance Agreement dated October 17, 2008 between Penn Virginia Corporation and H. Baird Whitehead (incorporated by reference to Exhibit 10.4 to Registrant’s Current Report on Form 8-K filed on October 22, 2008).
10.6	Amended and Restated Executive Change of Control Severance Agreement dated October 17, 2008 between Penn Virginia Resource GP, LLC and Keith D. Horton (incorporated by reference to Exhibit 10.1 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on October 22, 2008).
10.7	Amended and Restated Executive Change of Control Severance Agreement dated October 17, 2008 between Penn Virginia Resource GP, LLC and Ronald K. Page (incorporated by reference to Exhibit 10.2 to Penn Virginia Resource Partners, L.P.’s Current Report on Form 8-K filed on October 22, 2008).
10.8	Change of Location Severance Agreement dated November 5, 2008 between Penn Virginia Corporation and Nancy M. Snyder.
10.9	Penn Virginia Corporation and Affiliated Companies’ Employees’ 401(k) Plan (incorporated by reference to Exhibit 10.5 to Registrant’s Current Report on Form 8-K filed on October 22, 2008).
12.1	Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.
31.1	Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURES

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

		PENN VIRGINIA CORPORATION
Date: November 6, 2008	By:	/s/    Frank A. Pici
		Frank A. Pici
		Executive Vice President and Chief Financial Officer
Date: November 6, 2008	By:	/s/    Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller