Filed Pursuant to Rule 424(B)(3)
File Number 333-143852

This preliminary prospectus supplement relates to an effective registration statement but is not complete and may be changed. This preliminary prospectus supplement and the accompanying prospectus are not an offer to sell these notes and are not soliciting an offer to buy these notes in any jurisdiction where the offer or sale is not permitted.

Subject to completion, dated June 3, 2009

Preliminary prospectus supplement

(To prospectus dated June 18, 2007)

$250,000,000

    % Senior Notes due 2016

Interest payable                      and                    

The notes will mature on                 , 2016. Interest on the notes will accrue from                 , 2009 and the first payment will be on                 , 2009.

We may redeem some or all of the notes at any time on or after                 , 2013 at the redemption prices set forth beginning on page S-174 and prior to such date at a “make-whole” redemption price. We may also redeem up to 35% of the notes prior to                 , 2012 with cash proceeds we receive from certain equity offerings. If we sell certain assets and do not reinvest the proceeds or repay senior indebtedness or if we experience specific kinds of changes of control, we must offer to repurchase the notes.

The notes will be our senior unsecured obligations and will rank equally with all of our other unsecured senior indebtedness that is not by its terms subordinated to the notes. The notes will be senior to our existing and future subordinated indebtedness, including our 4.50% Convertible Senior Subordinated Notes due 2012. The notes will be effectively subordinated to all of our secured indebtedness (including our revolving credit facility) to the extent of the collateral securing that indebtedness.

The obligations under the notes will be fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under our revolving credit facility. The guarantee of any subsidiary will be released when such subsidiary no longer has outstanding or guarantees certain specified indebtedness, when such subsidiary is no longer a subsidiary of ours or when such subsidiary is designated an unrestricted subsidiary under the terms of the indenture. The guarantees will be equal in right of payment with the existing and future unsecured senior indebtedness of the guarantors, including the guarantees of our revolving credit facility, and will rank senior to the future subordinated indebtedness of the guarantors. The guarantees will be effectively junior to all existing and future secured indebtedness of the guarantors, including guarantees of our revolving credit facility to the extent of the collateral securing such indebtedness. Not all of our subsidiaries will guarantee the notes. The notes will be structurally subordinated to the indebtedness and other liabilities of our non-guarantor subsidiaries, including Penn Virginia G.P. Holdings, L.P. and Penn Virginia Resource Partners, L.P.

Investing in the notes involves risks. See “Risk factors” beginning on page S-18.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these notes or determined if this prospectus supplement or the accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

	Price to public(1)	Underwriting discounts and commissions	Proceeds to Penn Virginia Corporation(1)
Per note	%	%	%
Total	$	$	$

(1) Plus accrued interest, if any, from                     , 2009.

The notes will not be listed on a securities exchange. Currently, there is no public market for the notes.

We expect that delivery of the notes to purchasers will be made on or about                 , 2009 in book-entry form through The Depository Trust Company for the account of its participants, including Clearstream Banking société anonyme and Euroclear Bank S.A./N.V.

Joint book-running managers

J.P. Morgan	Banc of America Securities LLC
Wachovia Securities	Barclays Capital

Senior Co-managers

BNP PARIBAS RBC Capital Markets

Co-managers

Capital One Southcoast PNC Capital Markets LLC UBS Investment Bank

                    , 2009

Table of contents

Prospectus supplement

	Page
About this prospectus supplement	S-ii
Forward-looking statements	S-iii
Summary	S-1
Risk factors	S-18
Use of proceeds	S-48
Capitalization	S-49
Selected historical financial data	S-50
Management’s discussion and analysis of financial condition and results of operations	S-54
Business	S-127
Transactions with related persons	S-161
Management	S-164
Description of other indebtedness	S-167

	Page
Description of notes	S-172
Book-entry, delivery and form	S-237
Certain United States federal income and estate tax consequences	S-242
Underwriting	S-248
Legal matters	S-251
Engineers	S-251
Experts	S-251
Available information	S-251
Incorporation of certain documents by reference	S-252
Glossary of selected terms	A-1
Penn Virginia Corporation and subsidiaries index to financial statements	F-1

Prospectus

	Page
About this prospectus	1
About Penn Virginia Corporation	1
The subsidiary guarantors	1
Where you can find more information	2
Forward-looking statements	3
Use of proceeds	5
Ratios of earnings to fixed charges	5

	Page
Description of debt securities	5
Description of capital stock	15
Description of depositary shares	21
Description of warrants	21
Plan of distribution	22
Legal matters	23
Experts	23

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About this prospectus supplement

This document is in two parts. The first part is this prospectus supplement and the documents incorporated by reference herein, which, among other things, describes the specific terms of this offering. The second part, the accompanying prospectus and the documents incorporated by reference therein, gives more general information, some of which may not apply to this offering. If the description of this offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement.

You should rely only on the information contained in or incorporated by reference in this prospectus supplement, the accompanying prospectus and any related free writing prospectus. We have not authorized anyone to provide you with different information. We are not and the underwriters are not making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should not assume that the information contained in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the date on the front of this prospectus supplement.

Except in the section under the caption “Description of notes” and unless the context otherwise requires, all references in this prospectus supplement to:

• “Penn Virginia,” “Issuer,” “us,” “we,” “our” or “our Company” are to Penn Virginia Corporation, a Virginia corporation, together with its consolidated subsidiaries;

• “PVOG” are to Penn Virginia Oil and Gas Corporation, a Virginia corporation and a wholly owned subsidiary of Penn Virginia Corporation, together with its wholly owned subsidiaries;

• “PVG” are to Penn Virginia GP Holdings, L.P., a Delaware limited partnership;

• “PVR” are to Penn Virginia Resource Partners, L.P., a Delaware limited partnership; and

• “Restricted Group” are to Penn Virginia Corporation and each of the subsidiaries of Penn Virginia Corporation that guarantee debt under the existing Penn Virginia revolving credit facility (including the subsidiaries engaged in the oil and gas business), on a consolidating basis. PVG, PVR and their respective subsidiaries are not in the Restricted Group.

See “Glossary of selected terms” beginning on page A-1 for abbreviations and definitions commonly used in the oil, natural gas and coal industries that are used in this prospectus supplement.

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Forward-looking statements

Some of the information included in this prospectus supplement, the accompanying prospectus and the documents we incorporate by reference contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, referred to as the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, referred to as the Exchange Act. These statements use forward-looking words such as “may,” “will,” “should,” “could,” “achievable,” “anticipate,” “believe,” “expect,” “estimate,” “project” or other words and phrases of similar meaning. These statements discuss goals, intentions and expectations as to future trends, plans, events, results of operations or financial condition or state other “forward-looking” information. A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statements. We believe we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that assumed facts or bases almost always vary from actual results, and the differences between assumed facts or bases and actual results can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the cautionary statements in this prospectus supplement, the accompanying prospectus and the documents we have incorporated by reference. These statements reflect our current views with respect to future events and are subject to various risks, uncertainties and assumptions, including, but not limited, to the following:

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

• our ability to access external sources of capital;

• uncertainties relating to the occurrence and success of capital-raising transactions, including securities offerings and asset sales;

• reductions in the borrowing base under our revolving credit facility, or our Revolver;

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

• any impairment writedowns of our reserves;

• reductions in our anticipated capital expenditures;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• hedging results;

• accidents;

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

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

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

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

• uncertainties relating to our continued ownership of interests in PVG and PVR; and

• other risks set forth in “Risk factors” in this prospectus supplement and in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008 and the other documents incorporated herein by reference.

All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this prospectus supplement and the accompanying prospectus and in the documents incorporated herein and therein by reference. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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Summary

This summary highlights selected information contained elsewhere in this prospectus supplement, the prospectus and in the documents we incorporate by reference. This summary is not complete and does not contain all of the information that you should consider before deciding whether or not to invest in the notes. For a more complete understanding of our Company and this offering, we encourage you to read this entire document, including “Risk factors,” the financial and other information incorporated by reference in this prospectus supplement and the other documents to which we have referred. The notes we will issue in this offering will be guaranteed by each of our subsidiaries primarily engaged in the oil and gas business.

Penn Virginia Corporation

We are an independent oil and gas company primarily engaged in the development, exploration and production of natural gas and oil through our wholly owned subsidiary, Penn Virginia Oil & Gas Corporation, or PVOG. We also own partner interests in Penn Virginia Resource Partners, L.P., or PVR, which is involved in the coal and natural resource management and natural gas midstream businesses, and Penn Virginia GP Holdings, L.P., or PVG, which owns PVR’s general partner. For the twelve months ended March 31, 2009, the Restricted Group had net income of $109.1 million and Adjusted EBITDAX of $346.6 million, including cash distributions from PVG and PVR. See “—Summary historical financial data” for a reconciliation of net income to Adjusted EBITDAX. Of the Adjusted EBITDAX amount, $301.4 million was generated from our oil and gas business and $45.1 million was received from cash distributions in respect of our partner interests in PVG and PVR.

On May 22, 2009 we completed the sale of 3,500,000 shares of our common stock in a registered public offering. The net proceeds of the sale were $64.9 million and were used to repay a portion of the outstanding borrowings under our Revolver. The net proceeds of this offering also will be used to repay a portion of the outstanding borrowings under our Revolver. We are actively considering additional alternatives to further improve our liquidity and financial flexibility, including potential sales of substantial assets, including all or a portion of the partner interests in PVG and PVR that we own. See “Risk factors—Risks related to our ownership interests in PVG and PVR—We may sell some or all of our partner interests in PVG and PVR.” We may also consider additional equity or debt offerings in the future.

Our oil and gas business

We have a geographically diverse asset base with core areas of operation in the East Texas, Mid-Continent, Appalachian, Mississippi and Gulf Coast regions of the United States. As of December 31, 2008, we had proved natural gas and oil reserves of approximately 916 Bcfe, of which 82% were natural gas and 51% were proved developed, with an SEC pre-tax PV-10 value of $908.0 million and standardized measure of discounted future net cash flows of $729.4 million. See “—Summary reserve, production and operating data” for a reconciliation of PV-10 to standardized measure of discounted future net cash flows.

For the three months ended March 31, 2009 and the year ended December 31, 2008, we had average daily production of 152.3 MMcfe and 128.1 MMcfe. Our properties generally have long reserve lives and reasonably stable and predictable well production characteristics with a ratio of

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proved reserves to production (based on production for the year ended December 31, 2008) of approximately 19.5 years. At December 31, 2008, we owned 1.2 million net acres of leasehold interests, approximately 37% of which were undeveloped.

The following table sets forth by region the estimated quantities of proved reserves, production and reserves to production ratio (based on production for the year ended December 31, 2008):

	Proved reserves as of December 31, 2008				Average daily production
Region	Proved reserves (Bcfe)	% Total proved reserves	% Proved developed	Reserves to production ratio (in years)	Three months ended March 31, 2009 (MMcfe)	Year ended December 31, 2008 (MMcfe)
Appalachia	170	19%	74%	14.8	32.2	31.4
Mississippi	155	17%	71%	21.1	23.3	20.1
East Texas	419	46%	31%	31.2	40.8	36.6
Mid-Continent	141	15%	55%	18.5	31.7	20.9
Gulf Coast	31	3%	89%	4.5	24.3	19.1
Total	916	100%	51%	19.5	152.3	128.1

Our partner interests in PVG and PVR

We are indirectly involved in PVR’s coal and natural resource management and natural gas midstream businesses through our partner interests in PVR and PVG. We own the sole general partner of PVG and an approximate 77% limited partner interest in PVG, which in turn owns the sole 2% general partner interest and an approximate 37% limited partner interest in PVR. As part of its ownership of PVR’s general partner, PVG owns the rights, referred to as “incentive distribution rights,” to receive an increasing percentage of PVR’s quarterly distributions of available cash after certain levels of cash distributions have been achieved.

PVG consolidates PVR’s results into its financial statements because PVG controls PVR’s general partner. We consolidate PVG’s results into our financial statements because we control PVG’s general partner. PVG and PVR function with capital structures that are independent of each other and of us. While we report consolidated financial results of PVR’s coal and natural resource management and natural gas midstream businesses, the only cash we receive from those businesses is in the form of cash distributions we receive from PVG and PVR in respect of our partner interests in each of them. For the three months ended March 31, 2009 and the year ended December 31, 2008, these distributions were $11.6 million and $44.0 million.

PVR manages coal properties and enters into long-term leases with experienced, third-party mine operators. PVR provides them the right to mine its coal reserves in exchange for royalty payments, which generate stable and predictable cash flows and limit its exposure to declines in coal prices. PVR does not operate any mines, and as a result, does not directly have any operational risk or production costs. As of December 31, 2008, PVR owned or controlled approximately 827 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. 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.

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PVR also owns and operates natural gas midstream assets located in Oklahoma and Texas. These assets include approximately 4,069 miles of natural gas gathering pipelines and five natural gas processing facilities having 300 MMcfd of total capacity. In the three months ended March 31, 2009 and the year ended December 31, 2008, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 32.3 Bcf and 98.7 Bcf. PVR’s 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.

Summary corporate structure

The following chart depicts our simplified organizational structure:

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Business strengths

Geographically diverse, primarily lower-risk and longer-lived reserve base.    We have successfully grown and diversified our asset base through entry into five key oil and gas regions, which we believe helps reduce our dependence on any single area, thereby reducing operational, production and reserve growth risk. At December 31, 2008, 97% of our proved reserves were located in primarily longer-lived lower-risk basins in Appalachia, Mississippi, East Texas and the Mid-Continent. Wells in these regions are generally characterized by predictable production profiles. Furthermore, our proved reserves generally have long production lives with a ratio of proved reserves to production of approximately 19.5 years based on average daily production of 128.1 MMcfe in the year ended December 31, 2008.

Consistent track record of efficient proved reserve and production growth.    For the three years ended December 31, 2008, we were able to replace 572% of our production at a cost of $2.21 per Mcfe. For the three years ended December 31, 2008, we increased our proved reserves and production at annualized compounded growth rates of 35% and 20%. We have achieved these results from a combination of organic growth through drilling and selective asset acquisitions that have enhanced our competitive position. In the three years ended December 31, 2008, we drilled 785 gross (544.4 net) wells, of which 94% were successful in producing natural gas in commercial quantities.

Conservative financial profile.    We have historically operated with relatively conservative levels of leverage and have also maintained relatively strong interest coverage ratios by industry standards for companies of our size. At March 31, 2009, after giving effect to the issuance and sale of shares of our common stock on May 22, 2009 and the application of the net proceeds therefrom to repay a portion of the borrowings outstanding under our Revolver, the ratio of the Restricted Group’s debt to proved developed reserves would have been $1.12 per Mcfe, and the Restricted Group’s debt to Adjusted EBITDAX would have been 1.5x for the twelve months ended March 31, 2009.

Additional cash flow from PVG and PVR.    Our partner interests in PVG and PVR have historically provided us with growing quarterly cash distributions. Based on PVG’s and PVR’s current annualized distribution rates of $1.52 and $1.88 per unit, we would receive aggregate annualized distributions of $46.3 million in respect of our partner interests in the year ended December 31, 2009. PVR expects to grow its coal reserves and expand its midstream operations through accretive acquisitions and development projects. We believe that PVR’s growth strategy, if successfully implemented, will provide us with a growing source of cash flow from our partner interests in PVG and PVR.

Advantages of our relationship with PVR.    During 2006, PVR began marketing our natural gas production in Louisiana, Oklahoma and Texas, allowing PVR to add a new source of revenues. In 2008, PVR constructed the Crossroads plant, an 80 MMcfd gas processing plant in the Bethany Field in East Texas, and entered into a gas gathering and processing agreement with us. The Crossroads plant provides fee-based gas processing services to our oil and gas business in the East Texas region, as well as other producers.

Experienced management and technical teams.    Our key executives have an average of over 25 years of industry experience. Our executive management team is supported by technical and operating managers who also have substantial industry experience and expertise within the basins in which we operate.

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Business strategy

Growth primarily through development drilling.    We anticipate spending approximately $130.0 million to $140.0 million on oil and gas capital expenditures in 2009. We currently plan to allocate up to approximately 96% of capital expenditures in 2009 to development drilling and related projects in our core areas of East Texas, the Mid-Continent, Appalachia and Mississippi. We are applying horizontal drilling technology in each of these core areas which may result in increased reserve additions, higher production rates and increased rates of return. Capital spending levels in each of our core areas is expected to be significantly lower in 2009 than 2008.

Exploratory drilling provides operational balance and future development growth opportunities.    We intend to apply up to approximately 4% of capital expenditures in 2009 to our exploratory activities, including potentially higher-risk, higher-reward exploratory prospects in the Marcellus Shale in Pennsylvania. Capital for other exploratory prospects in the Mid-Continent, Appalachian and Gulf Coast regions has been deferred until commodity prices increase and access to the capital markets allows for increased equity or debt financing.

Pursue selective acquisition opportunities in existing basins.    Historically, we have pursued acquisitions of properties that we believe have development potential and that are consistent with our lower-risk drilling strategies. Our experienced team of management and technical professionals looks for new opportunities to increase reserves and production that complement our existing core properties. As a result of the current deterioration in the global economy, including financial and credit markets, minimal capital expenditures are anticipated as part of near-term oil and gas capital expenditures. In 2008, we made approximately $95.5 million of leasehold and other oil and gas acquisitions.

Manage risk exposure through an active hedging program.    We actively manage our exposure to commodity price fluctuations by hedging the commodity price risk for our expected proved developed production through the use of derivatives, typically three-way collar contracts. The level of our hedging activity and the duration of the instruments employed depend upon our cash flow at risk, available hedge prices and our operating strategy. As of May 31, 2009, we had hedged approximately 73%, 56% and 12% of our 2009, 2010 and 2011 proved developed production. See “Management’s discussion and analysis of financial condition and results of operations—Quantitative and qualitative disclosures about market risk—Price risk—Oil and gas segment” for a discussion of our hedging program.

Corporate information

We were founded in 1882 and are a Virginia corporation. Our corporate headquarters and principal executive offices are located at Three Radnor Corporate Center, Suite 300, 100 Matsonford Road, Radnor, Pennsylvania 19087, and our telephone number is (610) 687-8900. We maintain a website at http://www.pennvirginia.com. The information on our website is not part of this prospectus supplement, and you should rely only on the information contained in this prospectus supplement, the accompanying prospectus and the documents we incorporate by reference herein when making a decision as to whether to invest in the notes.

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The offering

The summary below describes the principal terms of the notes. Certain of the terms and conditions described below are subject to important limitations and exceptions. The “Description of notes” section of this prospectus supplement contains a more detailed description of the terms and conditions of the notes. For purposes of the description of notes included in this prospectus supplement, references to the “Company,” “issuer,” “us,” “we” and “our” refer only to Penn Virginia Corporation and do not include our subsidiaries.

Issuer Penn Virginia Corporation.

Securities $250,000,000 aggregate principal amount of     % Senior Notes due 2016.

Maturity                     , 2016.

Interest payment dates Interest is payable on the notes on              and              of each year, beginning on             , 2009.

Optional redemption We may, at our option, redeem all or part of the notes at any time prior to             , 2013, at a make-whole price, and on or after             , 2013, at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption, as described under “Description of notes—Optional redemption.” In addition, prior to             , 2012, we may, at our option, redeem up to 35% of the notes with the proceeds of certain equity offerings.

Ranking The notes will be our general unsecured, senior obligations. Accordingly, they will rank:

• senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the notes, including our $230.0 million aggregate principal amount of 4.50% Convertible Senior Subordinated Notes due 2012, or the Convertible Notes;

• equal in right of payment with any of our existing and future unsecured indebtedness that is not by its terms subordinated to the notes;

• effectively junior to our existing and future secured indebtedness, including indebtedness under our Revolver, to the extent of our assets constituting collateral securing that indebtedness; and

• structurally subordinated to all existing and future indebtedness and other liabilities (other than indebtedness and liabilities owed to us) of our non-guarantor subsidiaries, including PVG and PVR.

As of March 31, 2009, after giving effect to the sale on May 22, 2009 of shares of our common stock and the application of the net proceeds therefrom to pay down a portion of the borrowings

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outstanding under our Revolver, the Restricted Group would have had total indebtedness of $526.6 million, consisting of $325.1 million outstanding under our Revolver and $201.5 million of Convertible Notes. As of March 31, 2009, after giving effect to the issuance and sale of the shares of common stock and the application of the net proceeds therefrom and the issuance and sale of the notes and the application of the estimated net proceeds therefrom as set forth under “Use of proceeds” to pay down a portion of the borrowings outstanding under our Revolver, the Restricted Group would have had total indebtedness of $             million, consisting of $             million outstanding under our Revolver and $201.5 million of Convertible Notes.

Subsidiary guarantees The notes initially will be jointly and severally guaranteed on a senior unsecured basis by certain of our existing oil and gas subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. Each subsidiary guarantee will be a general unsecured obligation of the subsidiary guarantor and will rank:

• senior in right of payment to all existing and future subordinated indebtedness of that subsidiary guarantor;

• equal in right of payment to all existing and future senior unsecured indebtedness of that subsidiary guarantor;

• effectively junior to that subsidiary guarantor’s existing and future secured indebtedness, including its guarantee of indebtedness under our Revolver, to the extent of the value of the assets of such subsidiary guarantor constituting collateral securing that indebtedness; and

• structurally junior to the indebtedness and other liabilities of our non-guarantor subsidiaries, including PVG and PVR.

Not all of our subsidiaries will guarantee the notes. PVG, PVR and their respective subsidiaries and certain other of our subsidiaries will not guarantee the notes. As of March 31, 2009, our non-guarantor subsidiaries had indebtedness and other liabilities of $700.9 million, which indebtedness and other liabilities would rank structurally senior to the notes and related guarantees.

Covenants The indenture governing the notes will contain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:

• incur additional debt;

• make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock;

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• sell assets, including capital stock of our restricted subsidiaries;

• restrict dividends or other payments by restricted subsidiaries;

• create liens that secure debt;

• enter into transactions with affiliates; and

• merge or consolidate with another company.

These covenants are subject to a number of important limitations and exceptions that are described later in this prospectus supplement under the caption “Description of notes—Certain covenants.” In addition, certain of the covenants listed above will terminate before the notes mature if both of the specified rating agencies assign the notes an investment grade rating in the future and no events of default exist under the indenture. Any covenants that cease to apply to us as a result of achieving investment grade ratings will not be restored, even if the credit ratings assigned to the notes later fall below investment grade.

Change of control offer If we experience certain kinds of changes of control, we must give holders of the notes the opportunity to sell us their notes at 101% of their principal amount, plus accrued and unpaid interest. However, in such an event, we might not be able to pay you the required repurchase price for the notes you present to us because we might not have sufficient funds available at that time, or the terms of our Revolver may prevent us from applying funds to repurchase the notes.

No Public Market The notes are a series of securities for which there is currently no established trading market. The underwriters have advised us that they presently intend to make a market in the notes. However, you should be aware that they are not obligated to make a market and may discontinue their market-making activities at any time without notice. As a result, a liquid market for the notes may not be available if you try to sell your notes. We do not intend to apply for a listing of the notes on any securities exchange or any automated dealer quotation system.

Use of proceeds We intend to use the net proceeds from this offering to reduce indebtedness under our Revolver. See “Use of proceeds.” Affiliates of certain of the underwriters are currently lenders under our Revolver and, accordingly, they will receive a portion of the proceeds from the sale of the notes in this offering. Please see “Underwriting.”

Original issue discount The notes may be issued with original issue discount for U.S. federal income tax purposes, referred to as OID, and U.S. holders will be required to include OID in gross income for U.S. federal tax purposes

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in advance of the receipt of cash attributable to that income, regardless of the holders’ method of accounting for U.S. federal income tax purposes. See “Certain United States federal income and estate tax considerations—Tax consequences to U.S. holders—Stated interest and OID on the notes.”

Form The notes will be represented by registered global securities registered in the name of Cede & Co., the nominee of the depositary, The Depository Trust Company, or DTC. Beneficial interests in the notes will be shown on, and transfers will be effected through, records maintained by DTC and its participants.

Risk factors See “Risk factors” beginning on page S-18 of this prospectus supplement for important information regarding us and an investment in the notes.

