Ranger Oil (ROCC) 8-K Entry into a Material Definitive Agreement

Exhibit 99.2

Report of independent registered public accounting firm

The Board of Directors and Shareholders

Penn Virginia Corporation:

We have audited the accompanying consolidated balance sheets of Penn Virginia Corporation, a Virginia corporation, and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of income, shareholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2008. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Penn Virginia Corporation and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 3 to the consolidated financial statements, effective January 1, 2007, the Company changed its method of accounting for income tax uncertainties.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Penn Virginia Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 27, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 27, 2009, except for Note 24

to the consolidated financial statements,

as to which the date is June 2, 2009

Penn Virginia Corporation and Subsidiaries

Consolidated statements of income

	Year ended December 31,
(in thousands, except per share data)	2008			2007			2006
Revenues
Natural gas	$	368,801		$	262,169		$	212,919
Crude oil		46,529			22,439			17,634
Natural gas liquids		21,292			5,678			3,603
Natural gas midstream		589,783			433,174			402,715
Coal royalties		122,834			94,140			98,163
Gain on sales of property and equipment		31,426			12,416			—
Other		40,186			22,934			18,895
Total revenues		1,220,851			852,950			753,929
Expenses
Cost of midstream gas purchased		484,621			343,293			334,594
Operating		89,891			67,610			47,406
Exploration		42,436			28,608			34,330
Taxes other than income		28,586			21,723			14,767
General and administrative		74,494			66,983			49,566
Impairments		51,764			2,586			8,517
Depreciation, depletion and amortization		192,236			129,523			94,217
Total expenses		964,028			660,326			583,397
Operating income		256,823			192,624			170,532
Other income (expense)
Interest expense		(44,261	)		(37,419	)		(24,832	)
Other		(666	)		3,651			3,718
Derivatives		46,582			(47,282	)		19,497
Income before minority interest and income taxes		258,478			111,574			168,915
Minority interest		60,436			30,319			43,018
Income tax expense		73,874			30,501			49,988
Net income	$	124,168		$	50,754		$	75,909
Net income per share, basic	$	2.97		$	1.33		$	2.03
Net income per share, diluted	$	2.95		$	1.32		$	2.01
Weighted average shares outstanding, basic		41,760			38,061			37,362
Weighted average shares outstanding, diluted		42,031			38,358			37,732

See accompanying notes to consolidated financial statements.

2

Penn Virginia Corporation and Subsidiaries

Consolidated balance sheets

(in thousands)	As of December 31,
	2008			2007
Assets
Current assets
Cash and cash equivalents	$	18,338		$	34,527
Accounts receivable, net of allowance for doubtful accounts		149,241			179,120
Deferred income taxes		—			16,273
Derivative assets		67,569			5,683
Inventory		18,468			5,194
Other		9,902			3,275
Total current assets		263,518			244,072
Property and equipment
Oil and gas properties (successful efforts method)		2,106,126			1,525,728
Other property and equipment		1,076,471			859,380
		3,182,597			2,385,108
Accumulated depreciation, depletion and amortization		(671,422	)		(486,094	)
Net property and equipment		2,511,175			1,899,014
Equity investments		78,443			25,640
Goodwill		—			7,718
Intangible assets, net		92,672			28,938
Derivative assets		4,070			310
Other assets		46,674			47,769
Total assets	$	2,996,552		$	2,253,461
Liabilities and Shareholders’ Equity
Current liabilities
Short-term borrowings	$	7,542		$	12,561
Accounts payable and accrued liabilities		206,902			205,127
Derivative liabilities		15,534			43,048
Deferred taxes		17,598			—
Income taxes payable		18			1,163
Total current liabilities		247,594			261,899
Other liabilities		45,887			54,169
Derivative liabilities		8,721			3,030
Deferred income taxes		245,789			193,950
Long-term debt of the Company		562,000			352,000
Long-term debt of PVR		568,100			399,153
Minority interests of subsidiaries		299,671			179,162
Commitments and contingencies (see Note 23)
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; 41,870,893 and 41,408,497 shares issued and outstanding at December 31, 2008 and December 31, 2007		230			225
Paid-in capital		578,639			485,998
Retained earnings		446,993			332,223
Deferred compensation obligation		2,237			1,608
Accumulated other comprehensive income		(6,626	)		(7,936	)
Treasury stock—95,378 and 77,924 shares common stock, at cost, on December 31, 2008 and December 31, 2007		(2,683	)		(2,020	)
Total shareholders’ equity		1,018,790			810,098
Total liabilities and shareholders’ equity	$	2,996,552		$	2,253,461

See accompanying notes to consolidated financial statements.

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Penn Virginia Corporation and Subsidiaries

Consolidated statements of cash flows

	Year ended December 31,
(in thousands)	2008			2007			2006
Cash flows from operating activities
Net income	$	124,168		$	50,754		$	75,909
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		192,236			129,523			94,217
Impairments		51,764			2,586			8,517
Derivative contracts:
Total derivative losses (gains)		(41,102	)		52,157			(17,535	)
Cash paid to settle derivatives		(46,086	)		(3,651	)		(8,947	)
Deferred income taxes		60,505			23,340			38,020
Minority interest		60,436			30,319			43,018
Gain on the sale of property and equipment		(31,426	)		(12,416	)		—
Dry hole and unproved leasehold expense		35,847			24,975			24,502
Other		7,484			4,961			4,260
Changes in operating assets and liabilities:
Accounts receivable		29,418			(41,772	)		(1,770	)
Inventory		(13,440	)		(1,106	)		(659	)
Accounts payable and accrued liabilities		(31,969	)		42,733			30,116
Other assets and liabilities		(14,061	)		10,627			(13,829	)
Net cash provided by operating activities		383,774			313,030			275,819
Cash flows from investing activities
Acquisitions		(293,747	)		(292,001	)		(195,166	)
Additions to property and equipment		(585,339	)		(421,509	)		(269,773	)
Other		33,519			30,027			2,604
Net cash used in investing activities		(845,567	)		(683,483	)		(462,335	)
Cash flows from financing activities
Dividends paid		(9,398	)		(8,499	)		(8,398	)
Distributions paid to minority interest holders		(64,245	)		(49,739	)		(38,627	)
Short-term bank borrowings		7,542			—			—
Proceeds from Company borrowings		273,000			513,500			162,000
Repayments of Company borrowings		(63,000	)		(382,500	)		(20,000	)
Proceeds from PVR borrowings		453,800			220,500			85,800
Repayments of PVR borrowings		(297,800	)		(27,000	)		(122,900	)
Net proceeds from issuance of PVR partners' capital		138,141			860			117,818
Net proceeds from issuance of PVA equity		—			135,441			—
Cash received for stock warrants sold		—			18,187			—
Cash paid for convertible note hedges		—			(36,817	)		—
Other		7,564			709			5,248
Net cash provided by financing activities		445,604			384,642			180,941
Net increase (decrease) in cash and cash equivalents		(16,189	)		14,189			(5,575	)
Cash and cash equivalents—beginning of period		34,527			20,338			25,913
Cash and cash equivalents—end of period	$	18,338		$	34,527		$	20,338
Supplemental disclosures:
Cash paid for:
Interest (net of amounts capitalized)	$	43,244		$	34,794		$	23,452
Income taxes paid (refunds received)	$	15,228		$	(1,897	)	$	16,741
Noncash investing activities: (see Note 4)
Deferred tax liabilities related to acquisition, net	$	—		$	—		$	32,759
Issuance of PVR units for acquisition	$	15,171		$	—		$	—
PVG units given as consideration for acquisition	$	68,021		$	—		$	—
Other liabilities	$	4,673		$	—		$	—

See accompanying notes to consolidated financial statements.

4

Penn Virginia Corporation and Subsidiaries

Consolidated statements of shareholders’ equity and comprehensive income

(in thousands)	Shares outstanding	Common stock	Paid-in capital		Retained earnings		Deferred compensation obligation	Accumulated other comprehensive income		Treasury stock		Unearned compensation and ESOP		Total shareholders' equity		Comprehensive income (loss)
Balance at December 31, 2005	37,248	186	98,541		222,456		580	(7,816	)	(832	)	(2,807	)	310,308		$	54,992
Adoption of SFAS No. 123(R) (See Note 18)	—	—	(2,807	)	—		—	—		—		2,807		—
Dividends paid ($0.225 per share)	—	—	—		(8,398	)	—	—		—		—		(8,398	)
Sale of PVR & PVG securities	—	—	(3,560	)	—		—	—		—		—		(3,560	)
Stock issued as compensation	12	—	691		—		—	—		—		—		691
PVR units issued as compensation, net	—	—	1,229		—		—	—		—		—		1,229
Vesting of restricted units	—	—	(1,056	)	—		—	—		—		—		(1,056	)
Exercise of stock options	302	2	5,860		—		—	—		—		—		5,862
Compensation costs related to stock options	—	—	1,402		—		—	—		—		—		1,402
Deferred compensation	—	—	734		—		734	—		(817	)	—		651
Contribution to GP Holdings of investment in PVR	—	—	(475	)	—		—	—		—		—		(475	)
Net income	—	—	—		75,909		—	—		—		—		75,909		$	75,909
Other comprehensive gain, net of tax	—	—	—		—		—	1,200		—		—		1,200			1,200

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(in thousands)	Shares outstanding	Common stock	Paid-in capital		Retained earnings		Deferred compensation obligation	Accumulated other comprehensive income		Treasury stock		Unearned compensation and ESOP	Total shareholders' equity		Comprehensive income (loss)
Adoption of SFAS No. 158, net of tax (See Note 16)	—	—	—		—		—	(1,338	)	—		—	(1,338	)
Balance at December 31, 2006	37,562	188	100,559		289,967		1,314	(7,954	)	(1,649	)	—	382,425		$	77,109
Dividends paid ($0.225 per share)	—	—	—		(8,498	)	—	—		—		—	(8,498	)
Sale of PVR & PVG securities	—	—	(995	)	—		—	—		—		—	(995	)
SAB 51 gain on PVR & PVG offerings	—	—	241,736		—		—	—		—		—	241,736
Stock issued as compensation	19	—	878		—		—	—		—		—	878
PVR units issued as compensation, net	—	—	1,583		—		—	—		—		—	1,583
Vesting of restricted units	—	—	(1,099	)	—		—	—		—		—	(1,099	)
Exercise of stock options	366	2	8,791		—		—	—		—		—	8,793
Compensation costs related to stock options	—	—	2,611		—		—	—		—		—	2,611
Deferred compensation	11	—	613		—		294	—		(371	)	—	536
Common stock offering	3,450	35	131,321		—		—	—		—		—	131,356
Net income	—	—	—		50,754		—	—		—		—	50,754		$	50,754

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(in thousands)	Shares outstanding	Common stock		Paid-in capital			Retained earnings			Deferred compensation obligation		Accumulated other comprehensive income			Treasury stock			Unearned compensation and ESOP		Total shareholders' equity			Comprehensive income (loss)
Other comprehensive gain, net of tax	—		—		—			—			—		18			—			—		18			18
Balance at December 31, 2007	41,408	$	225	$	485,998		$	332,223		$	1,608	$	(7,936	)	$	(2,020	)	$	—	$	810,098		$	50,772
Dividends paid ($0.225 per share)	—		—		—			(9,398	)		—		—			—			—		(9,398	)
Sale of PVR & PVG securities	—		—		(1,700	)		—			—		—			—			—		(1,700	)
Recognition of SAB 51 gain (See Note 3)	—		—		39,723			—			—		—			—			—		39,723
Stock issued as compensation	40		—		1,258			—			—		—			(663	)		—		595
PVR units issued as compensation, net	—		—		2,231			—			—		—			—			—		2,231
Vesting of restricted units	—		—		(1,722	)		—			—		—			—			—		(1,722	)
Exercise of stock options	423		5		11,722			—			—		—			—			—		11,727
Compensation costs related to stock options	—		—		4,071			—			—		—			—			—		4,071
Deferred compensation	—		—		629			—			629		—			—			—		1,258

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(in thousands)	Shares outstanding	Common stock		Paid-in capital		Retained earnings		Deferred compensation obligation		Accumulated other comprehensive income			Treasury stock			Unearned compensation and ESOP		Total shareholders' equity		Comprehensive income (loss)
Gain on sale of subsidiary units, net of tax of $23.2 million (see Note 3)	—		—		36,429		—		—		—			—			—		36,429
Net income	—		—		—		124,168		—		—			—			—		124,168	$	124,168
Other comprehensive gain, net of tax	—		—		—		—		—		1,310			—			—		1,310		1,310
Balance at December 31, 2008	41,871	$	230	$	578,639	$	446,993	$	2,237	$	(6,626	)	$	(2,683	)	$	—	$	1,018,790	$	125,478

See accompanying notes to consolidated financial statements.

8

Penn Virginia Corporation and Subsidiaries

Notes to consolidated financial statements

1. Nature of operations

Penn Virginia Corporation (“Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company primarily engaged in the development, exploration and production of natural gas and oil in various domestic onshore regions including East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast. We also indirectly own partner interests in Penn Virginia Resource Partners, L.P. (“PVR”), a publicly traded limited partnership formed by us in 2001. Our ownership interests in PVR are held principally through our general partner 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 December 31, 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 and all of the incentive distribution rights (“IDRs”).

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

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

PVR is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. 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’s coal reserves are primarily located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. PVR also earns revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees.

PVR’s natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. PVR owns and operates natural gas midstream assets located in Oklahoma and Texas. PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, PVR owns a 25% member interest in Thunder Creek Gas Services, LLC (“Thunder Creek”), a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. PVR also owns a natural gas marketing

9

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

Principles of consolidation

Our consolidated financial statements include the accounts of Penn Virginia and all of its subsidiaries, including PVG and PVR. Intercompany balances and transactions have been eliminated in consolidation. PVR owns a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin and a 50% member interest in a coal handling joint venture. Earnings from PVR’s equity affiliates are recorded as other revenues on the consolidated statements of income and PVR’s investments in these equity affiliates are recorded on the equity investments line on the consolidated balance sheets. Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. These statements involve the use of estimates and judgments where appropriate.