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Summary historical financial data

The following tables show our summary historical financial data as of and for the periods indicated and summary historical financial data of the Restricted Group as of and for the periods indicated. Our and the Restricted Group’s summary income statements, statements of cash flows and balance sheets historical financial data as of and for the years ended December 31, 2008, 2007 and 2006 have been derived from our audited consolidated financial statements and the notes thereto. Our and the Restricted Group’s summary historical financial data as of and for the three months ended March 31, 2009 and 2008 are derived from our unaudited consolidated financial statements and the notes thereto and, in our opinion, except as described below, have been prepared on a basis consistent with the audited financial statements and include all adjustments consisting of normal recurring adjustments, necessary for a fair presentation of this information. Certain historical amounts have been reclassified to conform to the current presentation.

Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. Because PVG controls the general partner of PVR, the financial results of PVG include those of PVR. However, PVG and PVR function with capital structures that are independent of each other and us, with each having publicly traded common units and PVR having its own debt instruments. Furthermore, PVG and PVR are not part of the Restricted Group, and therefore, the only cash flows from PVG and PVR that are available to us to help service our debt, including the notes, are the distributions we receive in respect of our partner interests in PVG and PVR. Certain financial data for the Restricted Group are set forth in a separate table below our consolidated summary financial data. See also note 24 in the notes to our audited consolidated financial statements and note 13 in the notes to our unaudited consolidated financial statements included elsewhere in this prospectus supplement for a discussion of guarantor subsidiaries.

Effective January 1, 2009, we adopted (i) Financial Accounting Standards Board, or FASB, 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) and (ii) Statement of Financial Accounting Standards, or SFAS, No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (SFAS 160). FSP APB 14-1 required us to separately account for the liability and equity components of the Convertible Notes in a manner that reflects our nonconvertible borrowing debt borrowing rate when measuring interest cost of the Convertible Notes. Because the liability component was valued exclusive of the conversion feature, the Convertible Notes were recorded at a discount, which will be recognized as additional interest expense over the term of the Convertible Notes. SFAS 160 requires minority interest in PVG and PVR to be reclassed to noncontrolling interest within shareholders’ equity. Additionally, SFAS 160 requires allocation of net income between our shareholders and the noncontrolling interest in PVR and PVG on the consolidated statements of income.

Both of these accounting standards are to be applied retrospectively. Throughout this prospectus supplement, the adoption of these standards has been reflected in the balance sheet and shareholders’ equity as of March 31, 2009 and in the consolidated statements of income and cash flows for the three months ended March 31, 2009 and 2008 only. Other balance sheets, consolidated statements of income, shareholders’ equity, cash flows and related financial data as of and for each of the years in the three-year period ended December 31, 2008, or as of or for

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any other period referenced in this prospectus supplement, have not been adjusted to reflect the adoptions of FSP APB 14-1 or SFAS 160. The retroactive application of these standards would have decreased net income by approximately $3.1 million and $0.3 million for the years ended December 31, 2008 and 2007, with no impact on net income in 2006.

We derived the data in the following tables from, and the following tables should be read together with and are qualified in their entirety by reference to, our historical financial statements and the accompanying notes included elsewhere in this prospectus supplement. The tables should also be read together with “Management’s discussion and analysis of financial condition and results of operations.”

Consolidated financial data

($ in thousands)	Twelve months ended March 31, 2009			Three months ended March 31,						Year ended December 31,
				2009			2008			2008			2007			2006
Income statement data:
Revenues:
Natural gas	$	341,109		$	52,821		$	80,513		$	368,801		$	262,169		$	212,919
Crude oil		43,642			6,328			9,215			46,529			22,439			17,634
Natural gas liquids		22,794			3,370			1,868			21,292			5,678			3,603
Natural gas midstream		559,941			95,206			125,048			589,783			433,174			402,715
Coal royalties		129,502			30,630			23,962			122,834			94,140			98,163
Gain on sales of property and equipment		31,426			—			—			31,426			12,416			—
Other		42,462			10,805			8,529			40,186			22,934			18,895
Total revenues	$	1,170,876		$	199,160		$	249,135		$	1,220,851		$	852,950		$	753,929
Expenses:
Cost of midstream gas purchased	$	464,322		$	79,398		$	99,697		$	484,621		$	343,293		$	334,594
Operating		91,591			22,702			21,002			89,891			67,610			47,406
Exploration		59,068			21,312			4,680			42,436			28,608			34,330
Taxes other than income		27,623			6,432			7,395			28,586			21,723			14,767
General and administrative		75,321			18,486			17,659			74,494			66,983			49,566
Impairments		52,960			1,196			—			51,764			2,586			8,517
Depreciation, depletion and amortization		210,740			57,073			38,569			192,236			129,523			94,217
Total expenses	$	981,625		$	206,599		$	189,002		$	964,028		$	660,326		$	583,397
Operating income	$	189,251		$	(7,439)		$	60,133		$	256,823		$	192,624		$	170,532
Other income (expense):
Interest expense		(51,054	)		(12,502	)		(10,747	)		(44,261	)		(37,419	)		(24,832	)
Other		(1,424	)		1,573			2,331			(666	)		3,651			3,718
Derivatives		82,738			10,255			(25,901	)		46,582			(47,282	)		19,497
Income (loss) before minority interest, noncontrolling interest and income taxes		219,511			(8,113	)		25,816			258,478			111,574			168,915
Minority interest(1)											60,436			30,319			43,018
Income tax benefit (expense)		(64,763	)		4,562			(2,594	)		(73,874	)		(30,501	)		(49,988	)
Net income (loss)(1)		154,748			(3,551	)		23,222		$	124,168		$	50,754		$	75,909
Noncontrolling interests(1)		(44,066	)		(3,658	)		(20,028	)
Net income (loss) attributable to Penn Virginia Corporation(1)	$	110,682		$	(7,209	)	$	3,194

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($ in thousands)	Twelve months ended March 31, 2009			Three months ended March 31,						Year ended December 31,
				2009			2008			2008			2007			2006
Balance sheet data (at period end):
Cash and cash equivalents	$	29,721		$	29,721		$	32,880		$	18,338		$	34,527		$	20,338
Net property and equipment		2,542,804			2,542,804			1,972,486			2,511,175			1,899,014			1,358,383
Total assets		3,000,498			3,000,498			2,352,479			2,996,552			2,253,461			1,633,149
Total long-term debt, including current maturities		1,186,645			1,186,645			819,748			1,137,642			763,714			439,046
Minority interest of subsidiaries(1)								187,153			299,671			179,162			438,372
Shareholders’ equity(1)		1,314,988			1,314,988			811,441			1,018,790			810,098			382,425
Cash flows data:
Net cash flows provided by (used in):
Operating activities	$	420,641		$	103,019		$	66,152		$	383,774		$	313,030		$	275,819
Investing activities		(871,609	)		(139,039	)		(112,997	)		(845,567	)		(683,483	)		(462,335	)
Financing activities		447,802			47,396			45,198			445,604			384,642			180,941
Ratio of earnings to fixed charges(2)		4.5x			0.3x			3.1x			5.7x			3.3x			6.3x

(1) If adjusted for the adoption of SFAS 160, minority interest on the consolidated statement of income for the years ended December 31, 2008, 2007 and 2006 would not exist, and the amounts for each year would be considered noncontrolling interests. Minority interest on the balance sheets for the comparable periods would be considered noncontrolling interest, which is a component of shareholders’ equity.

(2) This data is unaudited for all periods presented. For purposes of computing our ratio of earnings to fixed charges on a consolidated basis, (x) earnings consist of the aggregate of income (before adjustment for income taxes, extraordinary items, income or loss from equity investees and minority interest), plus fixed charges, amortization of capitalized interest and distributed income of equity investees, and minus capitalized interest, and (y) fixed charges consist of interest expense (including amounts capitalized), amortization of debt issuance costs and the portion of rental expense representing the interest factor.

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Restricted Group financial data

	Twelve months ended March 31, 2009		Three months ended March 31,					Year ended December 31,
($ in thousands)			2009			2008		2008		2007		2006
Income statement and cash flow data:
Total revenues	$	441,597	$	64,564		$	92,300	$	469,333	$	334,216	$	235,948
Interest expense		25,677		6,886			5,815		19,568		20,082		6,011
Net income		109,129		(7,516	)		2,822		122,550		81,528		75,909
Additions to property and equipment		634,056		120,980			95,732		608,808		519,470		335,227
Balance sheet data (at period end):
Cash and cash equivalents	$	7,977	$	7,977		$	13,919	$	—	$	4,035
Total debt		591,545		591,545			406,000		569,542		352,000
Equity		1,058,776		1,058,776			841,841		1,047,947		840,871
Total debt and equity		1,650,321		1,650,321			1,247,841		1,617,489		1,192,871
Other financial data and key credit statistics:
EBITDAX(1)	$	301,433	$	53,400		$	64,148	$	308,305	$	201,765	$	179,957
PVG/PVR distribution to Penn Virginia		45,142		11,556			10,432		44,018		29,840		28,543
Adjusted EBITDAX(1)		346,575		64,956			74,580		352,323		231,605		208,500
Total interest(2)		27,265		7,250			6,629		21,606		23,767		8,828
Ratio of total debt to Adjusted EBITDAX		1.7x							1.6x		1.5x
Ratio of Adjusted EBITDAX to total interest(2)		12.7x		9.0x			11.3x		16.3x		9.7x		23.6x

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(1) EBITDAX represents net income of the Restricted Group, after deducting equity in earnings of our non-guarantor subsidiaries, before income tax expense, interest expense, depreciation, depletion and amortization, impairment of oil and gas properties, non-cash derivative loss (gain), loss (gain) on sale of properties, loss on assets held for sale, non-cash compensation expense and exploration expenses of the Restricted Group. Adjusted EBITDAX represents EBITDAX of the Restricted Group, plus cash distributions we received in respect of our partner interests in PVG and PVR. EBITDAX and Adjusted EBITDAX of the Restricted Group are not measures calculated in accordance with GAAP. EBITDAX and Adjusted EBITDAX of the Restricted Group should not be considered as alternatives to net income, income before taxes, net cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. We believe that EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt and to fund capital expenditures. Because EBITDAX is commonly used in the oil and gas industry, we believe it is useful in evaluating our ability to meet our interest obligations in connection with this offering. EBITDAX and Adjusted EBITDAX calculations may vary among entities, so our computation of EBITDAX and Adjusted EBITDAX may not be comparable to EBITDAX and Adjusted EBITDAX, or similar measures, of other entities. In evaluating EBITDAX and Adjusted EBITDAX, we believe that investors should consider, among other things, the amount by which EBITDAX and Adjusted EBITDAX exceed interest costs, how EBITDAX and Adjusted EBITDAX compare to principal payments on debt and how EBITDAX and Adjusted EBITDAX compare to capital expenditures for each period. The following table provides a reconciliation of net income of the Restricted Group to EBITDAX and to Adjusted EBITDAX of the Restricted Group:

($ in thousands)	Twelve months ended March 31, 2009			Three months ended March 31,						Year ended December 31,
				2009			2008			2008			2007			2006
Net income	$	109,129		$	(7,516)		$	2,822		$	122,550		$	81,528		$	75,909
Less: Equity in earnings of subsidiaries (non guarantors)		(23,276	)		(3,658	)		(8,641	)		(28,259	)		(27,942	)		(19,248	)
Add:
Interest expense		25,677			6,886			5,815			19,568			20,082			6,011
Income tax expense (benefit)		57,147			(7,044	)		(3,168	)		59,102			32,350			36,119
Depreciation, depletion and amortization		149,099			40,870			27,435			135,664			88,208			56,695
EBITDA	$	317,776		$	29,538		$	24,263		$	308,625		$	194,226		$	155,486
Impairment of oil and gas properties		21,159			1,196			—			19,963			2,586			8,517
Non-cash derivative loss (gain)		(72,714	)		(1,103	)		34,246			(37,365	)		16,122			(20,259	)
Loss (gain) on sale of properties		(30,577	)		11			(46	)		(30,634	)		(43,210	)		242
Non-cash compensation expense		6,721			2,446			1,005			5,280			3,433			1,641
Adjusted EBITDA	$	242,365		$	32,088		$	59,468		$	265,869		$	173,157		$	145,627
Exploration expenses		59,068			21,312			4,680			42,436			28,608			34,330
EBITDAX	$	301,433		$	53,400		$	64,148		$	308,305		$	201,765		$	179,957
Distributions from PVG and PVR		45,142			11,556			10,432			44,018			29,840			28,543
Adjusted EBITDAX	$	346,575		$	64,956		$	74,580		$	352,323		$	231,605		$	208,500

(2) Total interest includes interest expense of the Restricted Group plus interest capitalized during the period.

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Summary reserve, production and operating data

Estimates of our oil and natural gas reserves and present values as of and for the years ended December 31, 2008, 2007 and 2006 are derived from reserve reports prepared by Wright & Company, Inc. Guidelines established by the Securities and Exchange Commission, or the SEC, regarding the present value of future net cash flows were utilized to prepare these estimates. Estimates of reserves and their value are inherently imprecise and are subject to constant revision and change, and they should not be construed as representing the actual quantities of future production or cash flows to be realized from oil and natural gas properties or the fair market value of such properties.

The following table sets forth summary data with respect to estimated proved reserves and future net cash flows on a historical basis as of and for the periods presented:

	As of December 31,
($ in thousands)	2008		2007		2006
Proved reserves:
Natural gas (Bcf)		754		588		457
Oil and condensate (MMbbl)		27.0		15.2		4.9
Total (Bcfe)		916		680		487
% gas		82%		87%		94%
% proved developed		51%		59%		71%
Ratio of proved reserves to production (years)(1)		19.5		16.8		15.6
PV-10(2)	$	907,965	$	1,216,144	$	787,435
Standardized measure of discounted future net cash flows	$	729,401	$	971,910	$	604,600
Average price used in calculation of standardized measure of discounted future net cash flow(3):
Gas ($/Mcf)	$	5.71	$	6.80	$	5.64
Oil ($/Bbl)	$	44.60	$	95.95	$	61.05

(1) Calculated by dividing year-end reserves by annual production rates. This methodology implies that reserves are produced ratably over the reserve life indicated. Actual production rates for new wells tend initially to increase to peak production and thereafter to decline at an initially accelerated rate before moderating to decrease much more gradually over the majority of the well’s productive life.

(2) PV-10 is the present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to financial hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Standardized measure is the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

PV-10 is considered a non-GAAP measure. We believe the presentation of the PV-10 value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account corporate income taxes. We believe investors and creditors utilize our PV-10 value as a basis for comparison of the relative size and value of our reserves to other companies. Neither PV-10 value nor standardized measure reflects the impact of financial hedging transactions. The following reconciles our PV-10 value to our standardized measure:

	Year ended December 31,
($ in thousands)	2008		2007		2006
PV-10 value	$	907,965	$	1,261,144	$	787,435
Income tax effect		178,564		289,234		182,835
Standardized measure	$	729,401	$	971,910	$	604,600

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(3) Natural gas and oil prices were based on sales prices per Mcf and Bbl in effect on the applicable date, with the representative price of natural gas adjusted for basis premium and British thermal unit, or BTU, content to arrive at the appropriate net price.

The following table sets forth production, average sales prices and production costs with respect to our oil and gas properties for the periods presented:

($ in thousands)	Twelve months ended March 31, 2009		Three months ended March 31,				Year ended December 31,
			2009		2008		2008			2007			2006
Production data:
Natural gas (MMcf)		43,547		11,802		9,748		41,493			37,802			28,968
Crude oil (MBbl)		582		171		95		506			325			288
NGL (MBbl)		505		147		34		392			136			94
Total production (MMcfe)		50,069		13,710		10,522		46,881			40,569			31,260
Average realized prices(1):
Natural gas ($/Mcf)
Natural gas revenues, as reported	$	7.83	$	4.48	$	8.26	$	8.89		$	6.94		$	7.35
Derivatives (gains) losses included in natural gas revenues		—		—		—		—			(0.01	)		(0.02	)
Natural gas revenues before impact of derivatives	$	7.83	$	4.48	$	8.26	$	8.89		$	6.93		$	7.33
Cash settlements on natural gas derivatives(2)		0.16		1.27		0.06		(0.18	)		0.39			0.37
Natural gas revenues, adjusted for derivatives	$	7.99	$	5.75	$	8.32	$	8.71		$	7.32		$	7.70
Crude oil ($/Bbl)
Crude oil revenues, as reported	$	74.99	$	37.01	$	97.00	$	91.95		$	69.04		$	61.23
Derivatives (gains) losses included in crude oil and condensate revenues		—		—		—		—			1.54			1.59
Crude oil revenues before impact of derivatives	$	74.99	$	37.01	$	97.00	$	91.95		$	70.58		$	62.82
Cash settlements on crude oil derivatives(2)		1.83		7.89		—		(0.55	)		(2.26	)		(0.77	)
Crude oil revenues, adjusted for derivatives	$	76.82	$	44.90	$	97.00	$	91.40		$	68.32		$	62.05
Expenses ($/Mcfe):
Lease operating	$	1.20	$	1.08	$	1.35	$	1.27		$	1.15		$	0.88
Taxes other than income		0.45		0.35		0.56		0.50			0.44			0.38
General and administrative		0.44		0.37		0.44		0.45			0.40			0.41
Production costs	$	2.08	$	1.80	$	2.34	$	2.22		$	1.99		$	1.67
Exploration		1.18		1.55		0.44		0.91			0.71			1.10
Depreciation, depletion and amortization		2.91		2.92		2.53		2.82			2.15			1.80
Impairment of oil and gas properties		0.42		0.09		—		0.43			0.06			0.27
Interest expense		0.54		0.56		0.59		0.44			0.53			0.24
Total expenses	$	7.13	$	6.93	$	5.91	$	6.81		$	5.45		$	5.07

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(1) In 2006, we discontinued hedge accounting prospectively for our remaining and future commodity derivatives. Consequently, we began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income. The derivatives (gains) losses included in natural gas revenues and crude oil revenues represent the reclassifications out of accumulated other comprehensive income related to the derivatives for which we discontinued hedge accounting in 2006. The average realized prices represent the effects of the derivatives for which we discontinued hedge accounting on our natural gas and crude oil revenues.

(2) Cash settlements on derivatives represent the realized portion of the commodity derivatives and are recorded on the derivatives line on our consolidated statements of income. Had we not elected to discontinue hedge accounting, the cash settlements would have been recognized in the natural gas and crude oil revenues lines on our consolidated statements of income.

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Risk factors

An investment in the notes is subject to a number of risks. You should carefully consider the following risks, as well as the section entitled “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2008 incorporated herein by reference, as well as the other documents incorporated herein by reference, in evaluating this investment. If any of the following risks actually occur, our business, financial condition or results of operations could suffer.

Risks relating to the offering

After completion of the offering, we will have a significant amount of indebtedness and we may incur additional indebtedness.

At March 31, 2009, assuming we had completed the May 2009 issuance and sale of shares of our common stock at March 31, 2009, we and the guarantors of the notes would have had an aggregate of approximately $526.6 million of debt outstanding and would have been able to incur an additional $124.6 million under our Revolver. Assuming we had completed this offering and the May 2009 issuance and sale of shares of our common stock at March 31, 2009, we and the guarantors of the notes would have had an aggregate of approximately $             million of debt (including the notes) outstanding and would have been able to incur an additional $             million under our Revolver (after giving effect to the automatic reduction in the borrowing base under the Revolver resulting from the issuance of the notes). We and our subsidiaries may incur additional indebtedness in the future. Subject to certain conditions, the terms of the indenture under which the notes will be issued and our other existing debt instruments do not prohibit us or our subsidiaries from incurring additional indebtedness. Accordingly, should our current debt levels increase, the risks related to the notes and our indebtedness generally that we and our subsidiaries now face could also increase.

Any increase in our level of indebtedness will have several important effects on our future operations, including, without limitation:

• we will have additional cash requirements in order to support the payment of interest on our outstanding indebtedness;

• increases in our outstanding indebtedness and leverage will increase our vulnerability to adverse changes in general economic and industry conditions, as well as to competitive pressure; and

• depending on the levels of our outstanding debt, our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes may be limited.

Our ability to service our indebtedness will depend on certain financial, business and other factors, many of which are beyond our control.

Our ability to make scheduled payments of principal and interest on our indebtedness or to refinance our debt obligations depends on our future financial condition and operating performance, which will be subject to general economic conditions and to certain financial,

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business and other factors affecting our consolidated operations, many of which are beyond our control. If we are unable to generate sufficient cash flow from operations in the future to service our debt, we may be forced, among other things:

• to seek additional financing in the debt or equity markets;

• to refinance or restructure all or a portion of its indebtedness, including the notes;

• to sell selected assets;

• to reduce or delay planned capital expenditures; or

• to reduce or delay planned operating expenditures.

Such measures might not be successful and might not enable us to service our debt. In addition, any such financing, refinancing or sale of assets might not be available on economically favorable terms.

The indenture governing the notes and our Revolver impose restrictions on our operations and activities, including on our ability to dispose of assets or operations to meet our debt service and other obligations. If we are unable to comply with any of these restrictions or covenants, the trustee or the banks, as appropriate, could cause our debt to become due and payable prior to maturity.

Our Revolver and other debt instruments have restrictive covenants that could limit our financial flexibility.

The indentures related to the notes and the Convertible Notes and our Revolver contain financial and other restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under our Revolver is subject to compliance with certain financial covenants, including leverage and interest coverage ratios. Our Revolver includes other restrictions that, among other things, limit our ability to incur indebtedness; grant liens; engage in mergers, consolidations and liquidations; make asset dispositions, restricted payments and investments; enter into transactions with affiliates; and amend, modify or prepay certain indebtedness. The indenture related to the notes will contain limitations on our ability to effect mergers and change of control events, as well as other limitations, including:

• limitations on the declaration and payment of dividends or other restricted payments;

• limitations on incurring additional indebtedness or issuing preferred stock;

• limitations on the creation or existence of certain liens;

• limitations on incurring restrictions on the ability of certain of our subsidiaries to pay dividends or other payments;

• limitations on transactions with affiliates; and

• limitations on the sale of assets.

See “Description of other indebtedness.” Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our debts. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.

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The notes are unsecured obligations and will be effectively subordinated to our secured indebtedness.

Our obligations under the notes will not be secured by any of our assets and are and will be effectively subordinated to any of our existing and future secured indebtedness to the extent of the collateral securing such secured indebtedness. Accordingly, in the event of our bankruptcy, liquidation or any similar proceeding, holders of the notes will be entitled to payment only after the holders of any of our secured indebtedness have been paid out of the proceeds of the collateral securing such secured indebtedness, together with the accrued and unpaid interest. Assuming we had completed the May 2009 issuance and sale of shares of our common stock at March 31, 2009, we and the guarantors of the notes would have had an aggregate of approximately $325.1 million of secured indebtedness outstanding, consisting of indebtedness under our Revolver. Assuming we had completed this offering and the May 2009 issuance and sale of shares of our common stock at March 31, 2009, we and the guarantors of the notes would have had an aggregate of approximately $             million of secured indebtedness outstanding, consisting of indebtedness under our Revolver. See “Description of other indebtedness.” The indenture under which the notes will be issued and our other existing debt instruments will permit us, subject to certain limits, to incur additional secured obligations, including up to $500 million of indebtedness under our Revolver (subject to availability under our Revolver), all of which would be secured.

The notes will be structurally subordinated to indebtedness of our non-guarantor subsidiaries, including PVG and PVR and their respective subsidiaries.

You will not have any claim as a creditor against any of our non-guarantor subsidiaries, and indebtedness and other liabilities, including trade payables, of those subsidiaries will be effectively senior to your claims against those subsidiaries. Our right to receive any assets of any of our non-guarantor subsidiaries upon their bankruptcy, liquidation or reorganization, and therefore the right of the holders of the notes to participate in those assets, will be effectively subordinated to the claims of those non-guarantor subsidiaries’ creditors, including trade creditors. In addition, even if we are a creditor of any of our non-guarantor subsidiaries, our rights as a creditor would be subordinate to any security interest in the assets of such non-guarantor subsidiary’s subsidiaries and any indebtedness of such non-guarantor subsidiary’s subsidiaries that is senior to that held by us. PVG and PVR, their respective subsidiaries and certain of our other subsidiaries are non-guarantor unrestricted subsidiaries. At March 31, 2009, our non-guarantor subsidiaries had $700.9 million of outstanding indebtedness and other liabilities. In addition, the indenture under which the notes will be issued will permit these subsidiaries to incur additional indebtedness without any limitation.

We may not have the ability to raise funds necessary to finance any change of control offer required by the indenture.

If a change of control occurs as described in the section “Description of notes—Change of control,” we would be required to offer to repurchase the notes at 101% of their principal amount together with all accrued and unpaid interest, if any, to the date of purchase. Our Revolver currently provides that certain change of control events will constitute a default and, in the event of such a default, the holders of such indebtedness could elect to declare all funds borrowed to be due and payable, together with accrued and unpaid interest. Any of our future debt agreements may contain similar restrictions and provisions. We might not be able to repurchase the notes upon a change of control because we may not have sufficient financial

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resources to repurchase the notes tendered by holders upon a change of control. Our failure to repurchase the notes upon a change of control would cause a default under the indenture governing the notes offered hereby.

An active trading market may not develop for the notes.

The notes will constitute a new issue of securities for which there is no active public trading market. We do not intend to apply for listing of the notes on a securities exchange. The liquidity of the trading market in the notes and the market prices quoted for the notes may be adversely affected by changes in the overall market for this type of securities and by changes in our financial performance or prospects or in the performance or prospects for companies in our industry generally. As a consequence, an active trading market may not develop for the notes, you may not be able to sell the notes, or, even if you can sell the notes, you may not be able to sell them at a price that would be acceptable to you.

Federal and state laws allow courts, under specific circumstances, to void guarantees and to require you to return payments received from guarantors.

Although you will be direct creditors of the guarantors by virtue of the guarantees, existing or future creditors of any guarantor could avoid or subordinate that guarantor’s guarantee under the fraudulent conveyance laws if they were successful in establishing that:

• the guarantee was incurred with fraudulent intent; or

• the guarantor did not receive fair consideration or reasonably equivalent value for issuing its guarantee and

- was insolvent at the time of the guarantee;

- was rendered insolvent by reason of the guarantee;

- was engaged in a business or transaction for which its assets constituted unreasonably small capital to carry on its business; or

- intended to incur, or believed that it would incur, debt beyond its ability to pay such debt as it matured.

The measures of insolvency for purposes of determining whether a fraudulent conveyance occurred vary depending upon the laws of the relevant jurisdiction and upon the valuation assumptions and methodology applied by the court. Generally, however, a company would be considered insolvent for purposes of the foregoing if:

• the sum of the company’s debts, including contingent, unliquidated and unmatured liabilities, is greater than all of such company’s property at a fair valuation, or

• if the present fair saleable value of the company’s assets is less than the amount that will be required to pay the probable liability on its existing debts as they become absolute and matured.

We cannot assure you as to what standard a court would apply in order to determine whether a guarantor was “insolvent” as of the date its guarantee was issued, and we cannot assure you that, regardless of the method of valuation, a court would not determine that any guarantors

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were insolvent on that date. The subsidiary guarantees could be subject to the claim that, since the guarantees were incurred for our benefit, and only indirectly for the benefit of the other guarantors, the obligations of the guarantors thereunder were incurred for less than reasonably equivalent value or fair consideration.

If the notes are issued with OID you generally will be required to accrue income before you receive cash attributable to OID on the notes. Additionally, in the event we enter into bankruptcy, you may not have a claim for all or a portion of any unamortized amount of the OID on the notes.

The notes may be issued with OID for U.S. federal income tax purposes. Accordingly, if you are a U.S. holder, you generally will be required to accrue such OID on a current basis before you receive cash attributable to that income and regardless of your method of accounting for U.S. federal income tax purposes. For further discussion of the computation and reporting of OID, see “Certain United Stated federal income and estate tax considerations—Tax consequences to U.S. holders—Stated interest and OID on the notes.”

Additionally, a bankruptcy court may not allow a claim for all or a portion of any unamortized amount of OID on the notes.

Risks relating to our oil and gas business

Prices for natural gas, NGLs and crude oil are volatile, and a substantial or extended decline in prices would hurt our profitability and financial condition.

Our revenues, operating results, cash flow, profitability, future rate of growth and the carrying value of our oil and gas properties depend heavily on prevailing market prices for natural gas, NGLs and crude oil. Historically, natural gas, NGL and crude oil prices have been volatile, and they are likely to continue to be volatile. Wide fluctuations in natural gas, NGL and crude oil prices may result from relatively minor changes in the supply of and demand for oil and gas, market demand and other factors that are beyond our control, including:

• domestic and foreign supplies of natural gas, NGLs and crude oil;

• political and economic conditions in natural gas, NGL or crude oil producing regions;

• overall domestic and foreign economic conditions;

• prices and availability of alternative fuels;

• the availability of transportation facilities;

• weather conditions; and

• domestic and foreign governmental regulation.

Some of our projections and estimates are based on assumptions as to the future prices of natural gas, NGLs and crude oil. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future will likely differ from our estimates. Any substantial or extended decline in the actual prices of natural gas, NGLs

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or crude oil would have a material adverse effect on our financial position and results of operations (including reduced cash flow and borrowing capacity and possible asset impairment), the quantities of natural gas, NGLs and crude oil reserves that we can economically produce, the quantity of estimated proved reserves that may be attributed to our properties and our ability to fund our capital program.

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

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

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

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

The borrowing base under our Revolver has been reduced and may be further reduced in the future if commodity prices decline.

In March 2009, our bank group completed a semi-annual re-determination of the borrowing base under our Revolver. As a result, the borrowing base was revised to $450.0 million, which is approximately 6% less than its previous level of $479.0 million. Under the terms of our Revolver, the issuance of the notes will automatically result in a reduction of the borrowing base of our Revolver to $382.0 million.

Our borrowing base is re-determined twice a year. If oil and natural gas commodity prices deteriorate, we anticipate that the revised borrowing base under our Revolver may be further reduced. As a result, we may be unable to obtain adequate funding under our Revolver. If

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funding is not available when needed, or is available only on unfavorable terms, it might adversely affect our development plan as currently anticipated and our ability to make new acquisitions, each of which could have a material adverse effect on our production, revenues and results of operations.

Our future performance depends on our ability to find or acquire additional oil and gas reserves that are economically recoverable.

Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in oil and gas production and lower revenues and cash flows from operations. We have historically succeeded in substantially replacing reserves primarily through exploration and development and, to a lesser extent, acquisitions. We have conducted such activities on our existing oil and gas properties as well as on newly acquired properties. We may not be able to continue to replace reserves from such activities at acceptable costs. The currently depressed oil and gas prices may further limit the types of reserves that can be developed at acceptable costs. Lower prices also decrease our cash flows and may cause us to reduce capital expenditures. The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investments to maintain or expand our oil and gas reserves if cash flows from operations are reduced and external sources of capital remain limited or unavailable due to the deterioration of the global economy, including financial and credit markets. In addition, exploration and development activities involve numerous risks that may result in dry holes, the failure to produce oil and gas in commercial quantities and the inability to fully produce discovered reserves.

We are continually identifying and evaluating acquisition opportunities. However, competition for producing oil and gas properties is intense and many of our competitors have financial and other resources substantially greater than those available to us. Depending on the longevity of the deterioration of the market, our ability to make acquisitions may be significantly adversely affected. In the event we are successful in completing an acquisition, we cannot ensure that such acquisition will consist of properties that contain economically recoverable reserves or that such acquisition will be profitably integrated into our operations.

We have reduced and may further reduce our planned oil and gas segment capital expenditures in 2009, resulting in lower production growth in 2009.

We make, and will continue to make, substantial capital expenditures to find, acquire, develop, exploit and produce oil and natural gas reserves. However, in light of the recent fluctuations in oil and natural gas commodity prices, we have reduced our anticipated oil and gas segment capital expenditures in 2009, excluding acquisitions, to approximately $130.0 to $140.0 million, excluding drilling standby charges, which is a reduction from the previous guidance range of $210.0 to $220.0 million. This revised guidance is between $501.7 and $511.7 million, or between 78.2% and 79.7%, lower than the $641.7 million of capital expenditures, excluding acquisitions, that our oil and gas segment made in 2008. As a result of our decreased anticipated capital expenditures, we expect a decrease in the number of wells that will be drilled in 2009 and a reduction in our production from new wells. This could result in additional exploration expenses attributable to drilling rig standby charges of up to approximately $14.8 million for 2009. We may further reduce our anticipated 2009 oil and gas segment capital expenditures, resulting in even lower production growth in 2009. We will continue to evaluate economic conditions through the remainder of 2009 to determine whether or not to defer additional drilling.

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Exploration and development drilling may not result in commercially productive reserves.

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive natural gas or oil reserves will be found. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

• unexpected drilling conditions;

• pressure or irregularities in formations;

• equipment failures or accidents;

• shortages or delays in the availability of drilling rigs and the delivery of equipment;

• shortages in experienced labor;

• failure to secure necessary regulatory approvals and permits;

• fires, explosions, blow-outs and surface cratering; and

• adverse weather conditions.

The prevailing prices of oil and gas also affect the cost of and the demand for drilling rigs, production equipment and related services. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region.

Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays which jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore on or develop our properties.

The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that natural gas or oil is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Drilling activities can result in dry wells or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling costs.

Our future drilling activities may not be successful, nor can we be sure that our overall drilling success rate or our drilling success rate within a particular area will not decline. Unsuccessful drilling activities could have a material adverse effect on our business, results of operations or financial condition. Also, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we may not be able to economically produce oil or natural gas from all of them.

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We are exposed to the credit risk of our customers, and nonpayment or nonperformance by our customers would reduce our cash flows.

We are subject to risk from loss resulting from our customers’ nonperformance or nonpayment. We depend on a limited number of customers for a significant portion of revenues from our oil and gas segment. In the year ended December 31, 2008, 30% of our oil and gas segment revenues and 11% of our total consolidated revenues resulted from two of our oil and gas customers. Any nonpayment or nonperformance by our oil and gas customers would reduce our cash flows.

Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate.

Our operations are subject to all of the risks and hazards typically associated with the exploitation, development and exploration for, and the production and transportation of oil and natural gas. These operating risks include:

• fires, explosions, blowouts, cratering and casing collapses;

• formations with abnormal pressures;

• pipeline ruptures or spills;

• uncontrollable flows of oil, natural gas or well fluids;

• environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases; and

• natural disasters.

Any of these risks could result in substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. In addition, under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.

In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse effect on our business, results of operations or financial condition.

Our business depends on transportation facilities owned by others.

We deliver substantially all of our oil and natural gas production through pipelines that we do not own. The marketability of our production depends upon the availability, proximity and capacity of these pipelines as well as gathering systems and processing facilities. The unavailability or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.

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Federal, state and local regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and market our oil and natural gas.

Estimates of oil and natural gas reserves are not precise.

This prospectus supplement contains estimates of our proved oil and gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent on many variables and, therefore, changes often occur as these variables evolve and commodity prices fluctuate.

Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by us. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

At December 31, 2008, approximately 49% of our estimated proved reserves were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is based on volumetric calculations and adjacent reserve performance data. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from proved developed non-producing reserves will not be realized until some time in the future. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our reserves and the costs associated with these reserves in accordance with industry standards, these estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated.

You should not assume that the present value of estimated future net cash flows (standardized measure) referred to herein is the current fair value of our estimated oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual current and future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. As a result, net present value estimates using actual prices and costs may be significantly less than the SEC estimate that is provided herein. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor for us.

Additional impairment writedowns in our oil and gas segment may be required in 2009 or future periods if oil and gas prices decline.

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 of our fields because it becomes uneconomic to produce all recoverable reserves on such fields, thus reducing proved property reserve estimates. Natural gas and oil prices

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declined in 2008 and trended lower in the first quarter of 2009 followed by moderate improvements of uncertain duration in the second quarter of 2009. Our operating income in the three months ended March 31, 2009 and in the years ended December 31, 2008, 2007 and 2006 included impairment charges of $1.2 million, $20.0 million, $2.5 million and $8.5 million related to our oil and gas properties. Additional write-downs in our oil and gas segment may be required in 2009 if oil and natural gas prices decline, unproved property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any. In addition, we continue to experience an increase in lease expirations and unproved leasehold expense caused by current economic conditions which have impacted our future drilling plans thereby increasing the amount of expected lease expirations. Effective January 1, 2009, we changed our accounting process to amortize additional insignificant unproved properties over the average estimated life of the leases versus amortizing some leases and assessing other leases on an occurrence basis. As a result of amortizing additional leases, we recorded additional unproved leasehold expense, which is included in exploration expense on the consolidated statements of income, of $6.3 million in the three months ended March 31, 2009.

We have limited control over the activities on properties we do not operate.

In the year ended December 31, 2008, other companies operated approximately 21% of our net production. Our success in properties operated by others will depend upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental standards. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund for their operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns or lead to unexpected future costs.

Certain working interest owners in our properties have the right to control the timing of drilling activities on our properties under certain circumstances.

Under certain circumstances, certain of the other working interest owners in our properties have the right to limit the amount of drilling activities that can take place on our properties at any given time. If these working interest owners chose to exercise this right, we could be required to scale back anticipated drilling activities on the affected properties. In such an event, production from the affected properties would be deferred, thereby decreasing production from the properties in the short-term.

Our producing property acquisitions carry significant risks.

Acquisition of producing oil and gas properties is a key element of maintaining and growing reserves and production. Competition for these assets has been and will continue to be intense. Depending on the longevity of the deterioration of the market, our ability to make acquisitions may be significantly adversely affected. In the event we do complete an acquisition, its success will depend on a number of factors, many of which are beyond our control. These factors include the purchase price, future oil and gas prices, the ability to reasonably estimate or assess the

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recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and development activities on the acquired properties and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.

Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results, and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.

Derivative transactions may limit our potential gains and involve other risks.

In order to manage our exposure to price risks in the sale of our oil and natural gas, we periodically enter into oil and gas price hedging arrangements with respect to a portion of our expected production. Our hedges are limited in duration, usually for periods of two years or less. While intended to reduce the effects of volatile oil and natural gas prices, such transactions may limit our potential gains if oil or natural gas prices were to rise over the price established by the hedging arrangements. In trying to maintain an appropriate balance, we may end up hedging too much or too little, depending upon how oil or natural gas prices fluctuate in the future.

In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

• our production is less than expected;

• there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

• the counterparties to our futures contracts fail to perform under the contracts; or

• a sudden, unexpected event materially impacts oil or natural gas prices.

In addition, derivative instruments involve basis risk. Basis risk in a derivative contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of production may have more or less variability than the regional price index used for the sale of that production.

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We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and gas are subject to extensive federal, state and local laws and regulations, including complex environmental laws. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations, inability to obtain necessary regulatory approvals or a failure to comply with existing legal requirements may harm our business, results of operations or financial condition. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. Laws and regulations protecting the environment have become more stringent in recent years, and may, in some circumstances, result in liability for environmental damage regardless of negligence or fault. In addition, pollution and similar environmental risks generally are not fully insurable. These liabilities and costs could have a material adverse effect on our business, financial condition or results of operations. See “Business—Government regulation and environmental matters—Oil and gas segment—Environmental matters.”

Risks related to our ownership interests in PVG and PVR

We are not the only partners of PVG and PVR, and PVG’s and PVR’s respective partnership agreements require them to distribute all available cash to their respective partners, including public unitholders.

PVG and PVR are publicly traded limited partnerships. We own PVG GP, LLC, the sole general partner of PVG. As of May 31, 2009, we also owned an approximate 77% limited partner interest in PVG. As of May 31, 2009, PVG owned an approximate 37% limited partner interest in PVR, as well as 100% of the general partner of PVR, which owns a 2% general partner interest and the incentive distribution rights. We directly owned an additional 0.1% limited partner interest in PVR as of May 31, 2009. The remainder of the outstanding limited partner interests in each of PVG and PVR are owned by public unitholders. Although PVG’s and PVR’s respective partnership agreements require them to distribute, on a quarterly basis, 100% of their available cash to their respective unitholders of record and their respective general partners, we are not the only limited partners of PVG and PVR and, therefore, we receive only our proportionate share of cash distributions from each of PVG and PVR based on our partner interests in each of them. The remainder of the quarterly cash distributions is distributed, pro rata, to the public unitholders.

For each of PVG and PVR, available cash is generally all cash on hand at the end of each quarter, after payment of fees and expenses and the establishment of cash reserves by their respective general partners. PVG’s and PVR’s general partners determine the amount and timing of cash distributions by PVG and PVR and have broad discretion to establish and make additions to the respective partnership’s reserves in amounts the general partner determines to be necessary or appropriate:

• to provide for the proper conduct of partnership business, and in the case of PVR, the businesses of its operating subsidiaries (including reserves for future capital expenditures and for anticipated future credit needs);

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• to provide funds for distributions to the respective unitholders and the respective general partner for any one or more of the next four calendar quarters; or

• to comply with applicable law or any loan or other agreements.

Accordingly, cash distributions we receive on our partner interests in PVG and PVR may be reduced at any time, or we may not receive any cash distributions from PVG or PVR, which would in turn reduce our cash available to service our debt, including the notes.

PVG’s ability to make distributions to us is entirely dependent upon PVG receiving distributions from PVR, and the amount of cash that PVR will be able to distribute to its unitholders, including PVG, principally depends upon the amount of cash it can generate from its coal and natural resource management and natural gas midstream businesses.

PVG’s earnings and cash flow consist exclusively of cash distributions from PVR. Consequently, a significant decline in PVR’s earnings or cash distributions would have a negative impact on its distributions to its partners, including us. The amount of cash that PVR will be able to distribute to its partners, including PVG, each quarter principally depends upon the amount of cash it can generate from its coal and natural resource management and natural gas midstream businesses. The amount of cash that PVR will generate will fluctuate from quarter to quarter based on, among other things:

• the amount of coal its lessees are able to produce;

• the price at which its lessees are able to sell the coal;

• its lessees’ timely receipt of payment from their customers;

• the amount of natural gas transported in its gathering systems;

• the amount of throughput in its processing plants;

• the price of and demand for natural gas;

• the price of and demand for NGLs;

• the relationship between natural gas and NGL prices;

• the fees it charges and the margins it realizes for its natural gas midstream services; and

• its hedging activities.

In addition, the actual amount of cash that PVR will have available for distribution will depend on other factors, some of which are beyond its control, including:

• the level of capital expenditures it makes;

• the cost of acquisitions, if any;

• its debt service requirements;

• fluctuations in its working capital needs;

• restrictions on distributions contained in its debt agreements;

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• prevailing economic conditions; and

• the amount of cash reserves established by its general partner in its sole discretion for the proper conduct of its business.

Because of these factors, PVR may not have sufficient available cash each quarter to continue paying distributions at their current level or at all. If PVR reduces its per unit distribution, PVG will have less cash available for distribution to its unitholders, including us, and would probably be required to reduce its per unit distribution to its unitholders, including us. The amount of cash that PVR has available for distribution depends primarily upon PVR’s cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, PVR may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records profits.

Since PVR’s inception as a publicly traded partnership, it has grown principally by making acquisitions in both of its business segments and, to a lesser extent, by organic growth on its properties. Readily available access to debt and equity capital and credit availability has been and continue to be critical factors in PVR’s ability to grow. The current deterioration in the global financial markets and the consequential adverse effect on credit availability is adversely impacting PVR’s access to new capital and credit availability. Depending on the longevity and ultimate severity of this deterioration, PVR’s ability to make acquisitions may be significantly adversely affected, as may PVR’s ability to make cash distributions to its unitholders and, in turn, would affect our ability to make cash distributions to our unitholders.

In addition, the timing and amount, if any, of an increase or decrease in distributions by PVR to its unitholders will not necessarily be comparable to the timing and amount of any changes in distributions made by PVG. PVG’s ability to distribute cash received from PVR to its unitholders, including us, is limited by a number of factors, including:

• PVG’s estimated general and administrative expenses, as well as other operating expenses;

• expenses of PVR’s general partner and PVR;

• reserves necessary for PVG to make the necessary capital contributions to maintain its 2% general partner interest in PVR, as required by PVR’s partnership agreement upon the issuance of additional limited partner securities by PVR;

• reserves PVG’s general partner believes prudent for PVG to maintain the proper conduct of its business or to provide for future distributions by PVG; and

• restrictions on distributions contained in any future debt agreements.

A reduction in PVR’s distributions will disproportionately affect the amount of cash distributions to which PVG is currently entitled, and, consequently, will affect the amount of cash distributions PVG is able to make to its unitholders, including us.

PVG’s ownership of the incentive distribution rights in PVR, through PVG’s ownership of PVR’s general partner, entitles PVG to receive its pro rata share of specified percentages of total cash distributions made by PVR with respect to any particular quarter only in the event that PVR distributes more than $0.275 per unit for such quarter. As a result, the holders of PVR’s common units have a priority over the holders of PVR’s incentive distribution rights to the extent of cash distributions by PVR up to and including $0.275 per unit for any quarter.

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PVG’s ownership of the incentive distribution rights of PVR entitles it to receive increasing percentages, up to 50%, of incremental cash distributions above $0.375 per unit distributed by PVR on a quarterly basis. Because PVG is at the maximum target cash distribution level on the incentive distribution rights, future growth in distributions PVG receives from PVR, and in distributions we receive from PVG, will not result from an increase in the target cash distribution level associated with the incentive distribution rights. Furthermore, a decrease in the amount of distributions by PVR to less than $0.375 per unit per quarter would reduce PVG’s percentage of the incremental cash distributions above $0.325 per common unit per quarter from 50% to 25%, consequently resulting in less cash available to PVG to distribute to its unitholders, including us. A decrease in the amount of distributions by PVR and, consequently, PVG may be caused by a variety of circumstances. PVR may generate less cash available for distributions or determine to create larger reserves in computing cash available for distribution. Even if cash available for distribution remained stable, PVG and PVR may determine to modify the incentive distribution rights to reduce the percentage of incremental cash distributions such incentive distribution rights are entitled to receive.

We may sell some or all of our partner interests in PVG and PVR.

Subject to certain terms and conditions contained in the indenture governing the notes, we may sell some or all of our partner interests in PVG and PVR without the consent of holders of the notes. The indenture would neither limit the consideration we receive nor would it require us to use the proceeds to repay indebtedness or make reinvestments. If we sold our partner interests in PVG and PVR, we would no longer receive distributions in respect of the sold interests, and our cash available to service our indebtedness, including the notes, may be adversely affected.

PVR may issue additional limited partner interests or other equity securities, which may increase the risk that PVR will not have sufficient available cash to maintain or increase its cash distribution level, which in turn may reduce the available cash that PVG has to distribute to its unitholders, including us.

PVR has wide latitude to issue additional limited partner interests on the terms and conditions established by its general partner. PVG receives cash distributions from PVR on the general partner interest, incentive distribution rights and the limited partner interest that PVG holds. Because a majority of the cash PVG receives from PVR is attributable to PVG’s indirect ownership of the incentive distribution rights, payment of distributions on additional PVR limited partner interests may increase the risk that PVR will be unable to maintain or increase its quarterly cash distribution per unit, which in turn may reduce the amount of incentive distributions PVG receives and the available cash that PVG has to distribute to its unitholders, including us.

Conflicts of interest may arise because the board of directors of the respective general partners of PVG and PVR has a fiduciary duty to manage the general partners in a manner that is beneficial to their owners, and at the same time, in a manner that is beneficial to the respective unitholders of PVG and PVR.

We own the sole general partner of PVG and PVG owns the sole general partner of PVR. PVG and PVR are publicly traded limited partnerships. Each of the board of directors of the general partners owes a fiduciary duty to the respective unitholders of PVG and PVR, and not just to us and PVG as owners of the general partners. As a result of these conflicts, the board of directors of the general partners of PVG and PVR may favor the interests of the public unitholders of PVG and PVR over the interests of the respective owners of the general partners.