Prior to PVG’s initial public offering on December 5, 2006, our ownership of PVR included our ownership of limited partner interests in PVR and our ownership of Penn Virginia Resource GP, LLC, which is PVR’s general partner and owns the IDRs in PVR. Our sole ownership of Penn Virginia Resource GP, LLC provided us with a 2% general partner interest in PVR. Our general partner interest gave us control of PVR.

PVG’s only cash-generating assets are its ownership of limited partners interests in PVR and its ownership interest in Penn Virginia Resource GP, LLC, which owns the general partner interest and IDRs in PVR. Therefore, PVG’s cash flows are dependent upon PVR’s ability to make cash distributions, and the distributions PVG receives are subject to PVR’s cash distribution policies.

The minority interests of subsidiaries on our consolidated balance sheets reflect the outside ownership interest of PVG and PVR as of December 31, 2008, 2007 and 2006. PVG’s outside ownership interest was 23% at December 31, 2008 and 18% at December 31, 2007 and 2006. PVR’s outside ownership interest was 61% at December 31, 2008 and 56% at December 31, 2007 and 2006.

Use of estimates

Preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and cash equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

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

10

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 completion 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.

The costs of unproved leaseholds, including associated interest costs for the period activities that were in progress to bring projects to their intended use, are capitalized pending the results of exploration efforts. Interest costs associated with non-producing leases were capitalized in the amounts of $2.0 million, $3.7 million and $2.8 million in 2008, 2007 and 2006. 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. As of December 31, 2008, 2007 and 2006, unproved leasehold costs amounted to $154.8 million, $127.8 million and $100.0 million.

Other property and equipment

Other property and equipment primarily consist of processing facilities, gathering systems, compressor stations, PVR’s ownership in coal fee mineral interests, PVR’s royalty interest in oil and natural gas wells, forestlands, and related equipment. Property and equipment are carried at cost and include expenditures for additions and improvements, such as roads and land improvements, which increase the productive lives of existing assets. Maintenance and repair costs are expensed as incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. We compute depreciation and amortization of property, plant and equipment using the straight-line balance method over the estimated useful life of each asset as follows:

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

Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained

11

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

Intangible assets are primarily associated with assumed contracts, customer relationships and rights-of-way. These intangible assets are amortized over periods of up to 20 years, the period in which benefits are derived from the contracts, relationships and rights-of-way, and are combined with property, plant and equipment and are reviewed for impairment under SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets. See Note 13, “Intangible Assets, net” for a more detailed description of our intangible assets.

Asset retirement obligations

In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143,Accounting for Asset Retirement Obligations, we recognize the fair value of a liability for an ARO in the period in which it is incurred. The determination of fair value is based upon regional market and specific facility type information. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. See Note 16—“Asset Retirement Obligations.” The long-lived assets for which our AROs are recorded include natural gas processing facilities, compressor stations, gathering systems, coal processing plants and wells. The amount of an ARO and the costs capitalized equal the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed rate, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion and the depreciation are included in depreciation, depletion and amortization (“DD&A”) expense on our consolidated statements of income.

In connection with PVR’s natural gas midstream assets, we are obligated under federal regulations to perform limited procedures around the abandonment of pipelines. We are unable to reasonably determine the fair value of such ARO because the settlement dates, or ranges thereof, are indeterminable. An ARO will be recorded in the period in which we can reasonably determine the settlement dates.

Impairment of long-lived assets

We review long-lived assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. We recognize an impairment loss

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

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

The PVR natural gas midstream segment has completed a number of acquisitions in recent years. See Note 4, “Acquisitions and Divestitures,” for a description of the PVR natural gas midstream segment’s material acquisitions. In conjunction with our accounting for these acquisitions, it was necessary for PVR to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Changes in operations, further decreases in commodity prices, changes in the business environment or further deteriorations of market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. If these events occur, it is reasonably possible we could have a significant impairment charge to be recorded in our consolidated statements of income.

For the years ended December 31, 2008, 2007 and 2006, we recorded impairment charges related to our oil and gas segment properties of $20.0 million, $2.6 million and $8.5 million. See Note 14—“Impairment of Oil and Gas Properties.”

Impairment of goodwill

Goodwill has been allocated to the PVR natural gas midstream segment. Under SFAS No. 141,Business Combinations, and SFAS No. 142,Goodwill and Other Intangible Assets, goodwill recorded in connection with a business combination is not amortized, but tested for impairment at least annually.

Goodwill impairment is determined using a two-step test. The first step of the impairment test is used to identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value of a reporting unit exceeds its book value, goodwill of the reporting unit is not considered impaired, and the second step of the impairment test is not required. If the book value of a reporting unit exceeds its fair value, the second step of the impairment test is performed to measure the amount of impairment loss, if any. The second step of the impairment test compares the implied fair value of the reporting unit’s goodwill with the

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book value of that goodwill. If the book value of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. The annual impairment testing is performed in the fourth quarter.

Management uses a number of different criteria when evaluating goodwill for possible impairment. Indicators such as significant decreases in a reporting unit’s book value, decreases in cash flows, sustained operating losses, a sustained decrease in market capitalization, adverse changes in the business climate, legal matters, losses of significant customers and new technologies which could accelerate obsolescence of business products are used by management when performing evaluations. We tested goodwill for impairment during the fourth quarter of 2008 and recorded an impairment charge of $31.8 million. As a result of this impairment charge, we did not have a balance in goodwill at December 31, 2008. We had a $7.7 million balance in goodwill at December 31, 2007. See Note 12, “Goodwill.”

Environmental liabilities

Other liabilities include accruals for environmental liabilities that we either assumed in connection with certain acquisitions or recorded in operating expenses when it became probable that a liability had been incurred and the amount of that liability could be reasonably estimated.

Concentration of credit risk

Approximately 57% of our consolidated accounts receivable at December 31, 2008 resulted from our oil and gas segment, approximately 33% resulted from the PVR natural gas midstream segment and approximately 10% resulted from the PVR coal and natural resource management segment. Approximately 46% of PVR’s natural gas midstream segment accounts receivables and 16% of our consolidated accounts receivable at December 31, 2008 related to three natural gas midstream customers. Approximately $20.3 million of our oil and gas segment trade receivables at December 31, 2008 were related to three customers. Approximately 24% of our oil and gas segment’s receivables and 14% of our consolidated receivables at December 31, 2008 related to these three oil and gas customers. No significant uncertainties related to the collectability of amounts owed to us or PVR exists in regards to these natural gas midstream segment or these oil and gas segment customers. As of December 31, 2008, no receivables were collateralized, and we recorded a $1.0 million allowance for doubtful accounts in the oil and gas segment and a $1.4 million allowance for doubtful accounts in the PVR natural gas midstream segment.

At December 31, 2008, PVR reported a net commodity derivative asset related to the natural gas midstream segment of $22.7 million that is with two counterparties and is substantially concentrated with one of those counterparties. We reported a net commodity derivative asset related to our oil and gas segment of $41.2 million, 72% of which was concentrated with three counterparties. These concentrations may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. Neither we nor PVR paid nor received collateral with respect to our derivative positions. No significant uncertainties related to the collectability of amounts owed to us or PVR exists with regard to these counterparties.

These concentrations may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions.

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Revenues

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.

Derivative activities

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

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Until April 30, 2006, we applied 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 of the effective portion of these contracts were deferred in accumulated other comprehensive income (“AOCI”) until the hedged transactions settled. When we discontinued hedge accounting for commodity derivatives, a net loss remained in AOCI of $12.1 million. As the hedged transactions settled in 2006, 2007 and 2008, we and PVR recognized the $12.1 million of deferred changes in fair value in revenues and cost of gas purchased in our consolidated statements of income related to commodity derivatives. As of December 31, 2008, all amounts deferred under previous commodity hedging relationships have been reclassified into revenues and cost of midstream gas purchased.

PVR continues to apply hedge accounting to some of its interest rate hedges. Settlements on the PVR interest rate swap agreements (the “PVR Interest Rate Swaps”) that follow hedge accounting are recorded as interest expense. The effective portion of the change in the fair value of the swaps that follow hedge accounting are recorded each period in AOCI. Certain of the PVR Interest Rate Swaps do not follow hedge accounting. Accordingly, mark-to-market gains and losses for the PVR Interest Rate Swaps that do not follow hedge accounting are recognized in earnings currently in the Derivatives line on the consolidated statements of income.

Because we no longer apply hedge accounting for our commodity derivatives, we recognize changes in fair value in earnings currently in the derivatives line on the consolidated statements of income. We have experienced and could continue to experience significant changes in the estimate of unrealized derivative gains or losses recognized due to fluctuations in the value of these commodity derivative contracts. The discontinuation of hedge accounting has no impact on our reported cash flows, although our results of operations are affected by the volatility of mark-to-market gains and losses and changes in fair value, which fluctuate with changes in natural gas, crude oil and NGL prices. These fluctuations could be significant in a volatile pricing environment.

During the year ended December 31, 2008, we reclassified a total of $8.2 million from AOCI to earnings related to our and PVR’s commodity derivatives and our and PVR’s Interest Rate Swaps. At December 31, 2008, a $1.2 million loss remained in AOCI related to PVR Interest Rate Swaps on which PVR discontinued hedge accounting. The $1.2 million loss will be recognized in earnings through the end of 2011 as the hedged transactions settle. See Note 8—“Derivative Instruments,” for a more detailed description of our and PVR’s derivative programs.

Stock-based compensation

We have several stock compensation plans that allow incentive and nonqualified stock options and restricted stock to be granted to key employees and officers and nonqualified stock options and deferred common stock units to be granted to directors. The general partners of PVG and PVR both have long-term incentive plans that permit the granting of awards to their directors and employees and employees of their affiliates who perform services for PVG and PVR.

We and PVR account for stock-based compensation in accordance with SFAS No. 123 (R),Share-Based Payment,which establishes standards for transactions in which an entity exchanges its equity instruments for goods and services. This standard requires us and PVR to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. See Note 21—“Share-Based Payments.”

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Income taxes

We account for income taxes in accordance with the provisions of SFAS No. 109,Accounting for Income Taxes, which requires a company to recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in a company’s financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates. We now recognize interest related to unrecognized tax benefits in interest expense, and penalties are included in income tax accrued. See Note 19, “Income Taxes.”

Accounting for uncertainty in income taxes

We adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48,Accounting for Uncertainty in Income Taxes,an interpretation of FASB Statement No. 109 (“FIN 48”) as of January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We also adopted FASB Staff Position No. FIN 48–1,Definition of Settlement in FASB Interpretation No. 48 (“FSP FIN 48–1”) as of January 1, 2007. FSP FIN 48–1 provides that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal and it is remote that the taxing authority would reexamine the tax position in the future. The adoption of FIN 48 did not result in a transition adjustment to retained earnings; instead, $8.7 million was reclassified from deferred income taxes to a long-term liability. See Note 19—“Income Taxes.”

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, with a corresponding entry to minority interest. See Note 6—“PVR Unit Offering.”

In addition, we recognized a $36.4 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. (“Lone Star”). See Note 4—“Acquisitions and Divestitures.”

New accounting standards

In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations(“SFAS No. 141(R)”). SFAS No. 141(R) provides companies with principles and requirements on how an

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acquirer recognizes and measures in its financial statements the identifiable assets acquired, liabilities assumed and any noncontrolling interest in the acquiree as well as the recognition and measurement of goodwill acquired or a gain from a bargain purchase in a business combination. SFAS No. 141(R) also requires certain disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination. Acquisition costs associated with the business combination will generally be expensed as incurred. In addition, changes in an acquired entity’s valuation allowance for deferred tax assets and uncertain tax positions after the measurement period will be recorded in income tax expense. SFAS No. 141(R) became effective on January 1, 2009.

In December 2007, the FASB issued 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 statements of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS No. 160 also requires that gains from the sales of subsidiary stock be recorded directly to shareholders’ equity. If we sell sufficient controlling interest in our subsidiaries to require deconsolidation of those subsidiaries, then we expect to record a gain or loss on our consolidated statements of income. SFAS No. 160 became effective January 1, 2009 and will result in the classification of minority interest in PVG and PVR to be recorded as a component of shareholders’ equity. Net income and comprehensive income attributable to the noncontrolling interest will be separately presented on the face of the consolidated statements of income and consolidated statement of shareholders’ equity and comprehensive income, applied retrospectively for all periods presented.

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. 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. The adoption of FSP APB 14-1 will result in increased interest expense of approximately $8.0 million to $12.0 million for 2009. Beginning with the first quarter of 2009, we will recast our financial statements

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to retroactively apply the increase in interest expense resulting from the adoption to all periods presented. See Note 19—“Long-Term Debt” for a discussion of our convertible notes.

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 (“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 and divestitures

In the following paragraphs, all references to coal, crude oil and natural gas reserves and acreage acquired are unaudited. The factors we used to determine the fair market value of acquisitions include, but are not limited to, discounted future net cash flows on a risked-adjusted basis, geographic location, quality of resources, potential marketability and financial condition of lessees.

Business combination

Lone Star Gathering, L.P.

On July 17, 2008, PVR completed an acquisition of substantially all of the assets of Lone Star. 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 of PVG common units (which PVR purchased from two subsidiaries of ours 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 common units, at PVR’s election.