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PVG and PVR are not restricted subsidiaries and, therefore, are not subject to the provisions of the indenture governing the notes.

PVG and PVR are not guarantors of the notes or restricted subsidiaries subject to the terms of the indenture governing the notes. PVR may, among other things, sell all or substantially all of its assets or modify the terms of the incentive distribution rights owned by PVG, in each case, without the consent of holders of the notes. In addition, PVG may, among other things, sell all or substantially all of its assets, including its partner interests and incentive distribution rights in PVR, without the consent of holders of the notes.

Our ability to sell our common units of PVG, and PVG’s ability to sell its partner interests in PVR, may be limited by securities law restrictions and liquidity constraints.

As of May 31, 2009, we owned 30,077,429 common units of PVG and PVG owned 19,587,049 common units of PVR, all of which are unregistered and restricted securities within the meaning of Rule 144 under the Securities Act of 1933, or the Securities Act. Unless we or PVG were to register these units, we or PVG are limited to selling into the market in any three-month period an amount of PVG common units or PVR common units that does not exceed the greater of 1% of the total number of common units outstanding or the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale. In addition, PVG faces contractual limitations on its ability to sell its general partner interest and incentive distribution rights in PVR and the market for such interests is illiquid.

Risks related to PVR’s coal and natural resource management business

If PVR’s lessees do not manage their operations well or experience financial difficulties, their production volumes and PVR’s coal royalties revenues could decrease.

PVR depends on its lessees to effectively manage their operations on its properties. PVR’s lessees make their own business decisions with respect to their operations, including decisions relating to:

• the method of mining;

• credit review of their customers;

• marketing of the coal mined;

• coal transportation arrangements;

• negotiations with unions;

• employee hiring and firing;

• employee wages, benefits and other compensation;

• permitting;

• surety bonding; and

• mine closure and reclamation.

If PVR’s lessees do not manage their operations well, or if they experience financial difficulties, their production could be reduced, which would result in lower coal royalties revenues to PVR and could have a material adverse effect on PVR’s business, results of operations or financial condition.

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The coal mining operations of PVR’s lessees are subject to numerous operational risks that could result in lower coal royalties revenues.

PVR’s coal royalties revenues are largely dependent on the level of production from its coal reserves achieved by its lessees. The level of PVR’s lessees’ production is subject to operating conditions or events that may increase PVR’s lessees’ cost of mining and delay or halt production at particular mines for varying lengths of time and that are beyond their or its control, including:

• the inability to acquire necessary permits;

• changes or variations in geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;

• changes in governmental regulation of the coal industry;

• mining and processing equipment failures and unexpected maintenance problems;

• adverse claims to title or existing defects of title;

• interruptions due to power outages;

• adverse weather and natural disasters, such as heavy rains and flooding;

• labor-related interruptions;

• employee injuries or fatalities; and

• fires and explosions.

Any interruptions to the production of coal from PVR’s reserves could reduce its coal royalties revenues and could have a material adverse effect on PVR’s business, results of operations or financial condition. In addition, PVR’s coal royalties revenues are based upon sales of coal by its lessees to their customers. If PVR’s lessees do not receive payments for delivered coal on a timely basis from their customers, their cash flow would be adversely affected, which could cause PVR’s cash flow to be adversely affected and could have a material adverse effect on PVR’s business, results of operations or financial condition.

A substantial or extended decline in coal prices could reduce PVR’s coal royalties revenues and the value of PVR’s coal reserves.

A substantial or extended decline in coal prices from recent levels could have a material adverse effect on PVR’s lessees’ operations (including mine closures) and on the quantities of coal that may be economically produced from its properties. In addition, because a majority of PVR’s coal royalties are derived from coal mined on PVR’s properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price, PVR’s coal royalties revenues could be reduced by such a decline. Such a decline could also reduce PVR’s coal services revenues and the value of its coal reserves. Additionally, volatility in coal prices could make it difficult to estimate with precision the value of PVR’s coal reserves and any coal reserves that PVR may consider for acquisition. The future impact of the current deterioration of the global economy, including financial and credit markets on coal production levels and prices is uncertain. Depending on the longevity and ultimate severity of the deterioration, demand for coal may decline, which could adversely effect production and pricing for coal mined by PVR’s lessees, and, consequently, adversely affect the royalty income received by PVR.

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PVR depends on a limited number of primary operators for a significant portion of its coal royalties revenues and the loss of or reduction in production from any of PVR’s major lessees would reduce its coal royalties revenues.

PVR depends on a limited number of primary operators for a significant portion of its coal royalties revenues. In the year ended December 31, 2008, five primary operators, each with multiple leases, accounted for 65% of PVR’s coal royalties revenues and 7% of our total consolidated revenues. If any of these operators enters bankruptcy or decides to cease operations or significantly reduces its production, PVR’s coal royalties revenues would be reduced.

A failure on the part of PVR’s lessees to make coal royalty payments could give PVR the right to terminate the lease, repossess the property or obtain liquidation damages and/or enforce payment obligations under the lease. If PVR repossessed any of its properties, PVR would seek to find a replacement lessee. PVR may not be able to find a replacement lessee and, if it finds a replacement lessee, PVR may not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If PVR enters into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced. In addition, it may be difficult for PVR to secure new or replacement lessees for small or isolated coal reserves, since industry trends toward consolidation favor larger-scale, higher technology mining operations to increase productivity rates.

PVR’s coal business will be adversely affected if PVR is unable to replace or increase its coal reserves through acquisitions.

Because PVR’s reserves decline as its lessees mine its coal, PVR’s future success and growth depends, in part, upon its ability to acquire additional coal reserves that are economically recoverable. The current deterioration in the global economy, including financial markets, and the consequential adverse effect on credit availability is adversely impacting PVR’s access to new capital and credit availability. Depending on the longevity and ultimate severity of this deterioration, PVR’s ability to make acquisitions may be significantly adversely affected. If PVR is unable to negotiate purchase contracts to replace or increase its coal reserves on acceptable terms, PVR’s coal royalties revenues will decline as its coal reserves are depleted and PVR could, therefore, experience a material adverse effect on its business, results of operations or financial condition. If PVR is able to acquire additional coal reserves, there is a possibility that any acquisition could be dilutive to earnings and reduce its ability to make distributions to unitholders, including us, or to pay interest on, or the principal of, its debt obligations. Any debt PVR incurs to finance an acquisition may similarly affect its ability to make distributions to unitholders, including us, or to pay interest on, or the principal of, its debt obligations. PVR’s ability to make acquisitions in the future also could be limited by restrictions under its existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

PVR’s lessees could satisfy obligations to their customers with coal from properties other than PVR’s, depriving PVR of the ability to receive amounts in excess of the minimum royalties payments.

PVR does not control its lessees’ business operations. PVR’s lessees’ customer supply contracts do not generally require its lessees to satisfy their obligations to their customers with coal mined from PVR’s reserves. Several factors may influence a lessee’s decision to supply its customers with coal mined

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from properties PVR does not own or lease, including the royalty rates under the lessee’s lease with PVR, mining conditions, transportation costs and availability and customer coal quality specifications. If a lessee satisfies its obligations to its customers with coal from properties PVR does not own or lease, production under its lease will decrease, and PVR will receive lower coal royalties revenues.

Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from PVR’s properties.

Transportation costs represent a significant portion of the total cost of coal for the customers of PVR’s lessees. Increases in transportation costs could make coal a less competitive source of energy or could make coal produced by some or all of PVR’s lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition for PVR’s lessees from coal producers in other parts of the country or increased imports from offshore producers.

PVR’s lessees depend upon rail, barge, trucking, overland conveyor and other systems to deliver coal to their customers. Disruption of these transportation services due to weather-related problems, strikes, lockouts, bottlenecks, mechanical failures and other events could temporarily impair the ability of PVR’s lessees to supply coal to their customers. PVR’s lessees’ transportation providers may face difficulties in the future and impair the ability of its lessees to supply coal to their customers, thereby resulting in decreased coal royalties revenues to PVR.

PVR’s lessees’ workforces could become increasingly unionized in the future, which could adversely affect their productivity and thereby reduce PVR’s coal royalties revenues.

One of PVR’s lessees has one mine operated by unionized employees. This mine was PVR’s third largest mine on the basis of coal production for the year ended December 31, 2008. All of PVR’s lessees could become increasingly unionized in the future. If some or all of PVR’s lessees’ non-unionized operations were to become unionized, it could adversely affect their productivity and increase the risk of work stoppages. In addition, PVR’s lessees’ operations may be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against its lessees’ operations. Any further unionization of PVR’s lessees’ employees could adversely affect the stability of production from its coal reserves and reduce its coal royalties revenues.

PVR’s coal reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of PVR’s coal reserves.

PVR’s estimates of its coal reserves may vary substantially from the actual amounts of coal its lessees may be able to economically recover. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond PVR’s control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate to:

• geological and mining conditions, which may not be fully identified by available exploration data;

• the amount of ultimately recoverable coal in the ground;

• the effects of regulation by governmental agencies; and

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• future coal prices, operating costs, capital expenditures, severance and excise taxes and development and reclamation costs.

Actual production, revenues and expenditures with respect to PVR’s coal reserves will likely vary from estimates, and these variations may be material. As a result, you should not place undue reliance on the coal reserve data provided by PVR.

Any change in fuel consumption patterns by electric power generators away from the use of coal could affect the ability of PVR’s lessees to sell the coal they produce and thereby reduce PVR’s coal royalties revenues.

According to the U.S. Department of Energy, domestic electric power generation accounted for approximately 90% of domestic coal consumption in 2008. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants such as nuclear, natural gas, fuel oil and hydroelectric power and environmental and other governmental regulations. PVR believes that most new power plants will be built to produce electricity during peak periods of demand. Many of these new power plants will likely be fired by natural gas because of lower construction costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. The increasingly stringent requirements of the Clean Air Act, or the CAA, may result in more electric power generators shifting from coal to natural gas-fired power plants. See “Business—Government regulation and environmental matters—PVR coal and natural resource management segment.”

Extensive environmental laws and regulations affecting electric power generators could have corresponding effects on the ability of PVR’s lessees to sell the coal they produce and thereby reduce PVR’s coal royalties revenues.

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants, which are the ultimate consumers of the coal PVR’s lessees produce. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. As a result of these current and proposed laws, regulations and trends, electricity generators may elect to switch to other fuels that generate less of these emissions, possibly further reducing demand for the coal that PVR’s lessees produce and thereby reducing its coal royalties revenues. See “Business—Government regulation and environmental matters—PVR coal and natural resource management segment.”

Concerns about the environmental impacts of fossil-fuel emissions, including perceived impacts on global climate change, are resulting in increased regulation of emissions of greenhouse gases in many jurisdictions and increased interest in and the likelihood of further regulation, which could significantly affect PVR’s coal royalties revenues.

Global climate change continues to attract considerable public and scientific attention. Several widely publicized scientific reports have engendered widespread concern about the impacts of human activity, especially fossil fuel combustion, on global climate change. Legislative attention in the United States is being paid to global climate change and to reducing greenhouse gas emissions, particularly from coal combustion by power plants. Such legislation was introduced in Congress in 2006, 2007 and 2008 to reduce greenhouse gas emissions in the United States and further proposals or amendments are likely to be offered in the future. Although the United

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States Supreme Court’s recent decision in Massachusetts v. Environmental Protection Agency related to new motor vehicles, the reasoning of the decision could affect regulation of carbon dioxide emissions under other federal regulatory programs, including those that regulate emissions from coal-fired power plants. Several states have also either passed legislation or announced initiatives focused on decreasing or stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures have focused on emissions from coal-fired power plants. See “Business—Government regulation and environmental matters—PVR coal and natural resource management segment.” Enactment of laws, passage of regulations regarding greenhouse gas emissions by the United States or some of its states, or other actions to limit carbon dioxide emissions could result in electric generators switching from coal to other fuel sources. This may adversely affect the use of and demand for fossil fuels, particularly coal.

Delays in PVR’s lessees obtaining mining permits and approvals, or the inability to obtain required permits and approvals, could have an adverse effect on PVR’s coal royalties revenues.

Mine operators, including PVR’s lessees, must obtain numerous permits and approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. The permitting rules are complex and can change over time. The public has the right to comment on many permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required by PVR’s lessees to conduct operations may not be issued, maintained or renewed, may not be issued or renewed in a timely fashion, or may involve requirements that restrict PVR’s lessees’ ability to economically conduct their mining operations. Limitations on PVR’s lessees’ ability to conduct their mining operations due to the inability to obtain or renew necessary permits, or due to uncertainty, litigation or delays associated with the eventual issuance of these permits, could have an adverse effect on its coal royalties revenues. See “Business—Government regulation and environmental matters—PVR coal and natural resource management segment—Mining permits and approvals.”

Uncertainty over the precise parameters of the CWA’s regulatory scope and a recent federal district court decision may adversely impact PVR’s coal lessees’ ability to secure the necessary permits for their valley fill surface mining activities.

To dispose of mining overburden generated from surface mining activities, PVR’s lessees often need to obtain government approvals, including Clean Water Act, or CWA, Section 404 permits to construct valley fills and sediment control ponds. Ongoing uncertainty over which waters are subject to the CWA may adversely impact PVR’s lessees’ ability to secure these necessary permits. In addition, a 2007 decision by a U.S. District Court in West Virginia invalidated a permit issued to one of PVR’s lessees for the Republic No. 2 Mine and enjoined PVR’s lessee, Alex Energy, Inc., from taking any further actions under this permit. This ruling was appealed and the appellate court reversed and vacated the district court’s order. It is unclear if this ruling will be appealed or if the permits will be challenged on other grounds. Uncertainty over the correct legal standard for issuing Section 404 permits may lead to rulings invalidating other permits, additional challenges to various permits and additional delays and costs in applying for and obtaining new permits that could ultimately have an adverse effect on PVR’s coal royalties revenues. See “Business—Government regulation and environmental matters—PVR coal and natural resource management segment—Clean Water Act” for more information about the litigation described above.

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PVR’s lessees’ mining operations are subject to extensive and costly laws and regulations, which could increase operating costs and limit its lessees’ ability to produce coal, which could have an adverse effect on PVR’s coal royalties revenues.

PVR’s lessees are subject to numerous and detailed federal, state and local laws and regulations affecting coal mining operations, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Numerous governmental permits and approvals are required for mining operations. PVR’s lessees are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be significant and time-consuming and may delay commencement or continuation of exploration or production operations. The possibility exists that new laws or regulations (or judicial interpretations of existing laws and regulations) may be adopted in the future that could materially affect PVR’s lessees’ mining operations, either through direct impacts such as new requirements impacting its lessees’ existing mining operations, or indirect impacts such as new laws and regulations that discourage or limit coal consumers’ use of coal. Any of these direct or indirect impacts could have an adverse effect on PVR’s coal royalties revenues. See “Business—Government regulation and environmental matters—PVR coal and natural resource management segment.”

Because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, PVR does not believe violations by its lessees can be eliminated completely. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens and, to a lesser extent, the issuance of injunctions to limit or cease operations. PVR’s lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their operations. If PVR’s lessees are required to pay these costs and liabilities and if their financial viability is affected by doing so, then their mining operations and, as a result, PVR’s coal royalties revenues and its ability to make distributions to us, could be adversely affected.

The PVR coal and natural resource management segment may record impairment losses on its long-lived assets.

The PVR coal and natural resource management segment has completed a number of acquisitions in recent years. See note 4 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a description of the PVR coal and natural resource management segment’s material acquisitions. In conjunction with our accounting for these acquisitions, it was necessary for us 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. Unforeseen changes in operations, the business environment or market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. This could result in impairment charges being recorded in our consolidated statements of income.

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Risks related to PVR’s natural gas midstream business

The success of PVR’s natural gas midstream business depends upon its ability to find and contract for new sources of natural gas supply.

In order to maintain or increase system throughput levels on PVR’s gathering systems and asset utilization rates at its processing plants, PVR must contract for new natural gas supplies. The primary factors affecting PVR’s ability to connect new supplies of natural gas to its gathering systems include the level of drilling activity creating new gas supply near its gathering systems, PVR’s success in contracting for existing natural gas supplies that are not committed to other systems and PVR’s ability to expand and increase the capacity of its systems. PVR may not be able to obtain additional contracts for natural gas supplies.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. PVR has no control over the level of drilling activity in its areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, PVR has no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital.

PVR’s natural gas midstream assets, including its gathering systems and processing plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. PVR’s cash flows associated with these systems will decline unless it is able to secure new supplies of natural gas by connecting additional production to these systems. A material decrease in natural gas production in PVR’s areas of operation, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas PVR handles, which would reduce its revenues and operating income. In addition, PVR’s future growth will depend, in part, upon whether it can contract for additional supplies at a greater rate than the rate of natural decline in PVR’s currently connected supplies.

PVR typically does not obtain independent evaluations of natural gas reserves dedicated to its gathering systems; therefore, volumes of natural gas on PVR’s systems in the future could be less than it anticipates.

PVR typically does not obtain independent evaluations of natural gas reserves connected to its gathering systems due to the unwillingness of producers to provide reserve information, as well as the cost of such evaluations. Accordingly, PVR does not have independent estimates of total reserves dedicated to its gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to PVR’s gathering systems is less than it anticipates and PVR’s is unable to secure additional sources of natural gas, then the volumes of natural gas gathered on PVR’s gathering systems in the future could be less than PVR anticipates. A decline in the volumes of natural gas on PVR’s systems could have a material adverse effect on PVR’s business, results of operations or financial condition.

A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect PVR’s business, results of operations and financial condition.

The NGL products PVR produces, including ethane, propane, normal butane, isobutane and natural gasoline, have a variety of applications, including as heating fuels, petrochemical

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feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general economic conditions, new government regulations, reduced demand by consumers for products made with NGL products, increased competition from petroleum-based products due to pricing differences, mild winter weather or other reasons, could result in a decline in the volume of NGL products PVR handles or reduce the fees PVR charges for its services. Any reduced demand for PVR’s NGL products could adversely affect demand for the services PVR provides as well as NGL prices, which would negatively impact PVR’s results of operations and financial condition.

The profitability of PVR’s natural gas midstream business is dependent upon prices and market demand for natural gas and NGLs, which are beyond PVR’s control and have been volatile.

PVR is subject to significant risks due to fluctuations in natural gas commodity prices. During 2008, PVR generated a majority of its gross margin from two types of contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs—gas purchase/keep-whole and percentage-of-proceeds arrangements. See “Business—Our contracts—PVR natural gas midstream segment.”

Virtually all of the system throughput volumes in PVR’s Crescent System and Hamlin System are processed under percentage-of-proceeds arrangements. The system throughput volumes in PVR’s Panhandle System are processed primarily under either percentage-of proceeds or gas purchase/keep-whole arrangements. Under both types of arrangements, PVR provides gathering and processing services for natural gas received. Under percentage-of-proceeds arrangements, PVR generally sells the NGLs produced from the processing operations and the remaining residue gas at market prices and remits to the producers an agreed upon percentage of the proceeds based on either an index price or the price actually received for gas and NGLs. Under these arrangements, revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have a material adverse effect on PVR’s business, results of operations or financial condition. Under gas purchase/keep-whole arrangements, PVR generally buys natural gas from producers based upon an index price and then sells the NGLs and the remaining residue gas to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the volume of natural gas available for sale, profitability is dependent on the value of those NGLs being higher than the value of the volume of gas reduction or “shrink.” Under these arrangements, revenues and gross margins decrease when the price of natural gas increases relative to the price of NGLs. Accordingly, a change in the relationship between the price of natural gas and the price of NGLs could have a material adverse effect on PVR’s business, results of operations or financial condition.

In the past, the prices of natural gas and NGLs have been extremely volatile, and PVR expects this volatility to continue. The markets and prices for residue gas and NGLs depend upon factors beyond PVR’s control. These factors include demand for oil, natural gas and NGLs, which fluctuates with changes in market and economic conditions, and other factors, including:

• the impact of the current deterioration in the global economy, including financial and credit markets, on worldwide demand for oil and domestic demand for natural gas and NGLs;

• the impact of weather on the demand for oil and natural gas;

• the level of domestic oil and natural gas production;

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• the availability of imported oil and natural gas;

• actions taken by foreign oil and gas producing nations;

• the availability of local, intrastate and interstate transportation systems;

• the availability and marketing of competitive fuels;

• the impact of energy conservation efforts; and

• the extent of governmental regulation and taxation.

Acquisitions and expansions may affect PVR’s business by substantially increasing the level of its indebtedness and contingent liabilities and increasing the risks of being unable to effectively integrate these new operations.

From time to time, PVR evaluates and acquires assets and businesses that it believes complement its existing operations. Readily available access to debt and equity capital and credit availability has been and continues to be critical factors in PVR’s ability to grow. The current deterioration in the global economy, including financial markets, and the consequential adverse effect on credit availability is adversely impacting PVR’s access to new capital and credit availability. Depending on the longevity and ultimate severity of the deterioration, PVR’s ability to make acquisitions may be significantly adversely affected. In the event PVR completes acquisitions, PVR may encounter difficulties integrating these acquisitions with its existing businesses without a loss of employees or customers, a loss of revenues, an increase in operating or other costs or other difficulties. In addition, PVR may not be able to realize the operating efficiencies, competitive advantages, cost savings or other benefits expected from these acquisitions. Future acquisitions might not generate increases in PVR’s cash distributions to its unitholders, and because of the capital used to complete such acquisitions, or the debt incurred, PVR’s and our results of operations may change significantly.

Expanding PVR’s natural gas midstream business by constructing new gathering systems, pipelines and processing facilities subjects PVR to construction risks.

One of the ways PVR may grow its natural gas midstream business is through the construction of additions to existing gathering, compression and processing systems. The construction of a new gathering system or pipeline, the expansion of an existing pipeline through the addition of new pipe or compression and the construction of new processing facilities involve numerous regulatory, environmental, political and legal uncertainties beyond PVR’s control and require the expenditure of significant amounts of capital. PVR’s access to such capital is currently adversely impacted by the deterioration in the global economy, including financial and credit markets. If PVR does undertake these projects, they may not be completed on schedule, or at all, or at the anticipated cost. Moreover, PVR’s revenues may not increase immediately upon the expenditure of funds on a particular project. For example, the construction of gathering facilities requires the expenditure of significant amounts of capital, which may exceed PVR’s estimates. Generally, PVR may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, PVR may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. As a result, there is the risk that new facilities may not be able to attract enough natural gas to achieve PVR’s expected investment return, which could have a material adverse effect on PVR’s business, results of operations or financial condition.

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If PVR is unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then PVR may be unable to fully execute its growth strategy and its cash flows could be reduced.

The construction of additions to PVR’s existing gathering assets may require PVR to obtain new rights-of-way before constructing new pipelines. PVR may be unable to obtain rights-of-way to connect new natural gas supplies to its existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for PVR to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then PVR’s cash flows could be reduced.

PVR is exposed to the credit risk of its natural gas midstream customers, and nonpayment or nonperformance by PVR’s customers would reduce its cash flows.

PVR is subject to risk of loss resulting from nonpayment or nonperformance by its natural gas midstream customers. PVR depends on a limited number of customers for a significant portion of its natural gas midstream revenues. In the year ended December 31, 2008, 40% of PVR’s natural gas midstream segment revenues and 24% of our total consolidated revenues related to two of PVR’s natural gas midstream segment customers. Any nonpayment or nonperformance by PVR’s natural gas midstream segment customers would reduce its cash flows.

Any reduction in the capacity of, or the allocations to, PVR in interconnecting third-party pipelines could cause a reduction of volumes processed, which could adversely affect PVR’s revenues and cash flows.

PVR is dependent upon connections to third-party pipelines to receive and deliver residue gas and NGLs. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures or other causes could result in reduced volumes gathered and processed in PVR’s natural gas midstream facilities. Similarly, if additional shippers begin transporting volumes of residue gas and NGLs on interconnecting pipelines, PVR’s allocations in these pipelines could be reduced. Any reduction in volumes gathered and processed in PVR’s facilities could adversely affect its revenues and cash flows.

Natural gas derivative transactions may limit PVR’s potential gains and involve other risks.