The Lone Star acquisition has been accounted for using the purchase method of accounting in accordance with SFAS No. 141,Business Combinations. Under the purchase method of

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accounting, the total purchase price has been allocated to the net tangible and intangible assets acquired from Lone Star based on their estimated fair values. The total purchase price was allocated to the assets purchased based upon fair values on the date of the Lone Star acquisition as follows:

Cash consideration paid for Lone Star	$    81,125
Fair value of PVG common units given as consideration for Lone Star	68,021
Fair value of PVR common units issued and given as consideration for Lone Star	15,171
Payment guaranteed December 31, 2009	4,673
Total purchase price	$  168,990
Fair value of assets acquired:
Property and equipment	$    88,596
Intangible assets	69,200
Goodwill	11,194
Fair value of assets acquired	$  168,990

The purchase price includes approximately $11.2 million of goodwill, all of which has been allocated to the PVR natural gas midstream segment. A significant factor that contributed to the recognition of goodwill includes the ability to acquire an established business on the western border of the expanding Barnett Shale play in the Fort Worth Basin. Under SFAS No. 141 and SFAS 142,Goodwill and Other Intangible Assets,goodwill recorded in connection with a business combination is not amortized, but is tested for impairment at least annually. Accordingly, the accompanying pro forma combined income statement does not include amortization of the goodwill recorded in the acquisition. As a result of testing goodwill for impairment in the fourth quarter of 2008, we recognized a loss on impairment of goodwill. See Note 12, “Goodwill” for a description of our goodwill impairment.

The purchase price includes approximately $69.2 million of intangible assets that are associated with assumed contracts and customer relationships. These intangible assets will be amortized over the period in which benefits are derived from the contracts and relationships assumed and will be reviewed for impairment under SFAS No. 144,Accounting for the Impairment or Disposalof Long-Lived Assets.Based on when the estimated economic benefit will be earned, we have estimated the useful lives of these intangible assets to be 20 years. See Note 13, “Intangible Assets, net.”

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The following pro forma financial information reflects the consolidated results of our operations as if the Lone Star acquisition had occurred on January 1, 2007. The pro forma information includes adjustments primarily for depreciation of acquired property and equipment, the amortization of intangible assets, interest expense for acquisition debt and the change in weighted average common units resulting from the issuance of 542,610 of PVR’s newly issued common units given as consideration in the Lone Star acquisition. The pro forma financial information is not necessarily indicative of the results of operations as it would have been had these transactions been effected on the assumed date:

(in thousands)	Year ended December 31,
	2008		2007
	(Unaudited)
Revenues	$	1,224,418	$	855,944
Net income	$	121,533	$	47,016
Net income per limited partner unit, basic	$	2.91	$	1.24
Net income per limited partner unit, diluted	$	2.88	$	1.22

Other business combinations

In April 2008, PVR acquired a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. The purchase price was $51.6 million in cash, after customary closing adjustments and was funded with long-term debt under the PVR Revolver. The entire member interest is recorded in equity investments on the consolidated balance sheets. 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, which is 12 years. The earnings are recorded in other revenues on our consolidated statements of income.

In October 2007, we acquired lease rights to property covering 4,800 acres located in East Texas, with estimated proved reserves of 21.9 Bcfe. The purchase price was $44.9 million in cash and was funded with long-term debt under the our revolving credit facility (the “Revolver”).

In September 2007, PVR acquired fee ownership of approximately 62,000 acres of forestland in northern West Virginia. The purchase price was $93.3 million in cash and was funded with long-term debt under the PVR Revolver. The purchase price has been allocated as follows: $86.1 million to timber, $6.6 million to land and $0.6 million to oil and gas royalty interests.

In August 2007, we acquired the lease rights to property covering approximately 22,700 acres located in eastern Oklahoma with estimated proved reserves of 18.8 Bcfe. The purchase price was $47.9 million in cash and was funded with long-term debt under the Revolver. We acquired these assets in order to expand our oil and gas segment business. The acquisition has been recorded as a component of oil and gas properties.

In June 2007, PVR acquired a combination of fee ownership and lease rights to approximately 51 million tons of coal reserves, along with a preparation plant and coal handling facilities. The property is located on approximately 17,000 acres in western Kentucky. The purchase price was

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$42.0 million in cash and was funded with long-term debt under the PVR Revolver. The purchase price has been allocated as follows: $30.2 million to coal properties, $11.3 million to the coal processing plant and related facilities and $0.5 million to land. PVR also recorded a $28.1 million lease receivable and $16.6 million to deferred rent relating to a coal services facility lease.

The pro forma results for the years ended December 31, 2008, 2007 and 2006 for the above acquisitions did materially change the historical results for those periods.

Divestitures

In July 2008, we sold 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. The $30.5 million gain on the sale is reported in the revenues section of our consolidated statements of income.

In September 2007, we sold non-operated working interests in oil and gas properties located in eastern Kentucky and southwestern Virginia, with estimated proved reserves of 13.3 Bcfe. The sale price was $29.1 million in cash, and the proceeds of the sale were used to repay borrowings under the Revolver. We recognized a gain of $12.4 million on the sale, which is reported in the revenues section of our consolidated statements of income.

5. Stock split

On May 8, 2007, our board of directors approved a two-for-one-split of our common stock in the form of a 100% stock dividend payable on June 19, 2007 to shareholders of record on June 12, 2007. Shareholders received one additional share of common stock for each share held on the record date. All common shares and per share data for the year ended December 31, 2006 has been retroactively adjusted to reflect the stock split.

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 $138.2 million in net proceeds. PVG made contributions to PVR of $2.9 million to maintain its indirect 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 assets and 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”), delayed the application of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities to fiscal years and interim periods beginning after November 15, 2008. Examples of nonfinancial assets for which FSP SFAS 157-2 delays application of SFAS No. 157 include business combinations, impairment and initial recognition of an ARO.

Our financial instruments consist of cash and cash equivalents, receivables, accounts payable, derivative instruments and long-term debt. The carrying values of all of these financial instruments, except fixed rate long-term debt, approximate fair value. The fair value of our fixed

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rate long-term debt at December 31, 2008 and 2007 was $168.5 million and $230.0 million. As a result of repaying PVR’s Senior Unsecured Notes due 2013 (the “PVR Notes”), PVR had no fixed-rate long-term debt as of December 31, 2008. The fair value of PVR’s fixed-rate long-term debt at December 31, 2007 was $65.8 million.

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 December 31, 2008 (in thousands):

	Fair value measurements, December 31, 2008			Fair value measurement at December 31, 2008, using
Description				Quoted prices in active markets for identical assets (level 1)		Significant other observable inputs (level 2)			Significant unobservable inputs (level 3)
Marketable securities	$	4,559		$	4,559	$	—		$	—
Interest rate swap liability—current		(7,840	)		—		(7,840	)		—
Interest rate swap liability—noncurrent		(8,721	)		—		(8,721	)		—
Commodity derivative assets—current		67,569			—		67,569			—
Commodity derivative assets— noncurrent		4,070			—		4,070			—
Commodity derivative liability— current		(7,694	)		—		(7,694	)		—
Total	$	51,943		$	4,559	$	47,384		$	—

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

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

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

• Commodity derivative instruments: Both our oil and gas commodity derivatives and PVR’s natural gas midstream segment commodity derivatives utilize three-way collar derivative contracts. PVR also utilizes collar derivative contracts to hedge against the variability in its

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frac spread. We determine the fair values of our oil and gas derivative agreements based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of December 31, 2008. PVR determines the fair values its commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input. See Note 8—“Derivative Instruments.”

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

Oil and gas segment commodity derivatives

We utilize three-way collar derivative contracts to hedge against the variability in cash flows associated with anticipated 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.

A three-way collar contract consists of a collar contract plus a put option contract sold by us with a price below the floor price of the collar. The counterparty to a collar contract is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract.

The additional put option sold by us requires us to make a payment to the counterparty if the settlement price for any settlement period is below the put option price. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the collar contract and the additional put option price if the settlement price is equal to or less than the additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a collar contract only. If market prices are below the additional put option, we would be entitled to receive the market price plus the difference between the additional put option and the floor. See the oil and gas segment commodity derivative table in this footnote. This strategy enables us 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.

We determine the fair values of our oil and gas derivative agreements based on discounted cash flows derived from third-party forward quoted prices for NYMEX Henry Hub gas and West Texas

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Intermediate crude oil closing prices as of December 31, 2008. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties for derivatives in an asset position, and our own credit risk derivatives in a liability position, in accordance with SFAS No. 157. The following table sets forth our commodity derivative positions as of December 31, 2008:

	Average volume per day		Weighted average price							Estimated fair value (in thousands)
			Additional put option		Floor			Ceiling
Natural Gas Three-way Collars	(in MMBtus	)		(per MMBtu)
First Quarter 2009	65,000		$	6.00	$	8.67		$	11.68	$	13,688
Second Quarter 2009	40,000		$	6.38	$	8.75		$	10.79		6,918
Third Quarter 2009	40,000		$	6.38	$	8.75		$	10.79		6,166
Fourth Quarter 2009	30,000		$	6.83	$	9.50		$	13.60		4,869
First Quarter 2010	30,000		$	6.83	$	9.50		$	13.60		4,070
Crude Oil Three-way Collars	(Bbl	)				(Bbl	)
First Quarter 2009	500		$	80.00	$	110.00		$	179.00		1,328
Second Quarter 2009	500		$	80.00	$	110.00		$	179.00		1,272
Third Quarter 2009	500		$	80.00	$	110.00		$	179.00		1,236
Fourth Quarter 2009	500		$	80.00	$	110.00		$	179.00		1,197
Settlements to be paid in subsequent month											465
Oil and gas segment commodity derivatives-net asset										$	41,209

At December 31, 2008, we reported a net derivative asset related to the oil and gas commodity derivatives of $41.2 million. See theAdoption 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 three-way collar derivative contracts to hedge against the variability in cash flows associated with anticipated natural gas midstream revenues and cost of midstream gas purchased. PVR also utilizes collar 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 NGLs that PVR sells after processing. PVR hedges against the variability in its frac spread by entering into costless collar and swap derivative contracts to sell NGLs forward at a predetermined commodity price and to purchase an equivalent volume of natural gas forward on an MMBtu basis. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues or cost savings from favorable price movements.

A three-way collar contract consists of a collar contract plus a put option contract sold by PVR with a price below the floor price of the collar. The counterparty to a 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

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settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract.

The additional put option sold by PVR requires it to make a payment to the counterparty if the settlement price for any settlement period is below the put option price. By combining the collar contract with the additional put option, PVR is entitled to a net payment equal to the difference between the floor price of the collar contract and the additional put option price if the settlement price is equal to or less than the additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a collar contract only. If market prices are below the additional put option, PVR would be entitled to receive the market price plus the difference between the additional put option and the floor. See the PVR natural gas midstream segment commodity derivative table in this footnote. 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 discounted cash flows based on forward quoted prices for the respective commodities as of December 31, 2008, using discount rates adjusted for the credit risk of the counterparties if the derivative is in an asset position and PVR’s own credit risk for derivatives in a liability position. The following table sets forth PVR’s positions as of December 31, 2008 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:

			Weighted average price
	Average volume per day		Additional put option		Floor		Ceiling		Fair value (in thousands)
Crude Oil Three-way Collar	(in barrels	)		(per barrel)
First Quarter 2009 through Fourth Quarter 2009	1,000		$	70.00	$	90.00	$	119.25	$	6,101
Frac Spread Collar	(in MMBtu	)		(per MMBtu)
First Quarter 2009 through Fourth Quarter 2009	6,000				$	9.09	$	13.94		14,943
Settlements to be received in subsequent month										1,694
Natural gas midstream segment commodity derivatives—net asset									$	22,738

At December 31, 2008, PVR reported a net derivative asset related to the PVR natural gas midstream segment of $22.7 million. No loss remains in AOCI related to derivatives in the PVR natural gas midstream segment for which PVR discontinued hedge accounting in 2006. See theAdoption of SFAS No. 161section below for the impact of the PVR natural gas midstream commodity derivatives on our consolidated statements of income.

Interest rate swaps

We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver until December 2010. The notional amounts of the

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Interest Rate Swaps total $50.0 million, or approximately 15% of our total long-term debt outstanding under the Revolver at December 31, 2008. We will pay a weighted average fixed rate of 5.34% on the notional amount, and the counterparties will pay a variable rate equal to the three-month London Interbank Offered Rate, (“LIBOR”). Settlements on the Interest Rate Swaps are recorded as interest expense. The Interest Rate Swaps follow hedge accounting. 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) net derivative liability of $3.8 million at December 31, 2008 and (ii) loss in AOCI of $2.5 million, net of the related income tax benefit of $1.3 million, at December 31, 2008 related to the Interest Rate Swaps. In connection with periodic settlements, we recognized $0.7 million in net hedging losses, net of the related income tax benefit of $0.3 million, on the Interest Rate Swaps in interest expense in 2008. Based upon future interest rate curves at December 31, 2008, we expect to realize $1.9 million of hedging losses within the next 12 months. The amounts that we ultimately realize will vary due to changes in the fair value of open derivative agreements prior to settlement.

PVR interest rate swaps

PVR has entered into the PVR Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the PVR Revolver. Until March 2010, the notional amounts of the PVR Interest Rate Swaps total $285.0 million, or approximately 50% of PVR’s total long-term debt outstanding as of December 31, 2008, with PVR paying a weighted average fixed rate of 3.67% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From March 2010 to December 2011, the notional amounts of the PVR Interest Rate Swaps total $225.0 million with PVR paying a weighted average fixed rate of 3.52% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From December 2011 to December 2012, the notional amounts of the PVR Interest Rate Swaps total $75.0 million, with PVR paying a weighted average fixed rate of 2.10% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. The PVR Interest Rate Swaps extend one year past the maturity of the current PVR Revolver. The PVR Interest Rate Swaps have been entered into with six financial institution counterparties, with no counterparty having more than 26% of the open positions. In January 2009, PVR entered into an additional $25.0 million interest rate swap with a maturity of December 2012. Inclusive of this additional interest rate swap, the weighted average fixed interest rate PVR pays to its counterparties is 3.54% through March 2010, 3.37% from March 2010 through December 2011, and 2.09% from December 2011 through December 2012.

PVR continues to apply hedge accounting to some of its interest rate hedges. Settlements on the PVR Interest Rate Swaps that follow hedge accounting are recorded as interest expense. Accordingly, the effective portion of the change in the fair value of the transactions for the swaps that follow hedge accounting are recorded each period in AOCI. At December 31, 2008, a $1.2 million loss remained in AOCI related to Interest Rate Swaps on which we discontinued hedge accounting. The $1.2 million loss will be recognized in earnings through 2011 as the hedged transactions settle. Certain of the PVR Interest Rate Swaps do not follow hedge accounting. Accordingly, mark-to-market gains and losses for the PVR Interest Rate Swaps that do not follow hedge accounting are recognized in earnings currently in the Derivatives line on the consolidated statements of income.

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PVR reported a (i) net derivative liability of $12.8 million at December 31, 2008 and (ii) loss in AOCI of $4.2 million at December 31, 2008 related to the PVR Interest Rate Swaps. In connection with periodic settlements, PVR recognized $1.1 million, net of income tax benefit of $0.6 million, of net hedging losses in interest expense in the year ended December 31, 2008. Based upon future interest rate curves at December 31, 2008, PVR expects to realize $5.9 million of hedging losses within the next 12 months. The amounts that PVR ultimately realizes will vary due to changes in the fair value of open derivative agreements prior to settlement.

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 the disclosures required by SFAS No. 133. 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.

In the year ended December 31, 2008, we reclassified a total of $5.3 million, net of income tax expense of $2.9 million, out of AOCI and into earnings. We also recorded unrealized hedging losses of $4.4 million, net of income tax benefit of $2.3 million, in AOCI in the year ended December 31, 2008 related to the Interest Rate Swaps and the PVR Interest Rate Swaps. See Note 22, “Other Comprehensive Income,” for a detailed schedule of our AOCI.

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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 year ended December 31, 2008 (in thousands):

	Location of gain (loss) on derivatives recognized in income	Year ended December 31, 2008
Derivatives designated as hedging instruments under SFAS No. 133
(Effective portion):
Interest rate contracts(1)	Interest expense	$	(1,518	)
Increase (decrease) in net income resulting from derivatives designated as hedging instruments under SFAS No. 133 (Effective Portion)		$	(1,518	)
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivatives	$	(8,635	)
Interest rate contracts(1)	Interest expense		(1,203	)
Commodity contracts(1)	Natural gas midstream revenues		(8,219	)
Commodity contracts(1)	Cost of midstream gas purchased		2,739
Commodity contracts	Derivatives		55,217
Increase (decrease) in net income resulting from derivatives not designated as hedging instruments under SFAS No. 133		$	39,899
Total increase (decrease) in net income resulting from derivatives		$	38,381
Realized and unrealized derivative impact:
Cash paid for commodity and interest rate contract settlements	Derivatives	$	(46,086	)
Cash paid for interest rate contract settlements	Interest expense		(1,518	)
Unrealized derivative gain	(2)		85,985
Total increase (decrease) in net income resulting from derivatives		$	38,381

(1) This represents amounts reclassified out of AOCI and into earnings. 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. No losses remain in AOCI related to commodity derivatives for which we discontinued hedge accounting in 2006. At December 31, 2008, a $1.2 million loss remained in AOCI related to the PVR Interest Rate Swaps on which PVR discontinued hedge accounting in 2008.

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

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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 December 31, 2008 (in thousands):

	Balance sheet location	Estimated fair values at December 31, 2008
		Derivative assets		Derivative liabilities
Derivatives designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivative liabilities—current	$	—	$	3,177
Interest rate contracts	Derivative liabilities—noncurrent		—		3,648
Total derivatives designated as hedging instruments under SFAS No. 133		$	—	$	6,825
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivative liabilities—current	$	—	$	4,663
Interest rate contracts	Derivative liabilities—noncurrent		—		5,073
Commodity contracts	Derivative assets/liabilities—current		67,569		7,694
Commodity contracts	Derivative assets/liabilities—noncurrent		4,070		—
Total derivatives not designated as hedging instruments under SFAS No. 133		$	71,639	$	17,430
Total estimated fair value of derivative instruments		$	71,639	$	24,255

See Note 7, “Fair Value Measurement of Financial Instruments” for a description of how the above financial instruments are valued in accordance with SFAS No. 157.

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

Source	Year ended December 31, 2008
Interest on borrowings	$	(44,253	)
Capitalized interest(1)		2,713
Interest rate swaps		(2,721	)
Total interest expense	$	(44,261	)

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

The effects of derivative gains (losses), cash settlements of our oil and gas commodity derivatives, cash settlements of PVR’s natural gas midstream commodity derivatives, and cash settlements of the PVR Interest Rate Swaps that do not follow hedge accounting are reported as adjustments to reconcile net income to net cash provided by operating activities on our consolidated statements of cash flows. These items are recorded in the “Total derivative losses (gains)” and “Cash settlements of derivatives” lines on the consolidated statements of cash flows.

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The above hedging activity represents cash flow hedges. As of December 31, 2008, neither PVR nor we actively traded derivative instruments or have any fair value hedges. In addition, as of December 31, 2008, neither PVR nor we owned derivative instruments containing credit risk contingencies.

9. Common stock offering

In December 2007, we completed the sale of 3,450,000 shares of our common stock in a registered public offering. The net proceeds of the sale were $135.4 million and were used to repay a portion of the outstanding borrowings under the Revolver and for general corporate purposes.

10. Suspended well costs

The following table describes the changes in capitalized exploratory drilling costs that are pending the determination of proved reserves:

	2008					2007					2006
	Number of wells		Cost			Number of wells		Cost			Number of wells		Cost
Balance at beginning of period	4		$	4,336		1		$	1,119		3		$	1,670
Additions pending determination of proved reserves	1			2,482		4			4,336		1			1,119
Reclassifications to wells, equipment and facilities based on the determination of proved reserves	—			—		(1	)		(1,119	)	—			—
Charged to expense	(4	)		(4,336	)	—			—		(3	)		(1,670	)
Balance at end of period	1		$	2,482		4		$	4,336		1		$	1,119

We had no capitalized exploratory drilling costs that had been under evaluation for a period greater than one year as of December 31, 2008, 2007 and 2006.

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11. Property and equipment

The following table summarizes our property and equipment as of December 31, 2008 and 2007:

	December 31,
(in thousands)	2008		2007
Oil and gas properties
Proved	$1,951,325		$1,397,923
Unproved	154,801		127,805
Total oil and gas properties	2,106,126		1,525,728
Other property and equipment:
Coal properties	476,787		453,484
Midstream property and equipment	426,064		238,040
Land	20,985		17,753
Timber	87,869		87,800
Other property and equipment	64,766		62,303
Total property and equipment	3,182,597		2,385,108
Accumulated depreciation, depletion and amortization	(671,422	)	(486,094	)
Net property and equipment	$2,511,175		$1,899,014

12. Goodwill

The changes in the carrying amount of goodwill for the year ended December 31, 2008 are as follows:

	Natural gas midstream segment
Balance at January 1, 2008	$	7,718
Goodwill acquired during year		24,083
Impairment loss incurred during year		(31,801	)
Balance at December 31, 2008	$	—

In accordance with SFAS No. 142, PVR tests goodwill for impairment on an annual basis, at a minimum, and more frequently if a triggering event occurs. PVR’s annual impairment testing of goodwill and the subsequent hypothetical purchase price allocation, using the guidance prescribed by SFAS No. 142, resulted in an impairment to goodwill of approximately $31.8 million in the fourth quarter of 2008. The impairment charge, which was triggered by fourth quarter declines in oil and gas spot and futures prices and a decline in PVR’s market capitalization, reduces to zero all goodwill recorded in conjunction with acquisitions made by the PVR natural gas midstream segment in 2008 and prior years.

In determining the fair value of the PVR natural gas midstream segment (reporting unit), we used an income approach. Under the income approach, the fair value of the reporting unit is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, appropriate discount rates and a market-derived earnings multiple terminal value (the value of the reporting unit at the end of the estimation period).

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Key assumptions used in the discounted cash flows model described above include estimates of future commodity prices based on the December 31, 2008 commodity price strips and estimates of operating, administrative and capital costs. We discounted the resulting future cash flows using a PVR peer company based weighted average cost of capital of 12%.

This loss is recorded in the impairment line on our consolidated statements of income. The goodwill impairment loss reflects the negative impact of certain factors which resulted in a reduction in the anticipated cash flows used to estimate fair value. The business and marketplace environments in which PVR currently operates differs from the historical environments that drove the factors used to value and record the acquisition of these business units. Our goodwill balance at December 31, 2007 was $7.7 million.

13. Intangible assets, net

The following table summarizes PVR’s net intangible assets as of December 31, 2008 and 2007:

	As of December 31,
(in thousands)	2008			2007
Contracts and customer relationships	$	106,900		$	37,700
Rights-of-way		4,552			4,552
Total intangible assets		111,452			42,252
Accumulated amortization		(18,780	)		(13,314	)
Intangible assets, net	$	92,672		$	28,938

The contracts and customer relationships and rights-of-way were primarily acquired by PVR in the Lone Star acquisition. See Note 4—“Acquisitions and Divestitures.” Contracts and customer relationships are amortized on a straight-line basis over the expected useful lives of the individual contracts and relationships, up to 20 years. Total intangible amortization expense for the years ended December 31, 2008, 2007 and 2006 was approximately $5.5 million, $4.1 million and $5.0 million. As of December 31, 2008 and 2007, accumulated amortization of intangible assets was $18.8 million and $13.3 million. The following table sets forth our estimated aggregate amortization expense for the next five years and thereafter:

Year	Amortization expense
	(in thousands)
2009	$	9,538
2010		9,054
2011		8,467
2012		7,779
2013		7,560
Thereafter		70,498
Total	$	112,896

14. Impairment of oil and gas properties

In accordance with SFAS No. 144, we review oil and gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. We estimate the future

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cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. When we find that the carrying amounts of the properties exceed their estimated undiscounted future cash flows, we adjust the carrying amounts of the properties to their fair value as determined by discounting their estimated future cash flows. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

For the year ended December 31, 2008, we recorded $20.0 million of impairment charges in 2008 related to declines in spot and future oil and gas prices and declines in well performance. This reduced the estimated reserves on certain properties in the Mid-Continent and Appalachian regions, which was primarily due to a decline in well performance.

For the year ended December 31, 2007, we recognized impairment charges of $2.6 million primarily related to changes in estimates of the reserve bases of fields on certain properties in Oklahoma and Texas. These changes in reserve estimates were primarily due to declines in well performance. For the year ended December 31, 2006, we recognized impairment charges of $8.5 million related to changes in estimates of the reserve bases of fields on certain properties in Louisiana, Texas and West Virginia.

15. Accounts payable and accrued liabilities

The following table summarizes our accounts payable and accrued liabilities as of December 31, 2008 and 2007:

	December 31,
(in thousands)	2008		2007
Deferred income—PVR coal	$	4,842	$	2,958
Drilling costs		54,477		19,446
Royalties		9,495		18,032
Production and franchise taxes		12,062		11,935
Compensation		11,011		8,757
Interest		3,049		3,153
Other		5,702		14,830
Total accrued liabilities		100,638		79,111
Accounts payable		106,264		126,016
Accounts payable and accrued liabilities	$	206,902	$	205,127

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16. Asset retirement obligations

The following table reconciles the beginning and ending aggregate carrying amount of our AROs for the years ended December 31, 2008 and 2007, which are included in other liabilities on our consolidated balance sheets:

	Year ended December 31,
(in thousands)	2008			2007
Balance at beginning of period	$	7,873		$	6,747
Liabilities incurred		487			540
Revision of estimates		(505	)		—
Liabilities settled		9			(219	)
Accretion expense		725			805
Balance at end of period	$	8,589		$	7,873

The accretion expense is recorded in the depreciation, depletion and amortization expense line on the consolidated statements of income.

17. Other liabilities

The following table summarizes our other liabilities as of December 31, 2008 and 2007:

	December 31,
(in thousands)	2008		2007
Deferred income—PVR Coal	$	20,260	$	22,243
Asset retirement obligations		8,589		7,873
Pension		1,891		1,838
Post-retirement health care		3,478		4,036
Environmental liabilities		974		1,278
Unrecognized tax benefits		2,800		8,386
Deferred compensation		7,435		8,018
Other		460		497
Total other liabilities	$	45,887	$	54,169

18. Long-term debt

The following table summarizes our long-term debt as of December 31, 2008 and 2007:

	As of December 31,
(in thousands)	2008			2007
Short-term borrowings	$	7,542		$	12,561
Revolving credit facility—variable rate of 3.4% and 6.7% at December 31, 2008 and 2007		332,000			122,000
Convertible senior subordinated notes		230,000			230,000
PVR revolving credit facility—variable rate of 4.4% and 6.2% at December 31, 2008 and 2007		568,100			347,700
PVR senior unsecured notes—noncurrent portion		—			51,453
Total debt		1,137,642			763,714
Less: Short-term borrowings		(7,542	)		(12,561	)
Total long-term debt	$	1,130,100		$	751,153

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In the year ended December 31, 2008, the short-term borrowings reflect a book overdraft. In the year ended December 31, 2007, the short-term borrowings reflect the current portion of the PVR Notes.

We capitalized interest costs amounting to $2.0 million, $3.7 million and $3.2 million in 2008, 2007 and 2006 because the borrowings funded the preparation of unproved properties for their development.

PVR capitalized interest costs amounting to $0.7 million and $0.8 million in the years ended December 31, 2008 and 2007 related to the construction of two natural gas processing plants. PVR capitalized interest costs amounting to $0.3 million in the year ended December 31, 2006 related to the construction of a coal services facility in October 2006.

Revolver

As of December 31, 2008, we had $332.0 million outstanding under the Revolver, which is senior to the Convertible Notes. At the current $479.0 million limit on the Revolver, and given our outstanding balance of $332.0 million, net of $0.3 million of letters of credit, we could borrow up to $146.7 million at December 31, 2008. The Revolver, which matures in December 2010, is secured by a portion of our proved oil and gas reserves. Our borrowing base can be redtermined twice per year. 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 December 31, 2008. In 2008, we incurred commitment fees of $0.8 million on the unused portion of the Revolver. The commitments, which are can be redetermined relative to our borrowing base, cannot be withdrawn by the bank. The Revolver is governed by a borrowing base calculation and is redetermined semi-annually. We have the option to elect interest at (i) LIBOR, plus a margin ranging from 1.00% to 1.75%, based on the ratio of our outstanding borrowings to the borrowing base or (ii) the greater of the prime rate or federal funds rate plus a margin of up to 1.00%. The weighted average interest rate on borrowings outstanding under the Revolver during 2008 was 4.4%.