In order to manage PVR’s exposure to price risks in the marketing of its natural gas and NGLs, PVR periodically enters into condensate, natural gas and NGL price hedging arrangements with respect to a portion of its expected production. PVR’s hedges are limited in duration, usually for periods of two years or less. However, in connection with acquisitions, sometimes PVR’s hedges are for longer periods. These hedging transactions may limit PVR’s potential gains if natural gas or NGL prices were to rise (or decline with respect to natural gas hedges entered into to lock the frac spread) over the price established by the hedging arrangements. Moreover, PVR has entered into derivative transactions related to only a portion of its condensate, natural gas and NGL volumes. As a result, PVR will continue to have direct commodity price risk with respect to the unhedged portion of these volumes. In trying to maintain an appropriate balance, PVR may end up hedging too much or too little, depending upon how natural gas or NGL prices fluctuate in the future.

In addition, derivative transactions may expose PVR to the risk of financial loss in certain circumstances, including instances in which:

• PVR’s production is less than expected;

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• there is a widening of price basis differentials between delivery points for PVR’s production and the delivery point assumed in the hedge arrangement;

• the counterparties to PVR’s futures contracts fail to perform under the contracts; or

• a sudden, unexpected event materially impacts natural gas or NGL prices.

In addition, derivative instruments involve basis risk. Basis risk in a derivative contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of production may have more or less variability than the regional price index used for the sale of that production.

The accounting standards regarding hedge accounting are complex, and even when PVR engages in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect volatility due to these derivatives, even when there is no underlying economic impact at that point. In addition, it is not always possible for PVR to engage in a derivative transaction that completely mitigates its exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which PVR is unable to enter into a completely effective hedge transaction.

PVR’s natural gas midstream business involves many hazards and operational risks, some of which may not be fully covered by insurance.

PVR’s natural gas midstream operations are subject to the many hazards inherent in the gathering, compression, treating, processing and transportation of natural gas and NGLs, including:

• damage to pipelines, related equipment and surrounding properties caused by hurricanes, tornadoes, floods and other natural disasters and acts of terrorism;

• inadvertent damage from construction and farm equipment;

• leaks of natural gas, NGLs and other hydrocarbons; and

• fires and explosions.

These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of PVR’s related operations. PVR’s natural gas midstream operations are concentrated in Texas and Oklahoma, and a natural disaster or other hazard affecting these areas could have a material adverse effect on its business, results of operations or financial condition. PVR is not fully insured against all risks incident to its natural gas midstream business. PVR does not have property insurance on all of its underground pipeline systems that would cover damage to the pipelines. PVR is not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, it could adversely affect PVR’s business, results of operations or financial condition.

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Federal, state or local regulatory measures could adversely affect PVR’s natural gas midstream business.

PVR owns and operates an 11-mile interstate natural gas pipeline that, pursuant to the Natural Gas Act of 1938, or the NGA, is subject to the jurisdiction of the Federal Energy Regulatory Commission, or the FERC. The FERC has granted PVR waivers of various requirements otherwise applicable to conventional FERC-jurisdictional pipelines, including the obligation to file a tariff governing rates, terms and conditions of open access transportation service. The FERC has determined that PVR will have to comply with the filing requirements if the PVR natural gas midstream segment ever desires to apply for blanket transportation authority to transport third-party gas on the 11-mile pipeline. The FERC may revoke these waivers at any time.

PVR’s natural gas gathering facilities generally are exempt from the FERC’s jurisdiction under the NGA, but the FERC regulation nevertheless could change and significantly affect PVR’s gathering business and the market for its services. For a more detailed discussion of how regulatory measures affect PVR’s natural gas gathering systems, see “Business—Government regulation and environmental matters—PVR natural gas midstream segment.”

Failure to comply with applicable federal and state laws and regulations can result in the imposition of administrative, civil and criminal remedies.

The natural gas midstream business is subject to extensive environmental regulation.

Many of the operations and activities of PVR’s gathering systems, plants and other facilities are subject to significant federal, state and local environmental laws and regulations. These include, for example, laws and regulations that impose obligations related to air emissions and discharge of wastes from PVR’s facilities and the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by PVR or the prior owners of its natural gas midstream business or locations to which it or they have sent wastes for disposal. These laws and regulations can restrict or impact PVR’s business activities in many ways, including restricting the manner in which it disposes of substances, requiring pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in PVR’s natural gas midstream business due to its handling of natural gas and other petroleum products, air emissions related to its natural gas midstream operations, historical industry operations, waste disposal practices and the use by the prior owners of its natural gas midstream business of natural gas flow meters containing mercury. For example, an accidental release from one of PVR’s pipelines or processing facilities could subject it to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the

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possibility exists that stricter laws, regulations or enforcement policies could significantly increase PVR’s compliance costs and the cost of any remediation that may become necessary. PVR may incur material environmental costs and liabilities. Insurance may not provide sufficient coverage in the event an environmental claim is made. See “Business—Government regulation and environmental matters—PVR natural gas midstream segment.”

Risks relating to taxes

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

On February 26, 2009, the White House released President Obama’s budget proposal for fiscal year 2010. Among the changes contained in the budget proposal is the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures.

On April 23, 2009, the Oil Industry Tax Break Repeal Act of 2009, or the Senate Bill, was introduced in the Senate and includes many of the proposals outlined in the budget proposal. It is unclear whether any such changes will actually be enacted or how soon any such changes could become effective. The passage of any legislation as a result of the budget proposal, the Senate Bill or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively impact our financial condition and results of operations.

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Use of proceeds

We estimate that the net proceeds from the sale of the notes in this offering will be approximately $         million after deducting fees and expenses (including underwriting discount) of approximately $         million. We intend to use all of the net proceeds of this offering to pay down a portion of the outstanding borrowings under our Revolver. Affiliates of certain of the underwriters are currently lenders under our Revolver and, accordingly, they will receive a portion of the proceeds from the sale of the notes in this offering. See “Underwriting.”

Borrowings under our Revolver were incurred primarily to fund the drilling of wells across our operating areas, to make acquisitions and for other general corporate purposes.

Our Revolver matures in December 2010. We have the option to elect interest at (i) the London Interbank Offering Rate, or LIBOR, plus a margin ranging from 2.00% to 3.00% or (ii) the greater of the prime rate or federal funds rate plus a margin ranging from 1.125% to 2.125%, in each case based on the ratio of our outstanding borrowings to the borrowing base. The weighted average interest rate on borrowings outstanding under our Revolver at March 31, 2009 was approximately 3.89% (after giving effect to our interest rate swaps).

We intend to redraw some or all the amounts paid down on our Revolver for general corporate purposes, including working capital, exploration and development of our oil and natural gas properties, acquisition, exploration and development of additional properties or interests and acquisition of other oil and natural gas businesses.

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Capitalization

The following table sets forth our capitalization as of March 31, 2009:

• on an actual basis;

• on an as adjusted basis to give effect to the completion of the sale of 3,500,000 shares of our common stock on May 22, 2009 and the application of the net proceeds therefrom to pay down a portion of the outstanding borrowings under our Revolver; and

• on an as further adjusted basis to reflect the issuance of the notes in this offering and the application of the net proceeds therefrom as described in “Use of proceeds.”

You should read the information below in conjunction with “Use of proceeds,” “Management’s discussion and analysis of financial condition and results of operations” and our audited consolidated financial statements and related notes included elsewhere in this prospectus supplement.

	As of March 31, 2009
($ in thousands)	Actual			As adjusted(1)			As further adjusted(2)
Cash and cash equivalents	$	29,721		$	29,721		$	29,721
Long-term debt of Penn Virginia:
Revolver	$	390,000		$	325,100		$
% Senior Notes due 2016		—			—
Convertible Notes		201,545			201,545			201,545
Other consolidated non-recourse debt(3)		595,100			595,100			595,100
Total debt	$	1,186,645		$	1,121,745		$
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—41,883,695 shares issued and outstanding (actual); 45,383,695 shares issued and outstanding (as adjusted)		230			265			265
Paid-in capital		599,984			664,849			664,849
Retained earnings		434,087			434,087			434,087
Accumulated other comprehensive income and other		(4,378	)		(4,378	)		(4,378	)
Total Penn Virginia Corporation shareholders’ equity	$	1,029,923		$	1,094,823		$	1,094,823
Noncontrolling interests of subsidiaries		285,065			285,065			285,065
Total shareholders’ equity	$	1,314,988		$	1,379,888		$	1,379,888
Total capitalization	$	2,501,633		$	2,501,633		$

(1) Reflects the use of the net proceeds from the sale of 3,500,000 shares of our common stock, which was completed on May 22, 2009, to pay down a portion of the outstanding borrowings under our Revolver. Amounts repaid under our Revolver may be re-borrowed, subject to the terms and conditions of our Revolver.

(2) Reflects the use of the net proceeds from this offering to pay down a portion of the outstanding borrowings under our Revolver. Amounts repaid under our Revolver may be re-borrowed, subject to the terms and conditions of our Revolver.

(3) As of March 31, 2009, our other consolidated non-recourse debt consisted of $595.1 million outstanding under PVR’s revolving credit facility.

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Selected historical financial data

The following tables show our selected historical financial data as of and for the periods indicated and selected historical financial data of the Restricted Group as of and for the periods indicated. Our and the Restricted Group’s selected income statements, statements of cash flows and balance sheets historical financial data as of and for the years ended December 31, 2008, 2007, 2006, 2005 and 2004 have been derived from our audited consolidated financial statements and the notes thereto. Our and the Restricted Group’s selected historical financial data as of and for the three months ended March 31, 2009 and 2008 are derived from our unaudited consolidated financial statements and the notes thereto and, in our opinion, except as described below, have been prepared on a basis consistent with the audited financial statements and the notes thereto and include all adjustments consisting of normal recurring adjustments, necessary for a fair presentation of this information. Certain historical amounts have been reclassified to conform to the current presentation.

Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. Because PVG controls the general partner of PVR, the financial results of PVG include those of PVR. However, PVG and PVR function with capital structures that are independent of each other and us, with each having publicly traded common units and PVR having its own debt instruments. Furthermore, PVG and PVR are not part of the Restricted Group, and therefore, the only cash flows from PVG and PVR that are available to us to help service our debt, including the notes, are the distributions we receive in respect of our partner interests in PVG and PVR. Certain financial data for the Restricted Group are set forth in a separate table below our consolidated selected financial data. See also note 24 in the notes to our audited consolidated financial statements and note 13 in the notes to our unaudited consolidated financial statements included elsewhere in this prospectus supplement for a discussion of guarantor subsidiaries.

Effective January 1, 2009, we adopted (i) FSP APB 14-1 and (ii) SFAS 160. FSP APB 14-1 required us to separately account for the liability and equity components of the Convertible Notes in a manner that reflects our nonconvertible borrowing debt borrowing rate when measuring interest cost of the Convertible Notes. Because the liability component was valued exclusive of the conversion feature, the Convertible Notes were recorded at a discount, which will be recognized as additional interest expense over the term of the Convertible Notes. SFAS 160 requires minority interest in PVG and PVR to be reclassed to noncontrolling interest within shareholders’ equity. Additionally, SFAS 160 requires allocation of net income between our shareholders and the noncontrolling interest in PVR and PVG on the consolidated statements of income.

Both of these accounting standards are to be applied retrospectively. Throughout this prospectus supplement, the adoption of these standards has been reflected in the balance sheet and shareholders’ equity as of March 31, 2009 and in the consolidated statements of income and cash flows for the three months ended March 31, 2009 and 2008 only. Other balance sheets, consolidated statements of income, shareholders’ equity, cash flows and related financial data as of and for each of the years in the five-year period ended December 31, 2008, or as of or for any other period referenced in this prospectus supplement, have not been adjusted to reflect the adoptions of FSP APB 14-1 or SFAS 160. The retroactive application of these standards would have decreased net income by approximately $3.1 million and $0.3 million for the years ended December 31, 2008 and 2007, with no impact on net income in 2006, 2005 or 2004.

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We derived the data in the following tables from, and the following tables should be read together with and are qualified in their entirety by reference to, our historical financial statements and the accompanying notes included elsewhere in this prospectus supplement. The tables should also be read together with “Management’s discussion and analysis of financial condition and results of operations.”

Consolidated financial data

	Three months ended March 31,						Year ended December 31,
($ in thousands)	2009			2008			2008			2007			2006			2005			2004
Income statement data:
Revenues:
Natural gas	$	52,821		$	80,513		$	368,801		$	262,169		$	212,919		$	212,427		$	136,312
Crude oil		6,328			9,215			46,529			22,439			17,634			11,531			13,364
Natural gas liquids		3,370			1,868			21,292			5,678			3,603			2,261			2,110
Natural gas midstream		95,206			125,048			589,783			433,174			402,715			348,657
Coal royalties		30,630			23,962			122,834			94,140			98,163			82,725			69,643
Gain on sales of property and equipment		—			—			31,426			12,416			—			—			—
Other		10,805			8,529			40,186			22,934			18,895			16,263			6,996
Total revenues	$	199,160		$	249,135		$	1,220,851		$	852,950		$	753,929		$	673,864		$	228,425
Expenses:
Cost of midstream gas purchased	$	79,398		$	99,697		$	484,621		$	343,293		$	334,594		$	303,912		$	—
Operating		22,702			21,002			89,891			67,610			47,406			32,685			21,773
Exploration		21,312			4,680			42,436			28,608			34,330			40,917			26,058
Taxes other than income		6,432			7,395			28,586			21,723			14,767			16,005			10,480
General and administrative		18,486			17,659			74,494			66,983			49,566			36,606			26,170
Impairments		1,196			—			51,764			2,586			8,517			4,785			655
Depreciation, depletion and amortization		57,073			38,569			192,236			129,523			94,217			76,937			54,952
Total expenses	$	206,599		$	189,002		$	964,028		$	660,326		$	583,397		$	511,847		$	147,629
Operating income	$	(7,439	)	$	60,133		$	256,823		$	192,624		$	170,532		$	162,017		$	80,796
Other income (expense):
Interest expense		(12,502	)		(10,747	)		(44,261	)		(37,419	)		(24,832	)		(15,318	)		(7,672	)
Other		1,573			2,331			(666	)		3,651			3,718			1,332			1,101
Derivatives		10,255			(25,901	)		46,582			(47,282	)		19,497			(14,885	)		—
Income (loss) before minority interest, noncontrolling interest and income taxes		(8,113	)		25,816			258,478			111,574			168,915			133,146			74,225
Minority interest(1)								60,436			30,319			43,018			30,389			19,023
Income tax benefit (expense)		4,562			(2,594	)		(73,874	)		(30,501	)		(49,988	)		(40,669	)		(21,847	)
Net income (loss)(1)		(3,551	)		23,222		$	124,168		$	50,754		$	75,909		$	62,088		$	33,355
Noncontrolling interests(1)		(3,658	)		(20,028	)
Net income (loss) attributable to Penn Virginia Corporation(1)	$	(7,209	)	$	23,222
Balance sheet data (at period end):
Cash and cash equivalents	$	29,721		$	32,880		$	18,338		$	34,527		$	20,338		$	25,913		$	25,471
Net property and equipment		2,542,804			1,972,486			2,511,175			1,899,014			1,358,383			983,219			665,488
Total assets		3,000,498			2,352,479			2,996,552			2,253,461			1,633,149			1,251,546			783,335
Total long-term debt, including current maturities		1,186,645			819,748			1,137,642			763,714			439,046			333,954			193,726
Minority interest of subsidiaries(1)					187,153			299,671			179,162			438,372			313,524			182,891
Shareholders’ equity(1)		1,314,988			811,441			1,018,790			810,098			382,425			310,308			252,860

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	Three months ended March 31,				Year ended December 31,
($ in thousands)	2009		2008		2008		2007		2006		2005		2004
Cash flows data:
Net cash flows provided by (used in):
Operating activities	$ 103,019		$   66,152		$ 383,774		$ 313,030		$ 275,819		$ 231,407		$ 146,365
Investing activities	(139,039	)	(112,997	)	(845,567	)	(683,483	)	(462,335	)	(457,939	)	(151,357	)
Financing activities	47,396		45,198		445,604		384,642		180,941		226,974		12,455
Ratio of earnings to fixed charges(2)	0.3x		3.1x		5.7x		3.3x		6.3x		7.3x		7.6x
Earnings per share–basic and diluted:
Net income per share, basic					$       2.97		$       1.33		$       2.03		$       1.67		$       1.82
Net income per share, diluted					$       2.95		$       1.32		$       2.01		$       1.66		$       1.81
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, basic	$      (0.17	)	$       0.08
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, diluted	$      (0.17	)	$       0.07

(1) If adjusted for the adoption of SFAS 160, minority interest on the consolidated statement of income for the years ended December 31, 2008, 2007 and 2006 would not exist, and the amounts for each year would be considered noncontrolling interests. Minority interest on the balance sheets for the comparable periods would be considered noncontrolling interest, which is a component of shareholders’ equity.

(2) This data is unaudited for all periods presented. For purposes of computing our ratio of earnings to fixed charges on a consolidated basis, (x) earnings consist of the aggregate of income (before adjustment for income taxes, extraordinary items, income or loss from equity investees and minority interest), plus fixed charges, amortization of capitalized interest and distributed income of equity investees, and minus capitalized interest, and (y) fixed charges consist of interest expense (including amounts capitalized), amortization of debt issuance costs and the portion of rental expense representing the interest factor.

Restricted Group financial data

	Three months ended March 31,					Year ended December 31,
($ in thousands)	2009			2008		2008		2007		2006
Income statement and cash flow data:
Total revenues	$	64,564		$	92,300	$	469,333	$	334,216	$	235,948
Interest expense		6,886			5,815		19,568		20,082		6,011
Net income		(7,516	)		2,822		122,550		81,528		75,909
Additions to property and equipment		120,980			95,732		608,808		519,470		335,227
Balance sheet data (at period end):
Cash and cash equivalents		7,977			13,919		—		4,035
Total debt		591,545			406,000		569,542		352,000
Equity		1,058,776			841,841		1,047,947		840,871
Total debt and equity		1,650,321			1,247,841		1,617,489		1,192,871
Other financial data and key credit statistics:
EBITDAX(1)	$	53,400		$	64,148	$	308,305	$	201,765	$	179,957
PVG/PVR distribution to Penn Virginia		11,556			10,432		44,018		29,840		28,543
Adjusted EBITDAX(1)		64,956			74,580		352,323		231,605		208,500
Total interest(2)		7,250			6,629		21,606		23,767		8,828
Ratio of total debt to Adjusted EBITDAX							1.6x		1.5x
Ratio of Adjusted EBITDAX to total interest(2)		9.0x			11.3x		16.3x		9.7x		23.6x

(1) EBITDAX represents net income of the Restricted Group, after deducting equity in earnings of our non-guarantor subsidiaries, before income tax expense, interest expense, depreciation, depletion and amortization, impairment of oil and gas properties, non-cash derivative loss (gain), loss (gain) on sale of properties, loss on assets held for sale, non-cash compensation expense and exploration expenses of the Restricted Group. Adjusted EBITDAX represents EBITDAX of the Restricted Group, plus cash distributions we received in respect of our partner interests in PVG and PVR. EBITDAX and Adjusted EBITDAX of the Restricted Group are not measures calculated in accordance with GAAP. EBITDAX and Adjusted EBITDAX of the Restricted Group should not be considered as alternatives to net income,

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income before taxes, net cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. We believe that EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt and to fund capital expenditures. Because EBITDAX is commonly used in the oil and gas industry, we believe it is useful in evaluating our ability to meet our interest obligations in connection with this offering. EBITDAX and Adjusted EBITDAX calculations may vary among entities, so our computation of EBITDAX and Adjusted EBITDAX may not be comparable to EBITDAX and Adjusted EBITDAX, or similar measures, of other entities. In evaluating EBITDAX and Adjusted EBITDAX, we believe that investors should consider, among other things, the amount by which EBITDAX and Adjusted EBITDAX exceed interest costs, how EBITDAX and Adjusted EBITDAX compare to principal payments on debt and how EBITDAX and Adjusted EBITDAX compare to capital expenditures for each period. The following table provides a reconciliation of net income of the Restricted Group to EBITDAX and to Adjusted EBITDAX of the Restricted Group:

	Three months ended March 31,						Year ended December 31,
($ in thousands)	2009			2008			2008			2007			2006
Net income	$	(7,516	)	$	2,822		$	122,550		$	81,528		$	75,909
Less: Equity in earnings of subsidiaries (non guarantors)		(3,658	)		(8,641	)		(28,259	)		(27,942	)		(19,248	)
Add:
Interest expense		6,886			5,815			19,568			20,082			6,011
Income tax expense (benefit)		(7,044	)		(3,168	)		59,102			32,350			36,119
Depreciation, depletion and amortization		40,870			27,435			135,664			88,208			56,695
EBITDA	$	29,538		$	24,263		$	308,625		$	194,226		$	155,486
Impairment of oil and gas properties		1,196			—			19,963			2,586			8,517
Non-cash derivative loss (gain)		(1,103	)		34,246			(37,365	)		16,122			(20,259	)
Loss (gain) on sale of properties		11			(46	)		(30,634	)		(43,210	)		242
Non-cash compensation expense		2,446			1,005			5,280			3,433			1,641
Adjusted EBITDA	$	32,088		$	59,468		$	265,869		$	173,157		$	145,627
Exploration expenses		21,312			4,680			42,436			28,608			34,330
EBITDAX	$	53,400		$	64,148		$	308,305		$	201,765		$	179,957
Distributions from PVG and PVR		11,556			10,432			44,018			29,840			28,543
Adjusted EBITDAX	$	64,956		$	74,580		$	352,323		$	231,605		$	208,500

(2) Total interest includes interest expense of the Restricted Group plus interest capitalized during the period.

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Management’s discussion and analysis of financial condition and results of operations

Overview of business

We are an independent oil and gas company primarily engaged in the development, exploration and production of natural gas and oil through our subsidiary, PVOG. We also own partner interests in PVR, which is involved in the coal and natural resource management and natural gas midstream businesses, and PVG, which owns PVR’s general partner.

We have a geographically diverse asset base with core areas of operation in the East Texas, Mid-Continent, Appalachian, Mississippi and Gulf Coast regions of the United States. As of December 31, 2008, we had proved natural gas and oil reserves of approximately 916 Bcfe, of which 82% were natural gas and 51% were proved developed, with an SEC pre-tax PV-10 value of $908.0 million and standardized measure of discounted future net cash flows of $729.4 million. See “Summary—Summary reserve, production and operating data” for a reconciliation of PV-10 to standardized measure of discounted future net cash flows.

Effective January 1, 2009, we adopted (i) FSP APB 14-1 and (ii) SFAS 160. FSP APB 14-1 required us to separately account for the liability and equity components of the Convertible Notes in a manner that reflects our nonconvertible borrowing debt borrowing rate when measuring interest cost of the Convertible Notes. Because the liability component was valued exclusive of the conversion feature, the Convertible Notes were recorded at a discount, which will be recognized as additional interest expense over the term of the Convertible Notes. SFAS 160 requires minority interest in PVG and PVR to be reclassed to noncontrolling interest within shareholders’ equity. Additionally, SFAS 160 requires allocation of net income between our shareholders and the noncontrolling interest in PVR and PVG on the consolidated statements of income.

Both of these accounting standards are to be applied retrospectively. Throughout this prospectus supplement, the adoption of these standards has been reflected in the balance sheet and shareholders’ equity as of March 31, 2009 and in the consolidated statements of income and cash flows for the three months ended March 31, 2009 and 2008 only. Other balance sheets, consolidated statements of income, shareholders’ equity, cash flows and related financial data as of and for each of the years in the three-year period ended December 31, 2008, or as of or for any other period referenced in this prospectus supplement, have not been adjusted to reflect the adoptions of FSP APB 14-1 or SFAS 160, except where noted. The retroactive application of these standards would have decreased net income by approximately $3.1 million and $0.3 million for the years ended December 31, 2008 and 2007, with no impact on net income in 2006.