The financial covenants under the Revolver require us not to exceed specified ratios. The Revolver contains various other covenants that limit our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries. As of December 31, 2008, we were in compliance with all of our covenants under the Revolver.

Convertible notes

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

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

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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 certain circumstances. 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.

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. 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 is offset by the proceeds of the Warrants described below).

We also entered into separate warrant transactions whereby we sold to the Option Counterparties warrants to acquire, subject to anti-dilution adjustments, approximately 4.0 million shares of our common stock (the “Warrants”) at an exercise price of $74.25 per share. 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.

The Note Hedges and the Warrants are separate contracts entered into by us with the Option Counterparties, are not part of the terms of the Convertible Notes and will not affect the noteholders’ rights under the Convertible Notes. The Note Hedges are expected to offset the potential dilution upon conversion of the Convertible Notes in the event that the market value per share of our common stock at the time of exercise is greater than the strike price of the Note Hedges, which corresponds to the initial conversion price of the Convertible Notes and is simultaneously subject to certain adjustments.

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

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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.

PVR revolver

As of December 31, 2008, net of outstanding borrowings of $568.1 million and letters of credit of $1.6 million, PVR had remaining borrowing capacity of $130.3 million on the PVR Revolver. In August 2008, PVR increased the size of the PVR Revolver from $600.0 million to $700.0 million and secured the PVR Revolver with substantially all of PVR’s assets. The PVR Revolver matures in December 2011 and is available to PVR for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10.0 million sublimit for the issuance of letters of credit. In 2008, PVR incurred commitment fees of $0.5 million on the unused portion of the PVR Revolver. The interest rate under the PVR Revolver fluctuates based on the ratio of PVR’s total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 0.75% if PVR selects the base rate borrowing option under the PVR Revolver or at a rate derived from LIBOR plus an applicable margin ranging from 0.75% to 1.75% if PVR selects the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the PVR Revolver during 2008 was 4.6%. PVR does not have a public credit rating for the PVR Revolver.

The financial covenants under the PVR Revolver require PVR not to exceed specified ratios. 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 PVR’s ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of PVR’s business, or enter into a merger or sale of PVR’s assets, including the sale or transfer of interests in PVR’s subsidiaries. As of December 31, 2008, PVR was in compliance with all of its 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. 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. The $3.8 million of make-whole payments were recorded in interest expense on our consolidated statements of income. The PVR Notes were repaid with borrowings under the PVR Revolver. While the PVR Notes were outstanding, PVR had a DBRS public credit rating. However, due to the repayment of the PVR Notes, PVR has elected not to renew this rating. As of December 31, 2007, PVR owed $64.0 million under the PVR Notes, the current portion of which was $12.6 million. The PVR Notes bore interest at a fixed rate of 6.02%.

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Debt maturities

The following table sets forth the aggregate maturities of the principal amounts of long-term debt for the next five years and thereafter:

Year	Aggregate maturities of principal amounts
2009	$	—
2010		332,000
2011		568,100
2012		230,000
2013		—
Thereafter		—
Total debt, including current maturities		1,130,100

19. Income taxes

In 2006, the FASB issued Interpretation No. 48,Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109 (“FIN 48”) which we adopted on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position taken or expected to be taken that is required to be met before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. The adoption of FIN 48 did not result in a transition adjustment to retained earnings; instead, $8.7 million was reclassified from deferred income taxes to a long-term liability.

Due to the geographical scope of our operations, we are subject to ongoing tax examinations in numerous jurisdictions. Accordingly, we may record incremental tax expense based upon the more-likely-than-not outcomes of any uncertain tax positions. In addition, when applicable, we adjust the previously recorded tax expense to reflect examination results when the position is effectively settled. Our ongoing assessments of the more-likely-than-not outcomes of the examinations and related tax positions require judgment and can increase or decrease our effective tax rate, as well as impact our operating results. The specific timing of when the resolution of each tax position will be reached is uncertain.

The liability for unrecognized tax benefits at December 31, 2008 and 2007 included $3.3 million and $8.0 million of tax positions which would change the effective tax rate, if recognized. We recognize interest related to unrecognized tax benefits in interest expense, and penalties are included in income tax expense. For the years ended December 31, 2008 and 2007, we recognized $0.5 million and $0.7 million in interest and penalties. Prior to adoption of FIN 48, we classified interest on taxes as a component of income tax expense and penalties were included in income tax expense. We had accrued interest and penalties of $1.8 million and $3.4 million for the years ended December 31, 2008 and 2007. Tax years from 2005 forward remain open for examination by the Internal Revenue Service. Tax years from 2004 forward remain open for state jurisdictions.

We are currently evaluating the filing status of a subsidiary in a state. If management and the state’s taxing authority determine that the subsidiary’s income is taxable in that state, it is reasonably possible that a settlement of approximately $1.8 million will be made by the end of

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2009. We classified $1.8 million of the total liability for unrecognized tax benefits as a current liability in income taxes payable on the balance sheet at December 31, 2008. This current liability represents our best estimate of the change in unrecognized tax benefits that we expect to occur within the next 12 months.

A reconciliation of the beginning and ending amount of unrecognized tax benefits for the years ended December 31, 2008 and 2007 is as follows

	Year ended December 31,
(in millions)	2008			2007
Beginning of year (adoption adjustment)	$	9,852		$	8,737
Additions based on tax positions related to the current year		220			1,659
Additions as a result of tax positions taken in prior years		461			—
Settlements		(5,933	)		(544	)
Balance at end of year		4,600			9,852
Less: current portion		(1,800	)		(1,466	)
Long-term portion	$	2,800		$	8,386

(1) In the years ended December 31, 2008 and 2007, we paid $2.2 million and $0.4 million in cash to settle uncertain tax positions. In the same years, we recognized $3.7 million and $0.1 million in tax and interest benefits related to waived taxes, penalties and interest in connection with settlement.

The following table summarizes our provision for income taxes from continuing operations for the years ended December 31, 2008, 2007 and 2006:

	Year ended December 31,
(in thousands)	2008			2007		2006
Current income taxes
Federal	$	13,838		$	6,212	$	11,710
State		(469	)		949		258
Total current		13,369			7,161		11,968
Deferred income taxes
Federal		50,380			19,797		29,419
State		10,125			3,543		8,601
Total deferred		60,505			23,340		38,020
Total income tax expense	$	73,874		$	30,501	$	49,988

The following table reconciles the difference between the taxes computed by applying the statutory tax rate to income from operations before income taxes and our reported income tax expense for the years ended December 31, 2008, 2007 and 2006:

	Year ended December 31,
	2008				2007				2006
Computed at federal statutory tax rate	$	69,369		35.0%	$	28,441		35.0%	$	44,063	35.0%
State income taxes, net of federal income tax benefit		7,475		3.8%		3,275		4.0%		5,391	4.2%
Other, net		(2,970	)	(1.5)%		(1,215	)	(1.5)%		534	0.5%
Total income tax expense	$	73,874		37.3%	$	30,501		37.5%	$	49,988	39.7%

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The following table summarizes the principal components of our net deferred income tax liability as of December 31, 2008 and 2007:

	December 31,
(in thousands)	2008		2007
Deferred tax liabilities:
Property and equipment	$	278,149	$	229,557
Fair value of derivative instrument		6,919		—
Other		—		997
Total deferred tax liabilities		285,068		230,554
Deferred tax assets:
Fair value of derivative instrument		—		30,015
Deferred income—coal properties		9,732		9,836
Pension and post-retirement benefits		4,279		4,877
Stock-based compensation		4,699		3,428
Net operating loss carry forwards		—		459
Other		2,971		4,262
Total deferred tax assets		21,681		52,877
Net deferred tax liability	$	263,387	$	177,677

In assessing our deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible. Among other items, we consider the scheduled reversal of deferred tax liabilities, projected future taxable income and available tax planning strategies. As of December 31, 2008 and 2007, no valuation allowance had been recorded because we estimated that it was more likely than not that all of our deferred tax assets would be realized.

In June 2006, we acquired 100% of the common stock of Crow Creek Holding Corporation. As a result, we acquired federal and state tax net operating loss carryforwards (“NOLs”) which, if unused, will expire between 2022 and 2026. In addition to the carryforward period, these acquired NOLs are subject to other restrictions and limitations, including Section 382 of the Internal Revenue Code, which impact their ultimate realizability. As of December 31, 2008, we had utilized all of these federal and state NOLs.

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20. Earnings per share

The following table provides a reconciliation of the numerators and denominators used in the calculation of basic and diluted earnings per share for the years ended December 31, 2008, 2007 and 2006:

	Year ended December 31,
(in thousands, except per share data)	2008			2007			2006
Net income	$	124,168		$	50,754		$	75,909
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards (net of tax)		(295	)		(186	)		—
	$	123,873		$	50,568		$	75,909
Weighted average shares, basic		41,760			38,061			37,362
Effect of dilutive securities:
Stock options		271			297			370
Weighted average shares, diluted		42,031			38,358			37,732
Net income per share, basic	$	2.97		$	1.33		$	2.03
Net income per share, diluted	$	2.95		$	1.32		$	2.01

Options with an exercise price exceeding the average price of the underlying securities are not considered to be dilutive and are not included in calculation of the denominator for diluted earnings per share for the years ended December 31, 2008, 2007 and 2006. The total number of shares that could potentially dilute basic earnings per share in the future was 20,000 shares in 2008 and zero in 2007 and 2006. The Convertible Notes (see Note 9—“Common Stock Offering, Convertible Note Offering, Warrant and Note Hedges”) issued in December 2007 have not met the criteria for conversion. Therefore, the Convertible Notes are not dilutive and are not included in the calculation of the denominator for diluted earnings per share for the years ended December 31, 2008 and 2007.

21. Share-based payments

Stock compensation plans

We have several stock compensation plans (collectively, the “Stock Compensation Plans”) that allow incentive and nonqualified stock options and restricted stock to be granted to key employees and officers and nonqualified stock options and deferred common stock units to be granted to directors. At December 31, 2008, there were approximately 376,595 and 1,492,666 shares available for issuance to directors and employees pursuant to the Stock Compensation Plans. For the years ended December 31, 2008, 2007 and 2006, we recognized $5.9 million, $4.1 million and $2.8 million of compensation expense related to the Stock Compensation Plans, which is recorded on the general and administrative expenses line on the consolidated statements of income. The total income tax benefit recognized in our consolidated statements of income for the Stock Compensation Plans was $2.3 million, $1.6 million and $1.1 million for the years ended December 31, 2008, 2007 and 2006.

Stock options.    The exercise price of all options granted under the Stock Compensation Plans is equal to the fair market value of our common stock on the date of the grant. Options may be exercised at any time after vesting and prior to ten years following the date of grant. Options

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vest upon terms established by the compensation and benefits committee of our board of directors. Generally, options vest ratably over a three-year period, with one-third vesting in each year. In addition, all options will vest upon a change of control of us, as defined by the Stock Compensation Plans. In the case of employees, if a grantee’s employment terminates (i) for cause, all of the grantee’s options, whether vested or unvested, will be automatically forfeited, (ii) by reason of death, disability or retirement (age 62 and providing ten consecutive years of service) the grantee’s options will automatically vest and (iii) for any other reason, the grantee’s unvested options will be automatically forfeited. In the case of directors, if a grantee’s membership on our board of directors terminates for any reason, the grantee’s unvested options will be automatically forfeited. We have a policy of issuing new shares to satisfy share option exercises.

The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option-pricing formula that uses the assumptions noted in the following table. Expected volatilities are based on historical changes in the market value of our stock. Separate groups of employees that have similar historical exercise behavior are considered separately to estimate expected lives. Options granted have a maximum term of ten years. We base the risk-free interest rate on the U.S. Treasury rate for the week of the grant having a term equal to the expected life of the option.

	2008		2007	2006
Expected volatility	38.5% to 56.1%		30.0% to 38.5%	20.9% to 31.5%
Dividend yield	0.37% to 0.67%	��	0.51% to 0.63%	0.60% to 0.71%
Expected life	3.5 to 4.6 years		3.5 to 4.6 years	3.5 to 4.6 years
Risk-free interest rate	1.86% to 2.87%		3.86% to 4.72%	4.59% to 5.01%

The following table summarizes activity for our most recent fiscal year with respect to common stock options awarded:

Options	Shares under options		Weighted average exercise price		Weighted average remaining contractual term	Aggregate intrinsic value
					(in years)	(in thousands)
Outstanding at January 1, 2008	1,346,417		$	25.39
Granted	482,594			43.18
Exercised	(421,934	)		18.87
Forfeit	(29,862	)		36.81
Outstanding at December 31, 2008	1,377,215		$	33.28	7.6	$	4,282
Exercisable at December 31, 2008	529,853		$	23.99	6.1	$	4,282

The weighted-average grant-date fair value of options granted during the years ended December 31, 2008, 2007 and 2006 was $13.20, $9.83 and $7.17 per option. The total intrinsic value of options exercised during the years ended December 31, 2008, 2007 and 2006 was $13.1 million, $10.0 million and $7.4 million.

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The following table summarizes the status of our nonvested options as of December 31, 2008 and changes during the year then ended:

Nonvested options	Options		Weighted average grant-date fair value
Nonvested at January 1, 2008	728,812		$	8.54
Granted	482,594			13.20
Vested	(334,182	)		7.99
Forfeit	(29,862	)		9.46
Nonvested at December 31, 2008	847,362		$	11.38

As of December 31, 2008, we had $6.5 million of total unrecognized compensation cost related to nonvested stock options. We expect that cost to be recognized over a weighted-average period of 0.9 years. The total grant-date fair value of stock options that vested in 2008, 2007 and 2006 was $2.7 million, $1.8 million and $0.8 million. Cash received from the exercise of stock options in 2008 was $8.0 million, net of employee taxes withheld. The actual tax benefit realized for the tax deductions from option exercises was $4.6 million for the year ended December 31, 2008.