For the three months ended March 31, 2009 and the year ended December 31, 2008, we had average daily production of 152.3 MMcfe and 128.1 MMcfe. Our properties generally have long reserve lives and reasonably stable and predictable well production characteristics with a ratio of proved reserves to production (based on production for the year ended December 31, 2008) of approximately 19.5 years. At December 31, 2008, we owned 1.2 million net acres of leasehold interests, approximately 37% of which were undeveloped.

We are engaged in three primary business segments: (i) oil and gas, (ii) coal and natural resource management and (iii) natural gas midstream. We operate our oil and gas segment and PVR operates the coal and natural resource management and natural gas midstream segments.

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Our consolidated operating loss was $7.4 million in the three months ended March 31, 2009, compared to consolidated operating income of $60.1 million for the same period of 2008. The following tables present a summary of certain financial information relating to our segments for the three months ended March 31, 2009 and 2008:

	Three months ended March 31, 2009
($ in thousands)	Oil and gas			PVR coal and natural resource management		PVR natural gas midstream			Eliminations and other			Consolidated
Revenues	$	64,565		$	38,252	$	118,507		$	(22,164	)	$	199,160
Operating costs and expenses		46,025			5,884		112,445			(16,024	)		148,330
Impairments		1,196			—		—			—			1,196
Depreciation, depletion and amortization		39,999			7,394		9,109			571			57,073
Operating income (loss)	$	(22,655	)	$	24,974	$	(3,047	)	$	(6,711	)	$	(7,439	)

	Three months ended March 31, 2008
($ in thousands)	Oil and gas		PVR coal and natural resource management		PVR natural gas midstream		Eliminations and other			Consolidated
Revenues	$	92,299	$	30,294	$	126,520	$	22		$	249,135
Operating costs and expenses		29,331		6,299		107,781		7,022			150,433
Depreciation, depletion and amortization		26,616		6,413		5,087		453			38,569
Operating income (loss)	$	36,352	$	17,582	$	13,652	$	(7,453	)	$	60,133

Our operating income was $256.8 million in the year ended December 31, 2008, compared to $192.6 million in 2007 and $170.5 million in 2006. The following tables present a summary of certain financial information relating to our segments for the years ended December 31, 2008, 2007 and 2006:

	Year ended December 31, 2008
($ in thousands)	Oil and gas		PVR coal and natural resource management		PVR natural gas midstream		Eliminations and other			Consolidated
Revenues	$	469,330	$	153,327	$	728,253	$	(130,059	)	$	1,220,851
Operating costs and expenses		146,515		26,226		650,145		(102,858	)		720,028
Impairments		19,963		—		31,801		—			51,764
Depreciation, depletion and amortization		132,276		30,805		27,361		1,794			192,236
Operating income (loss)	$	170,576	$	96,296	$	18,946	$	(28,995	)	$	256,823

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	Year ended December 31, 2007
($ in thousands)	Oil and gas		PVR coal and natural resource management		PVR natural gas midstream		Eliminations and other			Consolidated
Revenues	$	303,241	$	111,639	$	437,806	$	264		$	852,950
Operating costs and expenses		109,449		20,138		370,070		28,560			528,217
Impairments		2,586		—		—		—			2,586
Depreciation, depletion and amortization		87,223		22,690		18,822		788			129,523
Operating income (loss)	$	103,983	$	68,811	$	48,914	$	(29,084	)	$	192,624

	Year ended December 31, 2006
($ in thousands)	Oil and gas		PVR coal and natural resource management		PVR natural gas midstream		Eliminations and other			Consolidated
Revenues	$	235,956	$	112,981	$	404,910	$	82		$	753,929
Operating costs and expenses		86,369		19,138		358,440		16,716			480,663
Impairments		8,517		—		—		—			8,517
Depreciation, depletion and amortization		56,237		20,399		17,094		487			94,217
Operating income (loss)	$	84,833	$	73,444	$	29,376	$	(17,121	)	$	170,532

The deterioration in global financial markets, which began during the third quarter of 2008, and the consequential adverse effect on credit availability continues to adversely impact our and PVR’s access to new capital and credit availability. Depending on the longevity and ultimate severity of this deterioration, our and PVR’s ability to conduct a growth oriented capital spending program will be adversely affected, as could PVR’s ability to make cash distributions to its limited partners and to PVG, the owner of its general partner. See “Risk factors.”

Oil and gas segment

We have a geographically diverse asset base with core areas of operation in the East Texas, Mid-Continent, Appalachian, Mississippi and Gulf Coast regions of the United States. As of December 31, 2008, we had proved natural gas and oil reserves of approximately 916 Bcfe, of which 82% were natural gas and 51% were proved developed. In the three months ended March 31, 2009, we produced 13.7 Bcfe, a 30% increase compared to 10.5 Bcfe in the same period in 2008. However, our average realized price received for natural gas decreased 46%, from $8.26 per Mcf in the three months ended March 31, 2008 to $4.48 per Mcf in the three months ended March 31, 2009, while the average realized price received for our crude oil decreased 62%, from $97.00 per Bbl to $37.01 per Bbl, and the average realized price received for our NGLs decreased 58%, from $54.94 per Bbl to $22.93 per Bbl in the same periods.

As of December 31, 2008, 97% of our proved reserves were located in primarily longer-lived, lower-risk basins in East Texas, the Mid-Continent, Appalachia and Mississippi, which comprised 43%, 15%, 19% and 15% of the proved reserves. Our Gulf Coast properties, representing 3% of proved reserves, are shorter-lived and have higher impact exploratory prospects. In the year

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ended December 31, 2008, we produced 46.9 Bcfe, a 16% increase compared to 40.6 Bcfe in 2007, with East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast comprising 29%, 16%, 25%, 16% and 16% of total production volumes. In the three years ended December 31, 2008, we drilled 785 gross (544.4 net) wells, of which 94% were successful in producing natural gas in commercial quantities. For a more detailed discussion of our reserves and production, see “Business—Properties.”

The primary development play types that our oil and gas operations are focused on include the horizontal Lower Bossier (Haynesville) Shale play in East Texas, the horizontal Granite Wash play in the Mid-Continent, the multi-lateral horizontal CBM play in Appalachia and the predominantly horizontal Selma Chalk play in Mississippi.

As of December 31, 2008, we owned 1.2 million net acres of leasehold interests, approximately 37% of which were undeveloped. Many of our proved undeveloped locations and additional potential drilling locations are direct offsets or extensions from existing production. We believe our existing undeveloped acreage position represents over 10 years of drilling opportunities based on our historical drilling rate.

Our operations include both conventional and unconventional developmental drilling opportunities, as well as some exploratory prospects. In the East Texas play, we drilled 102 gross (76.4 net) wells in 2008, including 93 gross (68.4 net) successful wells. We recently shifted our focus to the Lower Bossier (Haynesville) Shale play, which we believe has increased proved reserves and production levels. In Appalachia, we drilled 75 gross (33.1 net) wells in 2008, including 18 gross (9.0 net) horizontal CBM locations and 71 gross (30.6 net) successful locations. In the Selma Chalk play in Mississippi, we drilled 29 gross (28.6 net) wells in 2008, including 28 gross (27.6 net) successful horizontal wells. We also have unconventional development programs in the Mid-Continent and some higher-impact exploratory prospects in the Gulf Coast. In the Mid-Continent region, we drilled 75 gross (37.7 net) wells in 2008, including 29 gross (23.9 net) successful CBM locations.

Prior to 2009, the growth profile in our oil and gas segment was accomplished primarily by drilling oil and natural gas wells in our operating areas and, to a lesser extent, by making acquisitions of both producing properties and undeveloped leases. In the year ended December 31, 2008, we replaced 604% of our 2008 production entirely through the drillbit by adding approximately 283 Bcfe of proved reserves from extensions, discoveries and additions, net of revisions. This growth profile has required us to spend capital in excess of our cash flow from operations, and readily available access to debt and equity capital facilitated our ability to grow. Significantly lower internal cash flows due to reduced energy commodity prices and the continued weakness in global financial markets has adversely impacted our ability to fund a growth oriented capital spending program in 2009. In response to these conditions, we have limited our capital spending in 2009 to more closely mirror internally generated cash flow.

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

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PVR coal and natural resource management segment

As of December 31, 2008, PVR owned or controlled approximately 827 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. PVR enters into long-term leases with experienced, third-party mine operators, providing them the right to mine PVR’s coal reserves in exchange for royalty payments. PVR actively works with its lessees to develop efficient methods to exploit its reserves and to maximize production from PVR’s properties. PVR does not operate any mines. In the three months ended March 31, 2009, PVR’s lessees produced 8.7 million tons of coal from its properties and paid PVR coal royalties revenues of $30.6 million, for an average royalty per ton of $3.50. In the year ended December 31, 2008, PVR’s lessees produced 33.7 million tons of coal from its properties and paid PVR coal royalties revenues of $122.8 million, for an average royalty per ton of $3.65. Approximately 82% and 86% of PVR’s coal royalties revenues in the three months ended March 31, 2009 and in the year ended December 31, 2008 were derived from coal mined on PVR’s properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of PVR’s coal royalties revenues for the respective periods was derived from coal mined on PVR’s properties under leases containing fixed royalty rates that escalate annually.

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

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

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.

The deterioration of the global economy, including financial and credit markets, has reduced worldwide demand for coal with resultant price declines. Limited access to capital has and could continue to hamper PVR’s ability to fund acquisitions, potentially restricting future growth potential. Depending on the longevity and ultimate severity of the deterioration, demand for coal may decline, which could adversely effect production and pricing for coal mined by PVR’s lessees, and, consequently, adversely effect the royalty income received by PVR and its ability to make cash distributions to its limited partners and to PVG, the owner of PVR’s general partner.

PVR natural gas midstream segment

PVR’s natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of March 31, 2009, PVR owned and operated natural gas midstream assets located in Oklahoma and Texas, including five natural gas processing facilities having 300 MMcfd of total capacity and approximately 4,069 miles of natural gas gathering pipelines. PVR’s

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natural gas midstream business earns 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, or Thunder Creek, a joint venture that gathers and transports CBM in Wyoming’s Powder River Basin. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

In the three months ended March 31, 2009, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 32.3 Bcf, or approximately 359 MMcfd. In the year ended December 31, 2008, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 98.7 Bcf, or approximately 270 MMcfd. In the three months ended March 31, 2009, 25% of PVR’s natural gas midstream segment revenues and 15% of our total consolidated revenues were derived from Conoco, Inc., one of PVR’s natural gas midstream customers. In the year ended December 31, 2008, 27% and 13% of PVR’s natural gas midstream segment revenues and 16% and 8% of our total consolidated revenues were related to two of PVR’s natural gas midstream customers, Conoco, Inc. and Louis Dreyfus Energy Services.

PVR continually seeks new supplies of natural gas to both offset the natural declines in production from the wells currently connected to its systems and to increase system throughput volumes. New natural gas supplies are obtained for all of PVR’s systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors’ systems. In the three months ended March 31, 2009, PVR’s natural gas midstream segment made aggregate capital expenditures of $14.5 million, primarily related to PVR’s Panhandle System where producers continue to develop. In the year ended December 31, 2008, PVR’s natural gas midstream segment made aggregate capital expenditures of $333.3 million, primarily related to PVR’s 25% member interest acquisition of Thunder Creek, PVR’s acquisition of Lone Star Gathering, L.P., or Lone Star, PVR’s acquisition of pipeline assets in the Anadarko Basin of Oklahoma and Texas and PVR’s capacity expanding capital expenditures related to the Spearman and Crossroads plants. For a more detailed discussion of PVR’s acquisitions and investments, see “—Acquisitions and divestitures.”

Revenues, profitability and the future rate of growth of the PVR natural gas midstream segment are highly dependent on market demand and prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market uncertainty. The deterioration in the global economy, including financial and credit markets, has resulted in a decrease in worldwide demand for oil and domestic demand for natural gas and NGLs. Limited access to capital could continue to hamper PVR’s ability to fund acquisitions, potentially restricting future growth potential. Depending on the longevity and ultimate severity of the deterioration, NGL production from PVR’s processing plants could decrease and adversely effect PVR’s natural gas midstream processing income and PVR’s ability to make cash distributions.

Other and eliminations

Other and eliminations primarily represents corporate functions such as interest expense, income tax expense, oil and gas segment derivatives and elimination of intercompany sales.

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Ownership of and relationship with PVG and PVR

Penn Virginia, PVG and PVR are publicly traded on the New York Stock Exchange, or the NYSE, under the symbols “PVA,” “PVG” and “PVR.” As of March 31, 2009, we owned the general partner of PVG and an approximate 77% limited partner interest in PVG. PVG also owns an approximate 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. We directly owned an additional 0.1% limited partner interest in PVR as of March 31, 2009. 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. While we report consolidated financial results of PVR’s coal and natural resource management and natural gas midstream businesses, the only cash we received from those businesses is in the form of cash distributions we received from PVG and PVR in respect of our partner interests in each of them.

In conjunction with the initial public offering of PVG, we contributed our general partner interest, incentive distribution rights and most of our limited partner interest in PVR to PVG in exchange for the general partner interest and a limited partner interest in PVG. We are currently entitled to receive quarterly cash distributions from PVG and PVR on our limited partner interests in PVG and PVR. As a result, we received total distributions from PVG and PVR of $11.6 million and $10.4 million in the three months ended March 31, 2009 and 2008 and $44.0 million and $29.8 million in the years ended December 31, 2008 and 2007, as shown in the following table:

	Three months ended March 31,		Year ended December 31,
($ in thousands)	2009	2008	2008	2007
Penn Virginia GP Holdings, L.P.	$11,429	$10,268	$43,435	$29,200
Penn Virginia Resource Partners, L.P.(1)	127	164	583	640
Total	$11,556	$10,432	$44,018	$29,840

(1) Includes PVR distributions for restricted units held by employees and directors.

We have historically received increasing distributions from our partner interests in PVG and PVR. Based on PVG’s and PVR’s current annualized distribution rates of $1.52 and $1.88 per unit, we would receive aggregate annualized distributions of $46.3 million in respect of our partner interests in the year ended December 31, 2009. As a result of PVR’s 2008 unit offering, we recognized a gain in shareholders’ equity and PVG recognized gains in its partners’ capital. See note 3 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a description of the PVR unit offering.

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Prior to PVG’s initial public offering in December 2006, we indirectly owned common units representing an approximate 37% limited partner interest in PVR, as well as the sole 2% general partner interest and all of the incentive distribution rights in PVR. We received total distributions from PVR of $28.6 million in 2006, allocated among our limited partner interest, general partner interest and incentive distribution rights as shown in the following table:

($ in thousands)	Year ended December 31, 2006
Limited partner interest	$23,039
General partner interest (2%)	1,254
Incentive distribution rights	4,273
Total	$28,566

Acquisitions and divestitures

Oil and gas segment

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

In 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 our Revolver.

In October 2007, we sold to PVR oil and gas royalty interests associated with leases of property in eastern Kentucky and southwestern Virginia with estimated proved reserves of 8.7 Bcfe at January 1, 2007. The sale price was $31.0 million in cash, and the proceeds of the sale were used to repay borrowings under our Revolver. The gain on the sale and the related depletion expenses have been eliminated in the consolidation of our financial statements.

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 our 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.

In August 2007, we acquired 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 our Revolver.

In July 2007, we acquired lease rights to property covering approximately 4,000 acres located in East Texas, with estimated proved reserves of 19.5 Bcfe. The purchase price was $22.0 million in cash and was funded with long-term debt under our Revolver.

In June 2006, we acquired 100% of the capital stock of Crow Creek Holding Corporation, or Crow Creek. Crow Creek was a privately owned independent exploration and production company with operations primarily in the Oklahoma portions of the Arkoma and Anadarko Basins. Crow Creek’s assets included estimated net proved reserves of 42.7 Bcfe, approximately 85% of which were natural gas. The purchase price was $71.5 million in cash and was funded with long-term debt under our Revolver.

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PVR coal and natural resource management segment

In May 2008, PVR acquired fee ownership of approximately 29 million tons of coal reserves and approximately 56 million board feet of hardwood timber in western Virginia and eastern Kentucky. The purchase price was $24.5 million in cash and was funded with long-term debt under PVR’s $800.0 million revolving credit facility, or the PVR 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.

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 $42.0 million in cash and was funded with long-term debt under the PVR Revolver.

In May 2006, PVR acquired lease rights to approximately 69 million tons of coal reserves. The reserves are located on approximately 20,000 acres in southern West Virginia. The purchase price was $65.0 million in cash and was funded with long-term debt under the PVR Revolver.

PVR natural gas midstream segment

In July 2008, PVR completed the Lone Star acquisition. Lone Star’s assets are located in the southern portion of the Fort Worth Basin of North Texas and include approximately 129 miles of gas gathering pipelines and approximately 240,000 acres dedicated by active producers. The Lone Star acquisition expanded 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 the PVR Revolver, 2,009,995 PVG common units (which PVR purchased from two of our subsidiaries for $61.8 million) and 542,610 newly issued PVR common units. The contingent payments will be triggered if revenues from certain assets located in a defined geographic area reach certain targets by or before June 30, 2013 and will be funded in cash or PVR common units, at PVR’s election.

In April 2008, PVR acquired a 25% member interest in Thunder Creek, a joint venture that gathers and transports CBM 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.

In June 2006, PVR completed the acquisition of approximately 115 miles of gathering pipelines and related compression facilities in Texas and Oklahoma. These assets are contiguous to PVR’s Panhandle System. The purchase price was $14.7 million and was funded with cash. Subsequently, PVR borrowed $14.7 million under the PVR Revolver to replenish the cash used for the acquisition.

Liquidity and capital resources

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

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

Liquidity is defined as the ability to convert assets into cash or to obtain cash. Short-term liquidity refers to the ability to meet short-term obligations of 12 months or less. Liquidity is a matter of degree and is expressed in terms of working capital and the current ratio and, due to the recent deterioration of the credit and financial markets, in terms of the availability of borrowing capacity against existing credit facilities and debt instruments. Our consolidated working capital (current assets minus current liabilities) and consolidated current ratio (current assets divided by current liabilities) are as follows as of March 31, 2009 and 2008:

	As of March 31,
($ in thousands)	2009		2008
Current assets	$231,864		$271,023
Current liabilities	190,340		279,236
Working capital	$  41,524		$(8,213	)
Current ratio	1.22	x	0.97	x

Our consolidated working capital and consolidated current ratios were as follows as of December 31, 2008 and 2007:

	As of December 31,
($ in thousands)	2008		2007
Current assets	$263,518		$244,072
Current liabilities	247,594		261,899
Working capital	$  15,924		$(17,827	)
Current ratio	1.06	x	0.93	x

Because Penn Virginia, PVG and PVR operate with independent capital structures, an important indicator of liquidity is the availability of borrowing capacity. In March 2009, our bank group completed a semi-annual redetermination of the borrowing base under our Revolver. As a result, the borrowing base was revised to $450.0 million, which is approximately 6% less than its previous level of $479.0 million. As discussed in more detail in “—Long-term debt”, as of March 31, 2009, we had availability of $59.7 million on our Revolver and PVR had availability of $203.3 million under the recently expanded PVR Revolver. As of December 31, 2008, we had availability of $146.7 million and PVR had availability of $130.3 million under our separate credit facilities.

On May 22, 2009, we completed the sale of 3,500,000 shares of our common stock in a registered public offering. The net proceeds of the sale were $64.9 million and were used to repay a portion of the outstanding borrowings under our Revolver. The net proceeds of this offering also will be used to repay a portion of the outstanding borrowings under our Revolver. We are actively considering additional alternatives to further improve our liquidity and financial flexibility, including potential sales of substantial assets, including all or a portion of the partner interests in PVG and PVR that we own. See “Risk factors—Risks related to our ownership interests in PVG and PVR—We may sell some or all of our partner interests in PVG and PVR.” We may also consider additional equity or debt offerings in the future.

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With respect to Penn Virginia (excluding the sources and uses of capital by PVG and PVR), we satisfy our working capital requirements and fund our capital expenditures using cash generated from our operations, borrowings under our Revolver and proceeds from equity offerings. We satisfy our debt service obligations and dividend payments solely using cash generated from our operations. We believe that the cash generated from our operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled debt payments and dividend payments. Our ability to satisfy our obligations and planned expenditures will depend on our future operating performance, which will be affected by, among other things, prevailing economic conditions in the commodity markets of oil and natural gas, some of which are beyond our control. Because of the recent deterioration in the financial and credit markets we are anticipating a decrease in capital spending in 2009. In addition, depending on the longevity and ultimate severity of the recent deterioration of the global economy, including financial and credit markets, our ability in the future to grow organically or through acquisitions may be significantly adversely affected. See “Risk factors.”

PVR’s ability to satisfy its obligations and planned expenditures will depend upon its future operating performance, which will be affected by prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond PVR’s control. During the first quarter of 2009, PVR completed an amendment to increase the borrowing base under the PVR Revolver, with resultant borrowing availability of $203.3 million as of March 31, 2009. However, depending on the longevity and ultimate severity of the recent deterioration of the global economy, including financial and credit markets, PVR’s ability in the future to grow organically or through acquisitions may be significantly adversely affected, as may PVR’s ability to make cash distributions to its limited partners and to PVG, the owner of PVR’s general partner. See “Risk factors.”

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Cash flows

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

The following table summarizes our cash flow statements for the three months ended March 31, 2009 and 2008, consolidating the PVG cash flow statement and the oil and gas, corporate and other cash flow statement:

	Three months ended March 31, 2009
($ in thousands)	Oil and gas, PVA corporate & other			PVG			Consolidated
Net cash provided by operating activities	$	69,360		$	33,659		$	103,019
Net cash flows from investing activities:
Acquisitions		(1,817	)		(1,256	)		(3,073	)
Additions to property and equipment		(119,163	)		(17,050	)		(136,213	)
Other		(11	)		265			254
Net cash used in investing activities	$	(120,991	)	$	(18,041	)	$	(139,032	)
Cash flows from financing activities:
Dividends paid	$	(2,349	)	$	—		$	(2,349	)
Distributions received (paid)		11,533			(29,988	)		(18,455	)
Debt borrowings, net		58,000			27,000			85,000
Repayment of bank borrowings		(7,542	)		—			(7,542	)
Other		—			(9,258	)		(9,258	)
Net cash provided by (used in) financing activities	$	59,642		$	(12,246	)	$	47,396
Net increase in cash and cash equivalents	$	8,011		$	3,372		$	11,383

	Three months ended March 31, 2008
	Oil and gas, PVA corporate & other			PVG			Consolidated
Net cash provided by operating activities	$	38,173		$	27,979		$	66,152
Net cash flows from investing activities:
Acquisitions		(4,720	)		(20	)		(4,740	)
Additions to property and equipment		(91,012	)		(17,650	)		(108,662	)
Other		64			341			405
Net cash used in investing activities	$	(95,668	)	$	(17,329	)	$	(112,997	)
Cash flows from financing activities:
Dividends paid	$	(2,344	)	$	—		$	(2,344	)
Distributions received (paid)		10,432			(24,172	)		(13,740	)
Debt borrowings, net		54,000			2,000			56,000
Other		5,282			—			5,282
Net cash provided by (used in) financing activities	$	67,370		$	(22,172	)	$	45,198
Net increase (decrease) in cash and cash equivalents	$	9,875		$	(11,522	)	$	(1,647	)

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The following table summarizes our cash flow statements for the years ended December 31, 2008, 2007 and 2006, consolidating the PVG cash flow statement and the oil and gas, corporate and other cash flow statement:

	Year ended December 31, 2008
($ in thousands)	Oil and gas, PVA corporate & other			PVG			Consolidated
Net cash provided by operating activities	$	246,587		$	137,187		$	383,774
Net cash flows from investing activities:
Acquisitions		(33,371	)		(260,376	)		(293,747	)
Additions to property and equipment		(513,687	)		(71,652	)		(585,339	)
Other		32,521			998			33,519
Net cash used in investing activities	$	(514,537	)	$	(331,030	)	$	(845,567	)
Cash flows from financing activities:
Dividends paid	$	(9,398	)	$	—		$	(9,398	)
Distributions received (paid)		44,018			(108,263	)		(64,245	)
Debt borrowings, net		210,000			156,000			366,000
Proceeds received from issuance of PVR partners’ capital		—			138,141			138,141
Short-term bank borrowings		7,542			—			7,542
Other		11,764			(4,200	)		7,564
Net cash provided by financing activities	$	263,926		$	181,678		$	445,604
Net decrease in cash and cash equivalents	$	(4,024	)	$	(12,165	)	$	(16,189	)

	Year ended December 31, 2007
($ in thousands)	Oil and gas, PVA corporate & other			PVG			Consolidated
Net cash provided by operating activities	$	186,550		$	126,480		$	313,030
Net cash flows from investing activities:
Acquisitions		(115,084	)		(176,917	)		(292,001	)
Additions to property and equipment		(373,386	)		(48,123	)		(421,509	)
Other		29,169			858			30,027
Net cash used in investing activities	$	(459,301	)	$	(224,182	)	$	(683,483	)
Cash flows from financing activities:
Dividends paid	$	(8,499	)	$	—		$	(8,499	)
Distributions received (paid)		29,840			(79,579	)		(49,739	)
Debt borrowings, net		131,000			193,500			324,500
Gross proceeds from PVA stock offering		135,441			—			135,441
Cash received for stock warrants sold		18,187			—			18,187
Cash paid for Convertible Notes hedges		(36,817	)		—			(36,817	)
Other		972			597			1,569
Net cash provided by financing activities	$	270,124		$	114,518		$	384,642
Net decrease in cash and cash equivalents	$	(2,627	)	$	16,816		$	14,189

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	Year ended December 31, 2006
($ in thousands)	Oil and gas, PVA corporate & other			PVG			Consolidated
Net cash provided by operating activities	$	175,136		$	100,683		$	275,819
Net cash flows from investing activities:
Acquisitions		(103,907	)		(91,259	)		(195,166	)
Additions to property and equipment		(231,320	)		(38,453	)		(269,773	)
Other		2,568			36			2,604
Net cash used in investing activities	$	(332,659	)	$	(129,676	)	$	(462,335	)
Cash flows from financing activities:
Dividends paid	$	(8,398	)	$	—		$	(8,398	)
Distributions received (paid)		22,186			(60,813	)		(38,627	)
Debt borrowings (repayments), net		142,000			(37,100	)		104,900
Proceeds from equity issuance		(1,590	)		119,408			117,818
Other		7,213			(1,965	)		5,248
Net cash provided by financing activities	$	161,411		$	19,530		$	180,941
Net decrease in cash and cash equivalents	$	3,888		$	(9,463	)	$	(5,575	)

Net cash provided by operating activities

Changes to working capital and to our current ratio are largely affected by net cash provided by both our and PVR’s operating activities. Net cash provided by our and PVR’s operating activities primarily came from the following sources:

Oil and gas segment

• the sale of natural gas, crude oil and NGLs;

• settlements from our oil and gas commodity derivatives; and

• the collection of fees charged for gathering natural gas volumes.