Restricted stock.    Restricted stock vests upon terms established by the compensation and benefits committee of our board of directors and specified in the award agreement. In addition, all restricted stock will vest upon a change of control of us. If a grantee’s employment terminates for any reason other than death or disability, the grantee’s restricted stock will be automatically forfeited unless otherwise determined by the compensation and benefits committee and specified in the award agreement. If a grantee’s employment terminates by reason of death or disability, or if a grantee becomes retirement eligible (age 62 and providing 10 consecutive years of service), the grantee’s restricted stock will automatically vest. Except as specified by the compensation and benefits committee, a grantee shall be entitled to receive any dividends declared on our common stock. Restricted stock 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.

The following table summarizes the status of our nonvested restricted stock as of December 31, 2008 and changes during the year then ended:

Nonvested options	Nonvested restricted stock		Weighted average grant-date fair value
Nonvested at January 1, 2008	49,348		$	31.92
Granted	39,354			42.27
Vested	(34,302	)		(30.88	)
Nonvested at December 31, 2008	54,400		$	40.06

At December 31, 2008, we had $1.5 million of total unrecognized compensation cost related to nonvested restricted stock. We expect that cost to be recognized over a weighted-average period of 1.0 years. The total grant-date fair value of restricted stock that vested in the years ended December 31, 2008 and 2007 was $1.0 million and $0.6 million.

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Deferred common stock units.    A portion of the compensation paid to non-employee members of our board of directors is paid in deferred common stock units. Each deferred common stock unit represents one share of common stock, which vests immediately upon issuance and is available to the holder upon termination or retirement from our board of directors. Deferred common stock units awarded to directors receive all cash or other dividends we pay on account of shares of our common stock. The fair value of the deferred common stock units is calculated based on the grant-date stock price.

The following table summarizes activity for the most recent fiscal year with respect to deferred common stock units awarded:

	Deferred common stock units	Weighted average grant-date fair value
Outstanding at January 1, 2008	51,972	$	30.94
Granted	14,105		44.59
Outstanding at December 31, 2008	66,077	$	33.86

The aggregate intrinsic value of deferred common stock units converted to shares of common stock in the year ended December 31, 2007 was $0.3 million.

In accordance with EITF Issue No. 97-14,Accounting for Deferred Compensation Arrangements Where Amounts Earned Are Held in a Rabbi Trust and Invested, we recorded a $2.2 million, $1.6 million and $1.3 million deferred compensation obligation in shareholders’ equity at December 31, 2008, 2007 and 2006 and a corresponding amount for treasury stock.

Deferred PVG common units.    A portion of the compensation to the non-employee directors of PVG’s general partner is paid in deferred PVG common units. Each deferred PVG common unit represents one PVG common unit, which vests immediately upon issuance and is available to the holder upon termination or retirement from the board of directors of our general partner. At December 31, 2007, 13,396 deferred PVG common units were outstanding at a weighted average grant date fair value of $27.30. At December 31, 2008, 32,128 deferred PVG common units were outstanding at a weighted average grant date fair value of $23.40.

We granted 18,732 deferred PVG common units in 2008 at a weighted average grant date fair value of $20.61 per unit. We granted 13,396 deferred PVG common units in 2007 at a weighted average grant date fair value of $27.30 per unit. The fair value of the deferred PVG common units is calculated based on the grant-date unit price.

PVR long-term incentive plan

PVR’s general partner has adopted a long-term incentive plan. PVR’s long-term incentive plan permits the grant of awards to employees and directors of PVR’s general partner and employees of its affiliates who perform services for PVR. In January 2009, PVR’s general partner increased the number of common units permitted to be granted under the long-term incentive plan to 3,000,000 PVR common units. Awards under the PVR long-term incentive plan can be in the form of PVR common units, restricted PVR units, PVR unit options, phantom PVR units and deferred PVR common units. The PVR long-term incentive plan is administered by the compensation and benefits committee of the board of directors of PVR’s general partner. PVR reimburses its general

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partner for payments made pursuant to the PVR long-term incentive plan. PVR recognizes compensation cost based on the fair value of the awards over the vesting period.

PVR recognizes compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under PVR’s long-term incentive plan. PVR recognized a total of $3.2 million, $2.4 million and $1.9 million in the years ended December 31, 2008, 2007 and 2006 of compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under the long-term incentive plan.

PVR common units.    PVR’s common units, which are granted to non-employee directors, vest immediately upon issuance. PVR’s general partner granted 1,525 common units at a weighted average grant-date fair value of $20.27 per unit to non-employee directors in 2008. PVR’s general partner granted 1,183 common units at a weighted average grant-date fair value of $27.09 per unit to non-employee directors in 2007. PVR’s general partner granted 1,795 common units at a weighted average grant-date fair value of $26.01 per unit to non-employee directors in 2006. The fair value of the PVR common units is calculated based on the grant-date unit price.

Restricted PVR units.    Restricted PVR units vest upon terms established by the compensation and benefits committee of its general partner’s board of directors. In addition, all restricted PVR units will vest upon a change of control of PVR’s general partner or us. If a grantee’s employment with, or membership on the board of directors of, PVR’s general partner terminates for any reason, the grantee’s unvested restricted PVR units will be automatically forfeited unless, and to the extent that, the compensation and benefits committee provides otherwise. Distributions payable with respect to restricted PVR units may, in the compensation and benefits committee’s discretion, be paid directly to the grantee or held by PVR’s general partner and made subject to a risk of forfeiture during the applicable restriction period. Restricted PVR units generally vest over a three-year period, with one-third vesting in each year. The fair value of the restricted PVR units is calculated based on the grant-date unit price.

The following table summarizes the status of nonvested restricted PVR units as of December 31, 2008 and changes during the year then ended:

	Nonvested restricted units		Weighted average grant-date fair value
Nonvested at January 1, 2008	156,931		$	27.40
Granted	138,251			26.57
Vested	(71,074	)		27.27
Forfeit	(2,253	)		27.09
Nonvested at December 31, 2008	221,855		$	26.93

At December 31, 2008, PVR had $3.7 million of total unrecognized compensation cost related to nonvested restricted units. PVR expects to reimburse its general partner for that cost over a weighted-average period of 0.9 years. The total grant-date fair value of restricted units that vested in 2008, 2007 and 2006 was $1.9 million, $1.2 million and $2.2 million.

Deferred PVR common units.    A portion of the compensation to the non-employee directors of PVR’s general partner is paid in deferred PVR common units. Each deferred PVR common unit represents one PVR common unit, which vests immediately upon issuance and is available to the

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holder upon termination or retirement from the board of directors of PVR’s general partner. PVR’s general partner granted 21,337 deferred PVR common units in 2008 at a weighted-average grant-date fair value of $23.85. PVR’s general partner granted 22,209 deferred PVR common units in 2007 at a weighted average grant-date fair value of $26.43. At December 31, 2008, 56,433 deferred PVR common units were outstanding at a weighted average grant-date fair value of $24.87. At December 31, 2007, 61,218 deferred PVR common units were outstanding at a weighted average grant-date fair value of $25.58. At December 31, 2006, 39,009 deferred PVR common units were outstanding at a weighted average grant-date fair value of $25.26 per PVR common unit. In 2008, 26,122 deferred PVR common units converted to PVR common units. The aggregate intrinsic value of deferred PVR common units converted to PVR common units in 2008 and 2006 was $0.7 million and $0.2 million. No deferred PVR common units converted to PVR common units in 2007. The fair value of the deferred PVR common units is calculated based on the grant-date unit price.

22. Other 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 years ended December 31, 2008, 2007 and 2006:

(in thousands)	Cash flow hedges			Other			Total
Hedging unrealized loss, net of tax of ($2,352)	$	(4,368	)	$	—		$	(4,368	)
Hedging reclassification adjustment, net of tax of $2,871		5,332			—			5,332
Other, net of tax of $186		—			346			346
Other comprehensive income for the year ended December 31, 2008	$	964		$	346		$	1,310
Hedging unrealized loss, net of tax of ($1,432)	$	(2,659	)	$	—		$	(2,659	)
Hedging reclassification adjustment, net of tax of $1,449		2,691			—			2,691
Other, net of tax of ($8)		—			(14	)		(14	)
Other comprehensive income for the year ended December 31, 2007	$	32		$	(14	)	$	18
Hedging unrealized loss, net of tax of $321	$	597		$	—		$	597
Hedging reclassification adjustment, net of tax of $335		622			—			622
Other, net of tax of ($10)		—			(19	)		(19	)
Other comprehensive income for the year ended December 31, 2006	$	1,219		$	(19	)	$	1,200

Included in the comprehensive income balance at December 31, 2008 is $1.2 million of losses relating to the PVR Interest Rate Swaps on which PVR discontinued hedge accounting. The $1.2 million loss will be recognized in earnings through the end of 2011 as the hedged transactions settle. See Note 8, “Derivative Instruments.”

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23. Commitments and contingencies

Rental commitments

Operating lease rental expense in the years ended December 31, 2008, 2007 and 2006 was $22.8 million, $16.0 million and $10.0 million. The following table sets forth our consolidated minimum rental commitments for the next five years under all non-cancelable operating leases in effect at December 31, 2008:

Year	Minimum rental commitments
	(in thousands)
2009	$	12,009
2010		6,136
2011		3,503
2012		2,189
2013		2,150
Thereafter		8,591
Total minimum payments	$	34,578

Our rental commitments primarily relate to equipment and building leases and leases of coal reserve-based properties which PVR subleases, or intends to sublease, to third parties. The obligation with respect to leased properties which PVR subleases expires when the property has been mined to exhaustion or the lease has been canceled. The timing of mining by third party operators is difficult to estimate due to numerous factors. PVR believes that its future rental commitments with regard to this subleased property cannot be estimated with certainty.

Drilling commitments

We have agreements to purchase oil and gas well drilling services from third parties with terms that range from two to three years. The agreements include early termination provisions that would require us to pay penalties if we terminate the agreements prior to the end of their original terms. The amount of penalty is based on the number of days remaining in the contractual term and declines as time passes. As of December 31, 2008, the penalty amount would have been $41.6 million if we had terminated our agreements on that date. Our management intends to utilize drilling services under these agreements for the full terms and has no plans to terminate the agreements early. The following table sets forth our obligation for drilling commitments in effect at December 31, 2008 for the next five years and thereafter:

Year	Drilling commitments
2009	$	29,774
2010		17,056
2011		5,952
2012		—
2013		—
Thereafter		—
Total drilling commitments	$	52,782

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Oil and gas segment firm transportation commitments

In 2004, we entered into contracts which provide firm transportation capacity rights for specified volumes per day on a pipeline system with terms that ranged from one to 10 years. The contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. We may sell excess capacity to third parties at our discretion. The following table sets forth our obligation for firm transportation commitments in effect at December 31, 2008 for the next five years and thereafter:

Year	Firm transportation commitments
2009	$	3,051
2010		2,986
2011		2,767
2012		2,771
2013		2,767
Thereafter		17,678
Total firm transportation commitments	$	32,020

PVR natural gas midstream segment firm transportation commitments

As of December 31, 2008, PVR had contracts for firm transportation capacity rights for specified volumes per day on a pipeline system with terms that ranged from one to seven years. The contracts require PVR to pay transportation demand charges regardless of the amount of pipeline capacity PVR uses. PVR may sell excess capacity to third parties at its discretion. The following table sets forth PVR’s obligation for firm transportation commitments in effect at December 31, 2008 for the next five years and thereafter:

Year	Firm transportation commitments
	(in thousands)
2009	$	13,069
2010		6,168
2011		5,694
2012		4,508
2013		4,033
Thereafter		3,321
Total firm transportation commitments	$	36,793

Legal

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

Environmental compliance

Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the

49

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

PVR’s operations and those of its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of PVR’s coal property leases impose liability 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 December 31, 2008 and 2007, PVR’s environmental liabilities were $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.

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.

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24. Guarantor subsidiaries

The following subsidiaries may become guarantors upon the issuance of senior notes of the Company: Penn Virginia Holding Corp., Penn Virginia Oil and Gas Corporation, Penn Virginia Oil & Gas GP LLC, Penn Virginia Oil & Gas LP LLC, Penn Virginia Oil & Gas, L.P., Penn Virginia MC Corporation, Penn Virginia MC Energy L.L.C. and Penn Virginia MC Operating Company L.L.C. (collectively, the “Guarantor Subsidiaries”). As such, the Company will become subject to the requirements of Rule 3-10 of Regulation S-X of the Securities and Exchange Commission regarding financial statements of guarantors and issuers of registered guaranteed securities. As permitted under Rule 3-10(f), the Company is complying with the requirements of this rule by the addition of a footnote to the Notes to the Consolidated Financial Statements as each of the Guarantor Subsidiaries is 100% owned by us, any guarantees will be full and unconditional and joint and several. The primary non-guarantor subsidiaries will be PVG and PVR.

The condensed consolidating financial statements below present the financial position, results of operations and cash flows of the Company, the Guarantor Subsidiaries and non-guarantor subsidiaries as currently contemplated.

Balance Sheets

	December 31, 2008
(in thousands)	Penn Virginia Corporation	Guarantor subsidiaries	Non-guarantor subsidiaries	Eliminations		Consolidated
Assets
Cash and cash equivalents	—	—	18,338	—		18,338
Accounts receivable	—	75,962	73,279	—		149,241
Inventory	—	16,595	1,873	—		18,468
Other current assets	37,455	7,241	32,823	(48	)	77,471
Total current assets	37,455	99,798	126,313	(48	)	263,518
Property and equipment, net	8,255	1,636,830	895,247	(29,157	)	2,511,175
Investments in affiliates (equity method)	1,571,692	265,870	—	(1,837,562	)	—
Other assets	33,846	49	237,065	(49,101	)	221,859
Total assets	1,651,248	2,002,547	1,258,625	(1,915,868	)	2,996,552
Liabilities and shareholders’ equity
Current maturities of long-term debt	7,542	—	—	—		7,542
Accounts payable and accrued liabilities	8,294	129,190	69,418	—		206,902
Other current liabilities	15,032	—	18,166	(48	)	33,150
Total current liabilities	30,868	129,190	87,584	(48	)	247,594
Deferred income taxes	—	294,890	—	(49,101	)	245,789
Long-term debt of the Company	562,000	—	—	—		562,000
Long-term debt of subsidiary	—	—	568,100	—		568,100
Other long-term liabilities	10,433	6,775	37,400	—		54,608
Minority interests of subsidiaries	—	—	299,671	—		299,671
Shareholders’ equity	1,047,947	1,571,692	265,870	(1,866,719	)	1,018,790
Total liabilities and shareholders’ equity	1,651,248	2,002,547	1,258,625	(1,915,868	)	2,996,552

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	December 31, 2007
(in thousands)	Penn Virginia Corporation	Guarantor subsidiaries	Non-guarantor subsidiaries	Eliminations		Consolidated
Assets
Cash and cash equivalents	4,035	—	30,492	—		34,527
Accounts receivable	—	100,223	78,989	(92	)	179,120
Notes receviable—affiliates	—	—	16,198	(16,198	)	—
Inventory	—	3,063	2,131	—		5,194
Other current assets	4,872	1,115	20,215	(971	)	25,231
Total current assets	8,907	104,401	148,025	(17,261	)	244,072
Property and equipment, net	10,307	1,188,049	731,432	(30,774	)	1,899,014
Investments in affiliates (equity method)	1,177,768	255,388	—	(1,433,156	)	—
Other assets	36,923	27	125,186	(51,761	)	110,375
Total assets	1,233,905	1,547,865	1,004,643	(1,532,952	)	2,253,461
Liabilities and shareholders’ equity
Current maturities of long-term debt	—	—	12,561	—		12,561
Accounts payable and accrued liabilities	9,297	118,540	77,382	(92	)	205,127
Notes payable—affiliates	16,198	—	—	(16,198	)	—
Other current liabilities	3,449	—	41,733	(971	)	44,211
Total current liabilities	28,944	118,540	131,676	(17,261	)	261,899
Deferred income taxes	—	245,712	—	(51,762	)	193,950
Long-term debt of the Company	352,000	—	—	—		352,000
Long-term debt of subsidiary	—	—	399,153	—		399,153
Other long-term liabilities	12,090	5,845	39,264	—		57,199
Minority interests of subsidiaries	—	—	179,162	—		179,162
Shareholders’ equity	840,871	1,177,768	255,388	(1,463,929	)	810,098
Total liabilities and shareholders’ equity	1,233,905	1,547,865	1,004,643	(1,532,952	)	2,253,461

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Income Statements

	Year ended December 31, 2008
(in thousands)	Penn Virginia Corporation			Guarantor subsidiaries		Non-guarantor subsidiaries			Eliminations			Consolidated
Revenues	$	3		$	469,330	$	881,737		$	(130,219	)	$	1,220,851
Cost of midstream gas purchased		—			—		612,530			(127,909	)		484,621
Operating		—			59,459		32,744			(2,312	)		89,891
Exploration		—			42,436		—			—			42,436
Taxes other than income		984			23,336		4,266			—			28,586
General and administrative		24,210			21,285		28,999			—			74,494
Impairment of oil and gas properties		—			19,963		31,801			—			51,764
Depreciation, depletion and amortization		3,388			132,276		58,189			(1,617	)		192,236
Operating expenses		28,582			298,755		768,529			(131,838	)		964,028
Operating income		(28,579	)		170,575		113,208			1,619			256,823
Equity in earnings of subsidiaries		134,321			28,259		—			(162,580	)		—
Interest expense and other		(18,348	)		—		(26,579	)		—			(44,927	)
Derivatives		29,745			—		16,837			—			46,582
Income before minority interest and income taxes		117,139			198,834		103,466			(160,961	)		258,478
Minority interest		—			—		60,436			—			60,436
Income tax expense		(5,411	)		64,513		14,771			1			73,874
Net income	$	122,550		$	134,321	$	28,259		$	(160,962	)	$	124,168

	Year ended December 31, 2007
(in thousands)	Penn Virginia Corporation			Guarantor subsidiaries		Non-guarantor subsidiaries			Eliminations			Consolidated
Revenues	$	(305	)	$	334,521	$	549,734		$	(31,000	)	$	852,950
Cost of midstream gas purchased		—			—		343,293			—			343,293
Operating		—			46,713		20,897			—			67,610
Exploration		—			28,608		—			—			28,608
Taxes other than income		780			17,847		3,096			—			21,723
General and administrative		25,282			16,283		25,418			—			66,983
Impairment of oil and gas properties		—			2,586		—			—			2,586
Depreciation, depletion and amortization		985			87,223		41,541			(226	)		129,523
Operating expenses		27,047			199,260		434,245			(226	)		660,326
Operating income		(27,352	)		135,261		115,489			(30,774	)		192,624
Equity in earnings of subsidiaries		111,729			27,942		—			(139,671	)		—
Interest expense and other		(20,271	)		13		(13,510	)		—			(33,768	)
Derivatives		(1,715	)		—		(45,567	)		—			(47,282	)
Income before minority interest and income taxes		62,391			163,216		56,412			(170,445	)		111,574
Minority interest		—			—		30,319			—			30,319
Income tax expense		(19,137	)		51,487		(1,849	)		—			30,501
Net income	$	81,528		$	111,729	$	27,942		$	(170,445	)	$	50,754

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	Year ended December 31, 2006
(in thousands)	Penn Virginia Corporation			Guarantor subsidiaries		Non-guarantor subsidiaries			Eliminations			Consolidated
Revenues	$	(17	)	$	235,965	$	517,981		$	—		$	753,929
Cost of midstream gas purchased		—			—		334,594			—			334,594
Operating		—			27,403		20,003			—			47,406
Exploration		—			34,330		—			—			34,330
Taxes other than income		562			11,810		2,395			—			14,767
General and administrative		15,697			12,828		21,041			—			49,566
Impairment of oil and gas properties		—			8,517		—			—			8,517
Depreciation, depletion and amortization		458			56,237		37,522			—			94,217
Operating expenses		16,717			151,125		415,555			—			583,397
Operating income		(16,734	)		84,840		102,426			—			170,532
Equity in earnings of subsidiaries		70,621			19,248		—			(89,869	)		—
Interest expense and other		(6,119	)		36		(15,031	)		—			(21,114	)
Derivatives		30,757			—		(11,260	)		—			19,497
Income before minority interest and income taxes		78,525			104,124		76,135			(89,869	)		168,915
Minority interest		—			—		43,018			—			43,018
Income tax expense		2,616			33,503		13,869			—			49,988
Net income	$	75,909		$	70,621	$	19,248		$	(89,869	)	$	75,909

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Statements of Cash Flows

	Year ended December 31, 2008
(in thousands)	Penn Virginia Corporation			Guarantor subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(4,813	)	$	313,139		$	75,448		$	—		$	383,774
Cash flows provided by (used in) investing activities:
(Investment in) distributions from affiliates		(217,542	)		44,018			—			173,524			—
Proceeds from the sale of property and equipment and other		—			32,521			998			—			33,519
Additions to property and equipment		(1,588	)		(607,220	)		(270,278	)		—			(879,086	)
Net cash provided by (used in) investing activities		(219,130	)		(530,681	)		(269,280	)		173,524			(845,567	)
Cash flows provided by (used in) financing activities:
Distributions paid to minority interest holders		—			—			(64,245	)		—			(64,245	)
Short-term bank borrowings		7,542			—			—			—			7,542
Proceeds from borrowings of the Company		273,000			—			—			—			273,000
Repayments of borrowings of the Company		(63,000	)		—			—			—			(63,000	)
Capital contributions from (distributions to) affiliates		—			217,542			(44,018	)		(173,524	)		—
Proceeds from PVR issuance of units		—			—			138,141			—			138,141
Proceeds from PVR long-term debt		—			—			453,800			—			453,800
Repayment of PVR long-term debt		—			—			(297,800	)		—			(297,800	)
Other		2,366			—			(4,200	)		—			(1,834	)
Net cash provided by (used in) financing activities		219,908			217,542			181,678			(173,524	)		445,604
Net increase (decrease) in cash and cash equivalents		(4,035	)		—			(12,154	)		—			(16,189	)
Cash and cash equivalents-beginning of period		4,035			—			30,492			—			34,527
Cash and cash equivalents-end of period	$	—		$	—		$	18,338		$	—		$	18,338

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	Year ended December 31, 2007
(in thousands)	Penn Virginia Corporation			Guarantor subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	13,376		$	174,655		$	124,999		$	—		$	313,030
Cash flows provided by (used in) investing activities:
(Investment in) distributions from affiliates		(247,811	)		29,840			—			217,971			—
Proceeds from the sale of property and equipment and other		—			60,169			858			(31,000	)		30,027
Additions to property and equipment		(6,995	)		(512,475	)		(225,040	)		31,000			(713,510	)
Net cash provided by (used in) investing activities		(254,806	)		(422,466	)		(224,182	)		217,971			(683,483	)
Cash flows provided by (used in) financing activities:
Distributions paid to minority interest holders		—			—			(49,739	)		—			(49,739	)
Net proceeds from PVA stock offering		135,441			—			—			—			135,441
Cash received for stock warrants sold		18,187			—			—			—			18,187
Cash paid for convertible not hedges		(36,817	)		—			—			—			(36,817	)
Proceeds from borrowings of the Company		513,500			—			—			—			513,500
Repayments of borrowings of the Company		(382,500	)		—			—			—			(382,500	)
Capital contributions from (distributions to) affiliates		—			247,811			(29,840	)		(217,971	)		—
Proceeds from PVR long-term debt		—			—			220,500			—			220,500
Repayment of PVR long-term debt		—			—			(27,000	)		—			(27,000	)
Other		(7,527	)		—			597			—			(6,930	)
Net cash provided by (used in) financing activities		240,284			247,811			114,518			(217,971	)		384,642
Net increase (decrease) in cash and cash equivalents		(1,146	)		—			15,335			—			14,189
Cash and cash equivalents-beginning of period		5,181			—			15,157			—			20,338
Cash and cash equivalents-end of period	$	4,035		$	—		$	30,492		$	—		$	34,527

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	Year ended December 31, 2006
(in thousands)	Penn Virginia Corporation			Guarantor subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	8,898		$	164,791		$	102,130		$	—		$	275,819
Cash flows provided by (used in) investing activities:
(Investment in) distributions from affiliates		(142,000	)		22,186			—			119,814			—
Proceeds from the sale of property and equipment and other		—			2,568			36			—			2,604
Additions to property and equipment		(3,682	)		(331,545	)		(129,712	)		—			(464,939	)
Net cash provided by (used in) investing activities		(145,682	)		(306,791	)		(129,676	)		119,814			(462,335	)
Cash flows provided by (used in) financing activities:
Distributions paid to minority interest holders		—			—			(38,627	)		—			(38,627	)
Proceeds from borrowings of the Company		162,000			—			—			—			162,000
Repayments of borrowings of the Company		(20,000	)		—			—			—			(20,000	)
Capital contributions from (distributions to) affiliates		—			142,000			(22,186	)		(119,814	)		—
Proceeds from PVR issuance of units		—			—			117,818			—			117,818
Proceeds from PVR long-term debt		—			—			85,800			—			85,800
Repayment of PVR long-term debt		—			—			(122,900	)		—			(122,900	)
Other		(2,775	)		—			(375	)		—			(3,150	)
Net cash provided by (used in) financing activities		139,225			142,000			19,530			(119,814	)		180,941
Net increase (decrease) in cash and cash equivalents		2,441			—			(8,016	)		—			(5,575	)
Cash and cash equivalents-beginning of period		2,740			—			23,173			—			25,913
Cash and cash equivalents-end of period	$	5,181		$	—		$	15,157		$	—		$	20,338

25. 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

57

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.

The following table presents a summary of certain financial information relating to our segments as of and for the years ended December 31, 2008, 2007 and 2006:

	Revenues						Intersegment revenues(1)
	2008		2007		2006		2008			2007			2006
Oil and gas(2)	$	471,479	$	304,790	$	236,238	$	(2,149	)	$	(1,549	)	$	(282	)
Coal and natural resource(3)		152,535		110,847		112,189		792			792			792
Natural gas midstream(4)		595,884		436,257		404,628		132,369			1,549			282
Eliminations and other		953		1,056		874		(131,012	)		(792	)		(792	)
Consolidated totals	$	1,220,851	$	852,950	$	753,929	$	—		$	—		$	—

	Operating income									DD&A expense
	2008			2007			2006			2008		2007		2006
Oil and gas	$	170,576		$	103,983		$	84,833		$	132,276	$	87,223	$	56,237
Coal and natural resource		96,296			68,811			73,444			30,805		22,690		20,399
Natural gas midstream		18,946			48,914			29,376			27,361		18,822		17,094
Eliminations and other		(28,995	)		(29,084	)		(17,121	)		1,794		788		487
Consolidated totals	$	256,823		$	192,624		$	170,532		$	192,236	$	129,523	$	94,217
Interest expense		(44,261	)		(37,419	)		(24,832	)
Other		(666	)		3,651			3,718
Derivatives		46,582			(47,282	)		19,497
Minority interest		(60,436	)		(30,319	)		(43,018	)
Income tax expense		(73,874	)		(30,501	)		(49,988	)
Consolidated net income	$	124,168		$	50,754		$	75,909

	Additions to property and equipment								Total assets at December 31,
	2008			2007			2006		2008		2007		2006
Oil and gas	$	607,220		$	512,473		$	331,551	$	1,727,373	$	1,287,359	$	885,550
Coal and natural resource(5)		27,270			177,960			92,697		600,418		610,866		409,709
Natural gas midstream(6)		304,758			47,080			37,015		618,402		320,413		304,314
Eliminations and other		(60,162	)		(24,003	)		3,676		50,359		34,823		33,576
Consolidated totals	$	879,086		$	713,510		$	464,939	$	2,996,552	$	2,253,461	$	1,633,149

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(1) Intersegment revenues represent gas gathering and processing transactions between the PVR natural gas midstream segment and the oil and gas segment. Intersegment revenues also represent agent fees paid by the oil and gas segment to the PVR natural gas midstream segment for marketing certain natural gas production and rail car rental fees paid by a corporate affiliate to the PVR coal and natural resource management segment.