PVR coal and natural resource management segment

• the collection of coal royalties;

• the sale of standing timber;

• the collection of coal transportation, or wheelage, fees;

• distributions received from PVR’s equity investees; and

• settlements from PVR’s interest rate swaps, or the PVR Interest Rate Swaps.

PVR natural gas midstream segment

• the collection of revenues from natural gas processing contracts with natural gas producers;

• the collection of revenues from PVR’s natural gas marketing business; and

• settlements from PVR’s natural gas midstream commodity derivatives.

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In addition, we receive settlements from our interest rate swaps, or the Interest Rate Swaps, which are included in our corporate and other activities.

Both we and PVR use the cash provided by operating activities in the oil and gas segment, the PVR coal and natural resource management segment and the PVR natural gas midstream segment in the following ways:

• operating expenses, such as office rentals, core-hole drilling costs and repairs and maintenance costs;

• taxes other than income, such as severance and property taxes;

• general and administrative expenses, such as office rentals, staffing costs and legal fees;

• interest on debt service obligations;

• capital expenditures;

• repayments of borrowings;

• PVR’s distributions to partners; and

• dividends to our shareholders.

Net cash provided by operating activities of the oil and gas segment and for Penn Virginia corporate and other activities in the three months ended March 31, 2009 increased by $31.2 million, or 82%, to $69.4 million of cash provided by operating activities from $38.2 million of cash provided by operating activities in the same period of 2008. This increase was primarily due to changes in working capital. Excluding changes in working capital, cash provided by oil and gas segment operating activities decreased by $16.9 million, or 30%, to $38.8 million, due to decreased natural gas and crude oil revenues resulting from decreased commodity prices. See “—Results of operations—Oil and gas segment” and “—Results of operations—Eliminations and other—Corporate operating expenses” for a more detailed explanation of the factors that determined cash provided by operating activities.

Net cash provided by operating activities of the oil and gas segment and for Penn Virginia corporate and other activities in 2008 increased by $60.0 million, or 32%, to $246.6 million from $186.6 million in 2007. This increase was primarily attributable to increased natural gas, crude oil and NGL revenues resulting from increases in both production and pricing, partially offset by increased staffing costs in the oil and gas segment; increased severance taxes, which were driven by increased natural gas, crude oil and NGL production; increased cash outflows for oil and gas commodity derivative settlements; and increased operating costs in the oil and gas segment. See “—Results of operations—Oil and gas segment” and “—Results of operations—Eliminations and other—Corporate operating expenses” for a more detailed explanation of the factors that increased cash provided by operating activities.

Net cash provided by operating activities of the oil and gas segment and for Penn Virginia corporate and other activities in 2007 increased by $11.5 million, or 7%, to $186.6 million from $175.1 million in 2006. The overall increase in cash provided by operating activities in 2007 compared to 2006 was primarily attributable to increased natural gas and crude oil production, partially offset by increased consulting fees and staffing costs. See “—Results of operations—Oil and gas segment” and “—Results of operations—Eliminations and other—Corporate operating expenses” for a more detailed explanation of the factors that increased cash provided by operating activities.

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PVG does not have any operations on a stand-alone basis. It primarily relies on cash distributions received from PVR for its general and administrative expenses, which are the costs of PVG being a publicly-traded company.

Net cash provided by PVG’s operating activities in the three months ended March 31, 2009 increased by $5.7 million, or 20%, to $33.7 million from $28.0 million in the same period of 2008. The overall increase in net cash provided by PVG’s operating activities was primarily attributable to increased coal royalties received by PVR, which was driven primarily by increased production and sales prices of coal in all regions and an increase in cash received from the settlement of PVR’s derivative positions. These increases were partially offset by decreased cash received by PVR from the sales of residue gas and NGLs, which was primarily driven by a decrease in commodity prices for natural gas and NGLs. See “—Results of operations—PVR coal and natural resource management segment” and “—Results of operations—PVR natural gas midstream segment” for a more detailed explanation of the factors that increased cash provided by PVR’s operating activities.

Net cash provided by PVG’s consolidated operating activities in 2008 increased by $10.7 million, or 8%, to $137.2 million from $126.5 million in 2007. The overall increase in net cash provided by PVG’s consolidated operating activities in 2008 compared to 2007 was primarily attributable to increased cash received from the sales of residue gas and NGLs, which was primarily driven by increased system throughput volume; increased coal royalties received, which was driven primarily by increased production and sales prices of coal in the Central Appalachian and Illinois Basin regions; and increased cash received from the sale of standing timber, which was due primarily to increased harvesting from PVR’s September 2007 forestland acquisition. These increases were partially offset by increased cash outflows from PVR’s natural gas midstream derivative settlements. See “—Results of operations—PVR coal and natural resource management segment” and “—Results of operations—PVR natural gas midstream segment” for a more detailed explanation of the factors that increased cash provided by PVR’s operating activities.

Net cash provided by PVG’s consolidated operating activities in 2007 increased by $25.8 million, or 26%, to $126.5 million from $100.7 million in 2006. This increase was primarily attributable to increased sales of NGLs, which was primarily driven by increased volumes of processed gas and a higher frac spread during 2007 than in 2006; and decreased cash outflows for PVR’s natural gas midstream commodity derivative settlements. These increases were partially offset by a decrease in coal royalties received, which was driven by a decrease in coal production from subleased properties in the Central Appalachian region. See “—Results of operations—PVR coal and natural resource management segment” and “—Results of operations—PVR natural gas midstream segment” for a more detailed explanation of the factors that increased cash provided by PVR’s operating activities.

Net cash used in investing activities

Net cash used in investing activities in the oil and gas segment and for Penn Virginia corporate and other activities in the three months ended March 31, 2009 increased by $25.3 million, or 26%, to $121.0 million from $95.7 million in the same period of 2008. PVG’s investing activities consist solely of cash provided by and used in PVR’s investing activities. Net cash used by PVR in its investing activities in the three months ended March 31, 2009 increased by $0.7 million, or 4%, to $18.0 million from $17.3 million in the same period of 2008. The cash used by both us and PVR in investing activities in the three months ended March 31, 2009 and 2008 were used primarily for capital expenditures.

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The following table sets forth capital expenditures by segment made during the three months ended March 31, 2009 and 2008, including non-cash adjustments related to accrued drilling costs:

	Three months ended March 31,
($ in thousands)	2009	2008
Oil and gas:
Development drilling	$  76,483	$  79,115
Exploration drilling	1,468	5,425
Seismic	734	680
Lease acquisition and other	1,774	4,614
Pipeline, gathering, facilities	5,129	4,862
Total	$  85,588	$  94,696
Coal and natural resource management:
Acquisitions	$    1,256	$         20
Other property and equipment expenditures	44	28
Total	$    1,300	$         48
Natural gas midstream:
Expansion capital expenditures	$  11,200	$  16,373
Other property and equipment expenditures	3,282	3,106
Total	$  14,482	$  19,479
Other	595	251
Total capital expenditures	$101,965	$114,474

In the three months ended March 31, 2009, the oil and gas segment made aggregate capital expenditures of $85.6 million. These capital expenditures were related to development drilling and pipeline, gathering and facilities primarily in our Lower Bossier (Haynesville) play in East Texas. In the three months ended March 31, 2008, the oil and gas segment made aggregate capital expenditures of $94.7 million primarily for development drilling, exploration drilling and lease acquisitions.

In the three months ended March 31, 2009, PVR made aggregate capital expenditures of $15.8 million. These capital expenditures consisted primarily of expansion capital expenditures in the PVR natural gas midstream segment, primarily to develop additional processing capacity in its Panhandle System. The PVR natural gas midstream segment also incurred approximately $3.3 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas.

In the three months ended March 31, 2008, PVR made aggregate capital expenditures of $19.5 million. These capital expenditures consisted primarily of the PVR natural gas midstream segment gathering system expansion projects. The PVR natural gas midstream segment also incurred $3.1 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas.

We funded oil and gas and other capital expenditures in the three months ended March 31, 2009 and 2008 with borrowings under our Revolver, cash provided by operating activities, cash distributions received from PVG and PVR and cash provided by operating activities. PVR funded its coal and natural resource management and natural gas midstream capital expenditures in the

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three months ended March 31, 2009 and 2008 primarily with cash provided by operating activities and borrowings under the PVR Revolver. See “—Future capital needs and commitments” for an analysis of future capital expenditures and the sources for funding those expenditures.

Net cash used in the oil and gas segment and for Penn Virginia corporate and other activities in 2008 increased by $55.2 million, or 12%, to $514.5 million from $459.3 million in 2007. PVG’s investing activities consist solely of cash provided by and used in PVR’s investing activities. Net cash used by PVR in its investing activities in 2008 increased by $106.8 million, or 48%, to $331.0 million from $224.2 million in 2007. The cash used by both us and PVR in investing activities for the years ended December 31, 2008, 2007 and 2006 were used primarily for capital expenditures.

The following table sets forth capital expenditures by segment made during the years ended December 31, 2008, 2007 and 2006:

	Year ended December 31,
($ in thousands)	2008(1)	2007(2)	2006(3)
Oil and gas:
Proved property acquisitions	$           —	$  88,174	$    72,724
Development drilling	481,401	310,428	175,257
Exploration drilling	23,785	42,540	41,923
Seismic	4,169	2,773	6,238
Lease acquisition and other	95,529	53,775	27,795
Pipeline, gathering, facilities	36,812	22,738	14,547
Total	$   641,696	$520,428	$  338,484
Coal and natural resource management:
Acquisitions	$     27,075	$145,918	$    76,402
Expansion capital expenditures	—	85	15,103
Other property and equipment expenditures	195	84	100
Total	$     27,270	$146,087	$    91,605
Natural gas midstream:
Acquisitions	$   259,417	$        —	$    14,626
Expansion capital expenditures	59,385	38,686	15,394
Other property and equipment expenditures	14,505	9,767	9,414
Total	$   333,307	$  48,453	$    39,434
Other	$       1,336	$    7,294	$      3,682
Total capital expenditures	$1,003,609	$722,262	$  473,205

(1) The oil and gas segment acquisitions in 2006 excludes deferred tax assets of $32.3 million and acquisition of net liabilities other than property or equipment of $29.1 million related to the acquisition of Crow Creek.

(2) The PVR coal and natural resource management segment acquisitions in 2007 include an $11.5 million lease receivable associated with the acquisition of fee ownership and lease rights to coal reserves in western Kentucky and $31.0 million of oil and gas royalty interests that PVR purchased from us. The PVR coal and natural resource management segment acquisitions in 2006 include the acquisition of assets and liabilities other than property or equipment of $1.2 million.

(3) The PVR natural gas midstream segment acquisitions in 2008 include the following non-cash items, all of which was given as consideration in the Lone Star acquisition: newly issued PVR units valued at $15.2 million; PVG units, which were purchased from two of our subsidiaries, valued at $68.0 million; and a $4.7 million guaranteed payment which will be paid in 2009. The remainder of the difference between (i) capital additions and (ii) cash paid for acquisitions and additions to property and equipment primarily consists of the change in accrued drilling costs.

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In 2008, the oil and gas segment made aggregate capital expenditures of $641.7 million. These capital expenditures were primarily discretionary capital expenditures and included development drilling and various lease acquisitions primarily in East Texas. In 2008, we drilled a successful horizontal Lower Bossier (Haynesville) Shale well in Harrison County, Texas. Based on this successful horizontal test, we had four drilling rigs drilling horizontal Lower Bossier (Haynesville) Shale wells as of December 31, 2008. In addition to these capital expenditures, we also completed the sale of unproved oil and gas acreage in Louisiana for cash proceeds of $32.0 million.

In 2007, the oil and gas segment made aggregate capital expenditures of $520.4 million. These capital expenditures were primarily discretionary capital expenditures and included development drilling, the acquisitions of lease rights to property in eastern Oklahoma with estimated proved reserves of 18.8 Bcfe, the acquisition of lease rights to property in East Texas with estimated proved reserves of 21.9 Bcfe and lease rights to property in East Texas with estimated proved reserves of 19.5 Bcfe. In addition to these capital expenditures, we sold non-operated working interests in oil and gas properties located in eastern Kentucky and southwestern Virginia for $29.1 million in cash and sold to PVR oil and gas royalty interests associated with leases of property in eastern Kentucky and southwestern Virginia with estimated proved reserves of 8.7 Bcfe for $31.0 million. Other capital expenditures of $7.3 million in 2007 were also discretionary capital expenditures and were primarily due to consulting fees related to the implementation of a software system.

In 2006, the oil and gas segment made aggregate capital expenditures of $338.5 million, which were primarily discretionary capital expenditures related to development drilling, the acquisition of Crow Creek for $71.5 million and exploratory drilling.

In 2008, PVR made aggregate capital expenditures of $360.6 million. These capital expenditures consisted primarily of discretionary capital expenditures which included PVR’s 25% member interest acquisition in Thunder Creek, the Lone Star acquisition, pipeline assets in the Anadarko Basin of Oklahoma and Texas, expansion capital expenditures related to the Spearman and Crossroads plants and the acquisition of approximately 29 million tons of coal reserves and an estimated 56 million board feet of hardwood timber in western Virginia and eastern Kentucky. The PVR natural gas midstream segment also incurred approximately $14.5 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas.

In 2007, PVR made aggregate capital expenditures of $225.5 million. These capital expenditures consisted primarily of discretionary capital expenditures, which included PVR’s coal reserve acquisitions, a forestland acquisition, an oil and gas royalty interest acquisition and natural gas midstream gathering system expansion projects. The PVR natural gas midstream segment also incurred $9.8 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas.

In 2006, PVR made aggregate capital expenditures of $131.0 million. These capital expenditures consisted primarily of discretionary capital expenditures, which included PVR’s coal reserve acquisitions, coal loadout facility construction projects, a natural gas midstream acquisition and coal and natural gas midstream gathering system expansion projects. The PVR natural gas midstream segment also incurred $9.4 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas.

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We funded oil and gas and other capital expenditures in 2008 with borrowings under our Revolver, cash provided by operating activities, cash distributions received from PVG and PVR and cash provided by operating activities. We funded oil and gas and other capital expenditures in 2007 with borrowings under our Revolver, cash provided by operating activities, cash distributions received from PVG and PVR, the issuance of common stock and the Convertible Notes, the sale of common stock warrants and proceeds from the sale of oil and gas working and royalty interests. We funded oil and gas and other capital expenditures in 2006 with cash provided by operating activities, cash distributions received from PVG and PVR and borrowings under our Revolver.

PVR funded its coal and natural resource management and natural gas midstream capital expenditures in 2008 primarily with cash provided by operating activities, borrowings under the PVR Revolver, proceeds from the sale of common units and a contribution from its general partner to maintain its 2% general partner interest. PVR funded its capital expenditures in 2007 with cash provided by operating activities and borrowings under the PVR Revolver. PVR funded its capital expenditures in 2006 with cash provided by operating activities, borrowings under the PVR Revolver, proceeds from the sale of common and Class B units to PVG and a contribution from its general partner to maintain its 2% general partner interest.

Net cash provided by financing activities

Net cash provided by (used in) financing in the oil and gas segment and for corporate remained relatively constant from the three months ended March 31, 2008 to the same period of 2009. In the three months ended March 31, 2009, we borrowed $58.0 million under our Revolver. See “—Long-term debt” below for a more detailed description of our March 31, 2009 long-term debt balance.

As a result of our partner interests in PVG and PVR, we received cash distributions of $11.6 million and $10.4 million in the three months ended March 31, 2009 and 2008. These distributions were primarily used for oil and gas segment capital expenditures and operating activities.

Net cash used in PVG’s financing activities in the three months ended March 31, 2009 decreased by $10.0 million, or 45%, to $12.2 million from $22.2 million in the same period of 2008. Over the comparative period, we had an increase in cash distributions to PVG’s and PVR’s partners, which was related to an increase in the distribution per unit and to debt issuance costs paid by PVR in the three months ended March 31, 2009. The increase in cash distributions to partners was due to the increase in the cash distributions paid per unit and due to an increase in PVR’s outstanding common units resulting from the 2008 unit offering where PVR issued an additional 5.15 million common units to the public. These increases in cash used in financing activities were partially offset by an increase in net proceeds from PVR’s long-term borrowings. See “—Long-term debt” below for a more detailed description of PVR’s March 31, 2009 long-term debt balance.

The cash distribution that PVR and PVG paid to its partners in May 2009 for the first quarter of 2009 was unchanged from the distributions paid in February 2009. Both PVR and PVG will continue to be cautious about increasing and maintaining cash distributions to unitholders in the foreseeable future in order to preserve cash liquidity in light of uncertain commodity and financial markets.

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Net cash provided by financing in the oil and gas segment and for corporate activities in 2008 decreased by $6.2 million, or 2%, to $263.9 million from $270.1 million in 2007, due primarily to proceeds received in 2007, but not 2008, for a stock offering, higher net proceeds from debt borrowings in 2008 and higher distributions received from PVG and PVR in 2008. Net cash provided by financing activities in the oil and gas segment and for corporate activities in 2007 increased by $108.7 million, or 67%, to $270.1 million from $161.4 million in 2006, due primarily to the $135.4 million in net proceeds received from our 2007 stock offering, $18.2 million received in 2007 for the stock warrants that we sold and higher distributions received from PVG and PVR in 2007, partially offset by the $36.8 million paid in 2007 for the convertible note hedges.

In 2008, we had $210.0 million of net borrowings, consisting of borrowings under our Revolver of $273.0 million and repayments under our Revolver of $63.0 million. See “—Long-term debt” below for a more detailed description of our December 31, 2008 long-term debt balance. We had $131.0 million of net borrowings in 2007, comprised of net borrowings of $230.0 million under the Convertible Notes, and net repayments of $99.0 million under our Revolver. In addition, proceeds from the sale of our oil and gas working interests in 2007 were used to repay borrowings under our Revolver. We had net borrowings of $142.0 million under our Revolver in 2006, which consisted of $162.0 million of borrowings, partially offset by $20.0 million of repayments.

As a result of our partner interests in PVG and PVR, we received cash distributions of $44.0 million in 2008, $29.8 million in 2007 and $28.6 million in 2006. These distributions we received were primarily used for oil and gas segment capital expenditures.

Net cash provided by PVG’s financing activities in 2008 increased by $67.2 million, or 59%, to $181.7 million from $114.5 million in 2007. This increase was primarily due to net PVR borrowings of $156.0 million in 2008, comprised of net borrowings of $220.4 million under the PVR Revolver and net repayments of $64.4 million under PVR’s Senior Unsecured Notes due 2013, or the PVR Notes. See “—Long-term debt” below for a more detailed description of PVR’s December 31, 2008 long-term debt balance. PVR also received net proceeds of $141.1 million from the sale of its common units in a public offering in 2008, which was comprised of net proceeds of $138.2 million from the sale of the common units to the public and $2.9 million in contributions from its general partner to maintain its 2% general partner interest in PVR. These increases in 2008 financing activities were partially offset by increased cash distributions paid to PVR’s and PVG’s partners. Cash distributions paid to unaffiliated partners increased by $28.7 million, or 36%, from $79.6 million in 2007 to $108.3 million in 2008 because both PVG and PVR increased their cash distributions paid per unit. This increase in cash distributions paid to unaffiliated partners was also due to the increase in PVR’s outstanding common units resulting from PVR’s 2008 unit offering, where PVR issued an additional 5.15 million PVR common units to the public. See “—PVR unit offering” below for a more detailed description of this event. PVR also incurred $4.2 million of payments for debt issuance costs. Net cash provided by PVG’s financing activities in the year ended December 31, 2008 was used primarily for PVR’s capital expenditures.

PVR’s cash distributions per unit increased in every sequential quarter from the distribution paid in February 2007 for the fourth quarter of 2006 through the distribution paid in November 2008 for the third quarter of 2008. However, the most recent cash distribution paid to PVR’s partners in February 2009 for the fourth quarter of 2008 was unchanged from the distribution paid for the immediately prior quarter. PVG’s cash distribution per unit increased in every sequential

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quarter from the distribution paid in May 2007 for the first quarter of 2007 to the distribution paid in November 2008 for the third quarter of 2008. However, the most recent cash distribution paid to PVG’s partners in February 2009 for the fourth quarter of 2008 was unchanged from the distribution paid for the immediately prior quarter. Both PVG and PVR will continue to be cautious about increasing cash distributions to unitholders in the foreseeable future in order to preserve cash liquidity in light of uncertain commodity and financial markets.

Net cash provided by PVG’s financing activities in 2007 increased by $95.0 million, or 486%, to $114.5 million from $19.5 million in 2006. This increase is due primarily to $193.5 million of net borrowings in 2007, comprised of net borrowings of $204.5 million under the PVR Revolver and net repayments of $11.0 million under the PVR Notes. These increases in 2007 financing activities were partially offset by cash distributions paid to PVG’s and PVR’s partners. Distributions to partners increased by $18.8 million, or 31%, from $60.8 million in 2006 to $79.6 million in 2007 because PVG and PVR increased their cash distributions paid per unit. Net cash provided by PVG’s financing activities in the year ended December 31, 2007 was used primarily for PVR’s capital expenditures.

In December 2006, PVG completed its initial public offering and used substantially all of the resulting proceeds to purchase newly issued common and Class B units from PVR. PVR used the proceeds received from this transaction to repay $114.6 million of debt outstanding under the PVR Revolver. PVR had a total of $37.1 million of net repayments of debt in 2006, comprised of $28.8 million of net repayments under the PVR Revolver and $8.3 million of net repayments under the PVR Notes. PVG and PVR also paid $60.8 million in cash distributions to their partners in 2006.