(2) Oil and gas segment revenues for the year ended December 31, 2007 excludes $31.0 million of gain related to the sale of royalty interests to PVR. See Note 4—“Acquisitions and Divestitures.”

(3) The PVR coal and natural resource management segment’s revenues for the years ended December 31, 2008, 2007 and 2006 include $1.8 million, $1.8 million and $1.3 million of equity earnings related to PVR’s 50% interest in Coal Handling Solutions LLC.

(4) The PVR natural gas midstream segment’s revenues for the year ended December 31, 2008 include $2.4 million of equity earnings related to PVR’s 25% member interest in Thunder Creek that PVR acquired in 2008 for $51.6 million. See Note 4—“Acquisitions and Divestitures,” for a further description of this acquisition.

(5) Total assets at December 31, 2008, 2007 and 2006 for the PVR coal and natural resource management segment included equity investment of $23.4 million, $25.6 million and $25.3 million related to PVR’s 50% interest in Coal Handling Solutions LLC.

(6) Total assets at December 31, 2008 for the PVR natural gas midstream segment included equity investment of $55.0 million related to PVR’s 25% member interest in Thunder Creek that PVR acquired in 2008. See Note 4—“Acquisitions and Divestitures,” for a further description of this acquisition. Total assets at December 31, 2007 and 2006 for the PVR natural gas midstream segment included goodwill of $7.7 million. The PVR natural gas midstream segment had no goodwill balance remaining in total assets at December 31, 2008, due to $31.8 million of losses on the impairment of goodwill. See Note 12, “Goodwill.”

Operating income is equal to total revenues less cost of midstream gas purchased, operating costs and expenses and DD&A expenses. Operating income does not include certain other income items, interest expense, interest income and income taxes. Identifiable assets are those assets used in our operations in each segment.

For the year ended December 31, 2008, two third-party customers of the PVR natural gas midstream segment accounted for $288.7 million, or 24%, of our total consolidated net revenues, and two third-party customers of our oil and gas segment accounted for $142.3 million, or 11% of our total consolidated net revenues. These customer concentrations may impact our results of operations, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We are not aware of any financial difficulties experienced by these customers.

Intercompany railcar rental revenues were $0.8 million in 2008 and are included in the PVR coal and natural resource management segment. The offsetting railcar rental expense and the elimination of the revenue and expense are included in the corporate and other column of the preceding table. In 2008, the oil and gas segment paid $3.0 million to the PVR natural gas midstream segment for marketing a portion of the oil and gas segment’s natural gas production.

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 $127.9 million to sell to third parties. In 2008, PVR recorded $127.9 million of natural gas midstream revenue and $127.9 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP and the subsequent sale of that gas to third parties. PVR does not take title to the gas prior to transporting it to third parties. These transactions do not impact the gross margin, nor do they impact operating income.

For the year ended December 31, 2007, one customer of the PVR natural gas midstream segment accounted for $109.2 million, or 13%, of our total consolidated net revenues. Intercompany railcar rental revenues were $0.8 million in 2007 and are included in the PVR coal and natural resource management segment. The offsetting railcar rental expense and the elimination of the revenue and expense are included in the corporate and other column of the preceding table. In 2007, the oil and gas segment paid $2.2 million to the PVR natural gas midstream segment for marketing a portion of the oil and gas segment’s natural gas production.

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For the year ended December 31, 2006, one customer of the PVR natural gas midstream segment accounted for $129.1 million, or 17%, of our total consolidated net revenues. Intercompany railcar rental revenues were $0.8 million in 2006 and are included in the PVR coal and natural resource management segment. The offsetting railcar rental expense and the elimination of the revenue and expense are included in the corporate and other column of the preceding table. In 2006, the oil and gas segment paid $0.4 million to the PVR natural gas midstream segment for marketing a portion of the oil and gas segment’s natural gas production. The marketing agreement was effective September 1, 2006.

Supplemental quarterly financial information (unaudited)

(in thousands, except share data)	First quarter		Second quarter			Third quarter		Fourth quarter
2008
Revenues	$	249,135	$	360,414		$	385,612	$	225,690
Operating income(1)	$	60,133	$	106,224		$	122,327	$	(31,861	)
Net income	$	3,926	$	(3,793	)	$	123,738	$	297
Net income per share(2):
Basic	$	0.09	$	(0.09	)	$	2.95	$	0.01
Diluted	$	0.09	$	(0.09	)	$	2.90	$	0.01
Weighted average shares outstanding(2):
Basic		41,558		41,740			41,881		41,907
Diluted		41,803		41,740			42,544		42,006
2007
Revenues	$	186,270	$	222,398		$	215,758	$	228,524
Operating income	$	38,539	$	57,074		$	51,884	$	45,127
Net income	$	4,403	$	23,878		$	17,114	$	5,359
Net income per share(2):
Basic	$	0.12	$	0.63		$	0.45	$	0.14
Diluted	$	0.11	$	0.63		$	0.45	$	0.14
Weighted average shares outstanding(2):
Basic		37,594		37,750			37,898		38,805
Diluted		38,316		38,055			38,213		39,157
2006
Revenues	$	200,907	$	179,150		$	188,393	$	185,479
Operating income	$	48,666	$	49,939		$	44,644	$	27,283
Net income	$	24,108	$	18,217		$	22,881	$	10,703
Net income per share(2):
Basic	$	0.65	$	0.49		$	0.61	$	0.29
Diluted	$	0.64	$	0.48		$	0.61	$	0.28
Weighted average shares outstanding(2):
Basic		37,304		37,354			37,358		37,492
Diluted		37,746		37,826			37,790		37,872

(1) Operating income in 2008 included a loss on the impairment of goodwill of $31.8 million that was recorded in the fourth quarter of 2008. See Note 12, “Goodwill.”

(2) The sum of the quarters may not equal the total of the respective year’s net income per share due to changes in the weighted average shares outstanding throughout the year. The net income per share and weighted average shares outstanding has been adjusted to reflect the two-for-one stock split in June 2007. See Note 5—“Stock Split.”

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Supplemental information on oil and gas producing activities (unaudited)

The following supplemental information regarding the oil and gas producing activities is presented in accordance with the requirements of the SEC and SFAS No. 69,Disclosures about Oiland Gas Producing Activities. The amounts shown include our net working and royalty interest in all of our oil and gas operations.

Capitalized costs relating to oil and gas producing activities

	Year ended December 31,
(in thousands)	2008			2007			2006
Proved properties	$	322,030		$	280,742		$	213,017
Unproved properties		154,801			127,805			100,008
Wells, equipment and facilities		1,623,274			1,112,688			729,443
Support equipment		6,021			4,493			2,713
		2,106,126			1,525,728			1,045,181
Accumulated depreciation and depletion		(469,296	)		(337,679	)		(247,523	)
Net capitalized costs	$	1,636,830		$	1,188,049		$	797,658

In accordance with SFAS No. 143, during the years ended December 31, 2008, 2007 and 2006, an additional $0.5 million, $0.5 million and $1.4 million were added to the cost basis of oil and gas wells for wells drilled.

Costs incurred in certain oil and gas activities

	Year ended December 31,
(in thousands)	2008		2007		2006
Proved property acquisition costs	$	—	$	88,174	$	72,724
Unproved property acquisition costs		93,110		18,817		56,563
Exploration costs		30,373		46,425		51,665
Development costs and other		518,213		367,012		184,675
Total costs incurred	$	641,696	$	520,428	$	365,627

Costs for the year ended December 31, 2006 include deferred income taxes of $32.3 million provided for the book versus tax basis difference related to the acquired Crow Creek properties.

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Results of operations for oil and gas producing activities

The following table includes results solely from the production and sale of oil and gas and a non-cash charge for property impairments. It excludes corporate-related general and administrative expenses and gains or losses on property dispositions. The income tax expense is calculated by applying the statutory tax rates to the revenues after deducting costs, which include depletion allowances and giving effect to oil and gas related permanent differences and tax credits.

	Years ended December 31,
(in thousands)	2008		2007		2006
Revenues	$	436,622	$	290,286	$	234,156
Production expenses		82,191		65,130		39,681
Exploration expenses		42,436		28,608		34,330
Depreciation and depletion expense		132,276		87,223		56,237
Impairment of oil and gas properties		19,963		2,586		8,517
		159,756		106,739		95,391
Income tax expense		61,985		41,628		37,775
Results of operations	$	97,771	$	65,111	$	57,616

In accordance with SFAS No. 143, the combined depletion and accretion expense related to AROs that were recognized during 2008, 2007 and 2006 in DD&A expense was approximately $0.4 million, $0.7 million and $0.2 million.

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Oil and gas reserves

The following table sets forth the net quantities of proved reserves and proved developed reserves during the periods indicated. This information includes the oil and gas segment’s royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the three years ended December 31, 2008 were estimated by Wright and Company, Inc., utilizing data compiled by us. All reserves are located in the United States. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available. Proved reserves are the estimated quantities of crude oil, condensate and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

Proved developed and undeveloped reserves	Natural gas (MMcf)		Oil and condensate (MBbl)		Total equivalents (MMcfe)
December 31, 2005	359,181		2,897		376,560
Revisions of previous estimates	(10,182	)	396		(7,807	)
Extensions, discoveries and other additions	97,286		597		100,867
Production	(28,967	)	(382	)	(31,260	)
Purchase of reserves	39,928		1,402		48,346
Sale of reserves in place	—		—		—
December 31, 2006	457,246		4,910		486,706
Revisions of previous estimates	(19,554	)	3,853		3,566
Extensions, discoveries and other additions	137,634		6,547		176,915
Production	(37,802	)	(461	)	(40,569	)
Purchase of reserves	72,102		390		74,440
Sale of reserves in place	(21,363	)	(19	)	(21,476	)
December 31, 2007	588,263		15,220		679,582
Revisions of previous estimates	(59,828	)	(131	)	(60,614	)
Extensions, discoveries and other additions	267,190		12,783		343,888
Production	(41,493	)	(898	)	(46,881	)
Purchase of reserves	—		—		—
Sale of reserves in place	—		—		—
December 31, 2008	754,132		26,974		915,975
Proved Developed Reserves:
December 31, 2006	326,480		3,049		344,775
December 31, 2007	372,626		4,463		399,404
December 31, 2008	411,366		9,895		470,736

The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved reserves. Future cash inflows were computed by applying year-end prices of oil and gas to the estimated future production of proved reserves. Natural gas prices were escalated only where existing contracts contained fixed and determinable escalation

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clauses. Contractually provided natural gas prices in excess of estimated market clearing prices were used in computing the future cash inflows only if we expect to continue to receive higher prices under legally enforceable contract terms. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.

Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to our proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of statutory depletion in excess of tax basis, available net operating loss carryforwards and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate.

	Year ended December 31,
(in thousands)	2008			2007			2006
Future cash inflows	$	5,031,678		$	5,140,818		$	2,848,046
Future production costs		(1,588,959	)		(1,496,057	)		(775,561	)
Future development costs		(924,219	)		(667,118	)		(321,338	)
Future net cash flows before income tax		2,518,500			2,977,643			1,751,147
Future income tax expense		(567,779	)		(727,561	)		(435,299	)
Future net cash flows		1,950,721			2,250,082			1,315,848
10% annual discount for estimated timing of cash flows		(1,221,320	)		(1,278,172	)		(711,248	)
Standardized measure of discounted future net cash flows	$	729,401		$	971,910		$	604,600

Changes in standardized measure of discounted future net cash flows

	Year ended December 31,
	2008			2007			2006
Sales of oil and gas, net of productions costs	$	(355,552	)	$	(227,136	)	$	(196,284	)
Net changes in prices and production costs		(318,730	)		277,245			(720,914	)
Extensions, discoveries and other additions		233,603			241,497			142,007
Development costs incurred during the period		112,925			108,584			50,629
Revisions of previous quantity estimates		(93,346	)		17,846			(24,460	)
Purchase of minerals-in-place		—			69,179			51,810
Sale of minerals-in-place		—			(42,395	)		—
Accretion of discount		126,114			78,744			141,165
Net change in income taxes		110,670			(106,398	)		192,370
Other changes		(58,193	)		(49,856	)		(68,169	)
Net increase (decrease)		(242,509	)		367,310			(431,846	)
Beginning of year		971,910			604,600			1,036,446
End of year	$	729,401		$	971,910		$	604,600

The changes in standardized measure relating to sales of reserves are calculated using prices in effect as of the beginning of the period and changes in standardized measure relating to

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purchases of reserves are calculated using prices in effect at the end of the period. Accordingly, the changes in standardized measure for purchases and sales of reserves reflected above do not necessarily represent the economic reality of such transactions. See “Costs Incurred in Certain Oil and Gas Activities” earlier in this Note and our consolidated statements of cash flows.

Revised oil and gas standard

In December 2008, the SEC released the final rule forModernization of Oil and Gas Reporting, or Modernization. The Modernization disclosure requirements will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies will also be allowed to disclose probable and possible reserves to investors in SEC filed documents. In addition, companies will be required to report the independence and qualifications of its reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The Modernization disclosure requirements will become effective for the year ended December 31, 2009. The SEC is coordinating with the FASB to obtain the revisions necessary under SFAS No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies, and SFAS No. 69,Disclosures about Oil and Gas Producing Activities, to provide consistency with the Modernization. In the event that consistency is not achieved in time for companies to comply with the Modernization, the SEC will consider delaying the compliance date.

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