In January 2009, PVG declared a $0.38 ($1.52 on an annualized basis) per unit quarterly distribution in the three months ended December 31, 2008, of which we received $11.4 million, or $45.6 million on an annualized basis, as a result of our limited partner interest in PVG. This distribution was paid on February 18, 2009 to unitholders of record at the close of business on February 2, 2009. In January 2009, PVR declared a $0.47 ($1.88 on an annualized basis) per unit quarterly distribution in the three months ended December 31, 2008, of which we received $0.1 million, or $0.4 million on an annualized basis, as a result of our limited partner interest in PVR. This distribution was paid on February 13, 2009 to unitholders of record at the close of business on February 2, 2009. The portion of PVR’s distribution paid to PVG serves as the basis for PVG’s distribution to its unitholders, including us.

Long-term debt

The discussion below presents certain information regarding our long-term debt. For more details regarding our long-term debt, please see “Description of other indebtedness.”

Revolver.     As of March 31, 2009, we had $390.0 million outstanding under our Revolver, which is senior to the Convertible Notes. Our Revolver is governed by a borrowing base calculation and is redetermined semi-annually. In March 2009, our bank group completed the semi-annual re-determination. As a result, the borrowing base was revised to $450.0 million, which is approximately 6% less than its previous level of $479.0 million. In connection with this offering, we have entered into an amendment to our Revolver to permit the issuance of the notes.

On May 22, 2009, we completed the sale of 3,500,000 shares of our common stock in a registered public offering. The net proceeds of the sale were $64.9 million and were used to repay a portion of the outstanding borrowings under our Revolver. Assuming we had completed the issuance

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and sale of shares of our common stock at March 31, 2009 and on an as adjusted basis for the application of the net proceeds from the sale of shares of our common stock, we would have had $325.1 million outstanding under our Revolver (excluding $0.3 million of letters of credit) and would have been able to incur an additional $124.6 million under our Revolver. Assuming we had completed this offering and the May 2009 issuance and sale of shares of our common stock at March 31, 2009 and on an as further adjusted basis for the application of the estimated net proceeds from the sale of the notes, we would have had $             million outstanding under our Revolver (excluding $0.3 million of letters of credit) and would have been able to incur an additional $             million under our Revolver.

At the current $450.0 million limit on our Revolver, and given our outstanding balance of $390.0 million at March 31, 2009, net of $0.3 million of letters of credit outstanding, we could borrow up to $59.7 million at March 31, 2009. As a result of the issuance of the notes in this offering, the borrowing base under our Revolver will be automatically reduced to $382.0 million, which is approximately 11% less than the current level of $450.0 million. Our Revolver, which matures in December 2010, is secured by a portion of our proved oil and gas reserves. Our 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. In the three months ended March 31, 2009 and in the year ended December 31, 2008, we incurred commitment fees of $0.1 million and $0.8 million on the unused portion of our Revolver. The commitments, which can be redetermined relative to our borrowing base, cannot be withdrawn by the bank. We capitalized $0.4 million and $2.0 million of interest cost incurred in the three months ended March 31, 2009 and in the year ended December 31, 2008. We have the option to elect interest at (i) LIBOR plus a margin ranging from 2.00% to 3.00%, 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 2.125%. The weighted average interest rate on borrowings outstanding under our Revolver at March 31, 2009 and at December 31, 2008 was approximately 3.89% and 2.57% (after giving effect to the Interest Rate Swaps). We do not have a public credit rating for our Revolver.

The financial covenants under our Revolver require us not to exceed specified ratios. We are required to maintain a Debt-to-EBITDAX ratio of no more than 3.5-to-1.0, and at March 31, 2009 such ratio was 1.7-to-1.0, as compared to 1.5-to-1.0 at December 31, 2008. We are also required to maintain an EBITDAX-to-interest expense ratio of no less than 2.5-to-1.0, and at March 31, 2009 such ratio was 16.2-to-1.0, as compared to 21.8-to-1.0 at December 31, 2008. EBITDAX, which is a non-GAAP measure, is generally defined in our Revolver as our net income before the effects of interest expense, interest income, income tax expense, depreciation, depletion and amortization, or DD&A, expense, impairments, other similar non-cash charges, exploration expense, non-cash compensation expense and non-cash hedging activity. For covenant calculation purposes, EBITDAX is further adjusted for distributions received through our ownership in PVG and for dividends paid to shareholders. In addition, the financial covenants impose dividend limitation restrictions. Our 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 March 31, 2009 and December 31, 2008, we were in compliance with all of our covenants under our Revolver. We intend to apply the net proceeds of this offering to repay a portion of the outstanding borrowings under our Revolver.

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In the event that we would be in default of our covenants, we could appeal to the banks for a waiver of the covenant default. Should the banks deny our appeal to waive the covenant default, the outstanding borrowings under our Revolver would become payable upon demand and would be reclassified to the current liabilities section of our consolidated balance sheet. Our Revolver contains cross-default provisions for default of indebtedness of more than $5.0 million. Our Revolver does not contain a subjective acceleration clause.

Convertible Notes, Note Hedges and Warrants.    As of March 31, 2009, we had $230.0 million (excluding the discount of $28.5 million) of Convertible Notes outstanding. The Convertible Notes bear interest at a coupon rate of 4.50% per year payable semiannually in arrears on May 15 and November 15 of each year. We do not have a public credit rating for the Convertible Notes.

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

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

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

In connection with the sale of the Convertible Notes, we entered into convertible note hedge transactions, or the Note Hedges, with respect to shares of our common stock with affiliates of certain of the underwriters of the Convertible Notes (collectively, the “Option Counterparties”).

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The Note Hedges cover, subject to anti-dilution adjustments, the net shares of our common stock that would be deliverable to converting noteholders in the event of a conversion of the Convertible Notes. In December 2007, we paid an aggregate amount of $18.6 million of the net proceeds from the sale of the Convertible Notes for the cost of the Note Hedges (after such cost was offset by the proceeds of the Warrants described below).

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

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

Interest Rate Swaps.    We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under our Revolver until December 2010. The notional amounts of the Interest Rate Swaps total $50.0 million, or approximately 13% of our total long-term debt outstanding under our Revolver at March 31, 2009. We will pay a weighted average fixed rate of 5.34% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the Interest Rate Swaps were recorded as interest expense. During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value and losses for the Interest Rate Swaps will be recognized as a component of derivatives in the income statement. After considering the applicable margins of 2.75% and 1.25% in effect as of March 31, 2009 and December 31, 2008, the total interest rate on the $50.0 million portion of Revolver borrowings covered by the Interest Rate Swaps was 8.09% at March 31, 2009 and 6.6% at December 31, 2008.

PVR Revolver.    In March 2009, PVR increased the size of the PVR Revolver from $700.0 million to $800.0 million, which resulted in $9.3 million of debt issuance costs. The PVR Revolver is secured with substantially all of PVR’s assets. As of March 31, 2009, net of outstanding borrowings of $595.1 million and letters of credit of $1.6 million, PVR had remaining borrowing capacity of $203.3 million on the 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 the three months ended March 31, 2009 and the year ended December 31, 2008, PVR incurred commitment fees of $0.1 million and $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 1.25% 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 1.75% to 2.75% if PVR selects the LIBOR-based borrowing option. The weighted average interest rate on

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borrowings outstanding under the PVR Revolver at March 31, 2009 and December 31, 2008 was approximately 3.75% and 4.39% (after giving effect to the PVR Interest Rate Swaps). 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. PVR is required to maintain a debt-to-consolidated EBITDA ratio of less than 5.25-to-1.0, and at March 31, 2009 such ratio was 3.37-to-1.0, as compared to 4.05-to-1.0 at December 31, 2008. PVR is also required to maintain a consolidated EBITDA-to-interest expense ratio of greater than 2.5-to-1.0, and at March 31, 2009, such ratio was 6.31-to-1.0, as compared to 4.74-to-1.0 at December 31, 2008. EBITDA, which is a non-GAAP measure, is generally defined in the PVR Revolver as PVR’s net income before the effects of interest expense, interest income, DD&A expense, impairments and other similar charges and non-cash hedging activity. 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 its subsidiaries. As of March 31, 2009 and December 31, 2008, PVR was in compliance with all of its covenants under the PVR Revolver.

In the event that PVR would be in default of its covenants, PVR could appeal to the banks for a waiver of the covenant default. Should the banks deny PVR’s appeal to waive the covenant default, the outstanding borrowings under the PVR Revolver would become payable upon demand and would be reclassified to the current liabilities section of our consolidated balance sheet. The PVR Revolver contains cross-default provisions for default of indebtedness of more than $7.5 million. The PVR Revolver does not contain a subjective acceleration clause. 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.

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%.

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. During the first quarter of 2009, PVR discontinued hedge accounting for all of the PVR Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the PVR Interest Rate Swaps are recognized in earnings currently. Until March 2010, the notional amounts of the PVR Interest Rate Swaps total $310.0 million, or approximately 52% of PVR’s total long-term debt outstanding as of March 31, 2009, with PVR paying a weighted average fixed rate of 3.54% 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 $250.0 million with PVR paying a weighted average fixed rate of 3.37% on the notional amount, and

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the counterparties paying a variable rate equal to the three-month LIBOR. From December 2011 to December 2012, the notional amounts of the Interest Rate Swaps total $100.0 million, with PVR paying a weighted average fixed rate of 2.09% 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 seven financial institution counterparties, with no counterparty having more than 24% of the open positions. After considering the applicable margin of 2.00% in effect as of March 31, 2009, the total interest rate on the $310.0 million portion of PVR Revolver borrowings covered by the PVR Interest Rate Swaps was 5.54% at March 31, 2009. After considering the applicable margin of 1.75% in effect as of December 31, 2008, the total interest rate on the $285.0 million portion of PVR Revolver borrowings covered by the PVR Interest Rate Swaps was 5.42% at December 31, 2008.

We and PVR monitor changes in our and its counterparties and are not aware of any specific concerns regarding our or PVR’s counterparties’ ability to make payments under any of the Interest Rate Swaps or PVR Interest Rate Swaps.

PVR unit offering

In 2008, PVR issued 5.15 million common units to the public representing limited partner interests and received $138.2 million in net proceeds. PVR received total contributions of $2.9 million from its general partner in order to maintain its 2% general partner interest in PVR. The net proceeds were used to repay a portion of PVR’s borrowings under the PVR Revolver.

Future capital needs and commitments

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

For the remainder of 2009, we anticipate making oil and gas segment capital expenditures of approximately $45.0 million to $55.0 million. In addition to our capital expenditures and the $9.9 million we included in exploration expense in the three months ended March 31, 2009, we could incur up to $14.4 million of additional cost for rig delay and standby charges, which would also be recorded as exploration expense as incurred. These capital and other rig delay-related expenditures are expected to be primarily funded from internally generated sources of cash, including cash distributions received from PVG and PVR, supplemented by Revolver borrowings as needed. At March 31, 2009, we had $59.7 million of borrowing capacity under our Revolver. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on industry conditions, cash flows provided by operating activities and the availability of capital. We believe our cash flow from operating activities and sources of debt financing are sufficient to fund our 2009 planned oil and gas capital expenditure program.

For future periods, we continue to assess funding needs for our growth opportunities in the context of our presently available debt capacity. We expect to use a combination of cash flows from operating activities, borrowings under our Revolver, issuances of additional debt and equity

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securities and sale of non-core assets to fund our growth. However, if the current disruptions in the worldwide credit, capital and commodities markets continue into the future, our ability to grow will likely remain limited. We cannot be certain that we will be able to issue our debt or equity securities on terms or in the amounts that we anticipate, or at all, and we may be unable to refinance our Revolver when it expires in 2010. In addition, we may be unable to obtain adequate funding under our Revolver because our lending counterparties may be unwilling or unable to meet their funding obligations. We believe our portfolio of assets provides us with opportunities for organic growth which could require capital in excess of our internal sources. We expect to rely less on our Revolver to fund our capital needs, replaced by other sources of debt and equity capital and non-core asset sales as needed.

Currently, PVG has no capital requirements. In the future, we may decide to facilitate PVR acquisitions and other capital expenditures by the issuance of PVG debt or equity if market conditions are favorable to such an issuance.

PVR believes that its short-term cash requirements for operating expenses and quarterly distributions to PVG, as the owner of PVR’s general partner, and unitholders will be funded through operating cash flows. PVR also believes that its remaining borrowing capacity of $203.3 million will be sufficient for its capital needs and commitments for the remainder of 2009. For the remainder of 2009, PVR anticipates making capital expenditures, excluding acquisitions, of approximately $47.0 to $53.0 million. The majority of the 2009 capital expenditures are expected to be incurred in the PVR natural gas midstream segment. Long-term cash requirements for acquisitions and other capital expenditures are expected to be funded by several sources, including cash flows from operating activities, borrowings under the PVR Revolver and the issuances of additional debt and equity securities if available under commercially acceptable terms.

Part of PVR’s long-term strategy is to increase cash available for distribution to PVR’s unitholders by making acquisitions and other capital expenditures. PVR’s ability to make these acquisitions and other capital expenditures in the future will depend largely on the availability of debt financing and on PVR’s ability to periodically use equity financing through the issuance of new common units. Future financing will depend on various factors, including prevailing market conditions, interest rates and PVR’s financial condition and credit rating.

The current disruptions in the global financial and commodities markets and the general economic climate have made access to equity and debt capital markets very difficult since late in 2008. While signs of improvement in these markets have started to arise in 2009, with issuances of debt and equity securities by other publicly traded partnerships, the short-term outlook remains uncertain with respect to PVR’s ability to access the capital markets on acceptable terms. If the situation worsens and PVR is unable to access the capital markets for an extended period, PVR’s ability to make acquisitions and other capital expenditures, as well as PVR’s ability to increase or sustain cash distributions to its limited partners and to PVG, the owner of PVR’s general partner, will likely become limited. If additional financing is required, there are no assurances that it will be available, or if available, that it can be obtained on terms favorable to PVR or not dilutive to PVR’s future earnings.

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Contractual obligations

The following table summarizes our and PVR’s contractual obligations as of December 31, 2008:

	Payments due by period
($ in thousands)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Revolver	$	332,000	$	—	$	332,000	$	—	$	—
Convertible Notes		230,000		—		—		230,000		—
PVR Revolver		568,100		—		568,100		—		—
Asset retirement obligations(1)		8,589		—		—		369		8,220
Derivatives(2)		24,255		15,534		8,721		—		—
Interest expense(3)		114,217		37,426		66,441		10,350		—
Unrecognized tax benefits(4)		4,600		1,800		—		—		2,800
Natural gas midstream activities(5)		36,793		13,069		11,862		8,541		3,321
Rental commitments(6)		34,578		12,009		9,639		4,339		8,591
Oil and gas activities(7)		84,802		32,825		28,761		5,538		17,678
Total contractual obligations(8)	$	1,437,934	$	112,663	$	1,025,524	$	259,137	$	40,610

(1) The asset retirement obligations reflect the discounted balance, which is recorded in the other liabilities section of our consolidated balance sheets. See note 16 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement. The undiscounted balance was $52.2 million at December 31, 2008.

(2) The derivatives commitments represent the estimated payments we and PVR will make resulting from the oil and gas and natural gas midstream commodity derivatives as well as both from both our and PVR’s Interest Rate Swaps. See “—Liquidity and capital resources—Long-term debt—Interest Rate Swaps” and “—Quantitative and qualitative disclosures about market risk—Price risk” for a detailed description of our and PVR’s derivatives and Interest Rate Swaps.

(3) The interest expense commitments represent the estimated interest payments that will be due under our Revolver, the PVR Revolver and the Convertible Notes. See “—Liquidity and capital resources—Long-term debt” for a detailed description of these debt instruments and the factors affecting our and PVR’s interest expense calculations.

(4) See note 19 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a further description of this liability and the factors underlying the calculation of this expense.

(5) Commitments for PVR natural gas midstream activities relate to firm transportation agreements. As of December 31, 2008, PVR’s firm transportation capacity rights for specified volumes per day on a pipeline system had 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.

(6) 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 cannot be estimated with certainty; however, based on current knowledge and historical trends, PVR believes that it will incur between approximately $0.9 million and $1.0 million in rental commitments annually until the reserves have been exhausted.

(7) Commitments for oil and gas activities relate to firm transportation agreements and drilling contracts. 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. We also have agreements to purchase oil and gas well drilling services from third parties with terms that ranged from two to three years.

(8) Total contractual obligations do not include anticipated 2009 capital expenditures, excluding acquisitions, of approximately $130.0 to $140.0 million for the oil and gas segment and $72.0 million for PVR.

Part of the purchase price for the PVR Lone Star acquisition includes contingent payments of approximately $55.0 million. These contingency payments will be made by PVR if certain revenue targets are met before June 30, 2013. Because the outcome of these contingent payments is not determinable beyond a reasonable doubt, PVR did not accrue these contingent payments as a liability during the year ended December 31, 2008. Rather, once the revenue targets are met, the contingent payments will be recorded as an additional cost of Lone Star.

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Off-balance sheet arrangements

As of March 31, 2009 and December 31, 2008, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We are, therefore, not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships.

Results of operations

Selected financial data—consolidated

The following table sets forth a summary of certain consolidated financial data for the three months ended March 31, 2009 and 2008:

	Three months ended March 31,
($ in thousands, except per share data)	2009		2008
Revenues	$199,160		$249,135
Expenses	206,599		189,002
Operating income (loss)	$   (7,439	)	$  60,133
Net income (loss)	$   (7,209	)	$    3,194
Earnings (loss) per share, basic	$     (0.17	)	$      0.08
Earnings (loss) per share, diluted	$     (0.17	)	$      0.07
Cash flows provided by operating activities	$103,109		$  66,152

Operating income (loss) decreased by $67.6 million in the three months ended March 31, 2009 compared to the same period of 2008 primarily due to a $27.7 million decrease in natural gas revenues, an $18.5 million increase in DD&A expense and a $16.6 million increase in exploration expense. These changes were partially offset by a $6.7 million increase in coal royalties revenues.

Net income (loss) decreased by $10.4 million in the three months ended March 31, 2009 compared to the same period of 2008 primarily due to the decrease in operating income (loss), partially offset by a $36.2 million increase in derivative income.

The assets, liabilities and earnings of PVG are fully consolidated in our financial statements, with the public unitholders’ interest (23% as of March 31, 2009) reflected as a minority interest in our consolidated financial statements. The assets, liabilities and earnings of PVR are fully consolidated in PVG’s financial statements, with the interest that PVG does not own (61%, after the effect of IDRs, as of March 31, 2009) reflected as a minority interest in PVG’s consolidated financial statements.

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The following table sets forth a summary of certain consolidated financial data for the years ended December 31, 2008, 2007 and 2006:

	Year ended December 31,
($ in thousands)	2008		2007		2006
Revenues	$	1,220,851	$	852,950	$	753,929
Expenses		964,028		660,326		583,397
Operating income	$	256,823	$	192,624	$	170,532
Net income	$	124,168	$	50,754	$	75,909
Earnings per share, basic	$	2.97	$	1.33	$	2.03
Earnings per share, diluted	$	2.95	$	1.32	$	2.01
Cash flows provided by operating activities	$	383,774	$	313,030	$	275,819

Operating income increased in 2008 compared to 2007 primarily due to a $106.6 million increase in natural gas revenues, a $28.7 million increase in coal royalties and a $15.3 million increase in gross margin, partially offset by a $62.7 million increase in DD&A expenses and $51.8 million of impairments recorded in 2008. Operating income increased in 2007 compared to 2006 primarily due to a $49.3 million increase in natural gas revenues, a $21.8 million increase in natural gas midstream gross margin and $12.4 million in net gains on the sales of properties in 2007, partially offset by a $35.3 million increase in DD&A expense, a $17.4 million increase in general and administrative expenses and a $20.2 million increase in operating expenses.

Net income increased in 2008 compared to 2007 primarily due to the increase in operating income and a $93.9 million increase in derivatives income resulting from changes in the valuation of unrealized derivative positions, partially offset by the corresponding increase in income tax expense. Net income decreased in 2007 compared to 2006 primarily due to a $66.8 million increase in derivative losses and a $12.6 million increase in interest expense, partially offset by the increase in operating income and the corresponding decrease in income tax expense.

The assets, liabilities and earnings of PVG are fully consolidated in our financial statements, with the public unitholders’ interest (23% as of December 31, 2008) reflected as a minority interest in our consolidated financial statements. The assets, liabilities and earnings of PVR are fully consolidated in PVG’s financial statements, with the interest that PVG does not own (61%, after the effect of incentive distribution rights, as of December 31, 2008) reflected as a minority interest in PVG’s consolidated financial statements.

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Oil and gas segment

Three months ended March 31, 2009 compared with three months ended March 31, 2008

The following table sets forth a summary of certain financial and other data for our oil and gas segment and the percentage change for the three months ended March 31, 2009 and 2008:

	Three months ended March 31,				Three months ended March 31,
	2009		2008	% Change	2009		2008
	($ in thousands, except as noted)				(per Mcfe)(1)
Financial Highlights
Revenues
Natural gas	$ 52,821		$80,513	(34)%	$ 4.48		$  8.26
Crude oil	6,328		9,215	(31)%	37.01		97.00
NGL	3,370		1,868	80%	22.93		54.94
Other income	2,046		703	191%
Total revenues	$ 64,565		$92,299	(30)%	$ 4.71		$  8.77
Expenses
Operating	$ 14,763		$14,209	4%	$ 1.08		$  1.35
Taxes other than income	4,826		5,858	(18)%	0.35		0.56
General and administrative	5,124		4,584	12%	0.37		0.44
Production costs	$ 24,713		$24,651	0%	$ 1.80		$  2.34
Exploration	21,312		4,680	355%	1.55		0.44
Impairments	1,196		—	—	0.09		—
Depreciation, depletion and amortization	39,999		26,616	50%	2.92		2.53
Total expenses	$ 87,220		$55,947	56%	$ 6.36		$  5.32
Operating income	$(22,655	)	$36,352	(162)%	$(1.65	)	$  3.45
Production
Natural gas (MMcf)	11,802		9,748	21%
Crude oil (MBbl)	171		95	80%
NGL (MBbl)	147		34	332%
Total production (MMcfe)	13,710		10,522	30%

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

Production.    Approximately 86% and 93% of production in the three months ended March 31, 2009 and 2008 was natural gas. Total production increased by 3.2 Bcfe, or 30%, from 10.5 Bcfe in the three months ended March 31, 2008 to 13.7 Bcfe in the same period of 2009, primarily due to increased production in the East Texas, Mid-Continent, Mississippi and Gulf Coast regions.

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The following table summarizes total natural gas, crude oil and NGL production and total natural gas, crude oil and NGL revenues by region for the three months ended March 31, 2009 and 2008:

	Natural gas, oil and NGL production		Natural gas, oil and NGL revenues
	Three months ended March 31,		Three months ended March 31,
Region	2009	2008	2009	2008
	(MMcfe)		($ in thousands)
East Texas	3,676	2,757	$15,919	$25,525
Appalachia	3,899	2,840	15,000	22,962
Mid-Continent	3,856	1,462	9,945	11,784
Mississippi	2,094	1,806	10,470	15,282
Gulf Coast	2,185	1,657	11,185	16,043
Total	13,710	10,522	$62,519	$91,596

The increased production in the East Texas region is primarily due to aggressive drilling and development in the region, as well as contributions from natural gas production in the horizontal Lower Bossier (Haynesville) Shale play. The increase in production in the Mid-Continent region is primarily due to the natural gas production increases from additional drilling in the Granite Wash play in Oklahoma. The increase in production in the Mississippi and Gulf Coast regions is primarily due to new production from wells drilled in the past year.

Revenues.    Natural gas revenues decreased by $27.7 million, or 34%, from $80.5 million in the three months ended March 31, 2008 to $52.8 million in the same period of 2009. Of the $27.7 million decrease, $44.7 million was the result of decreased realized prices for natural gas, partially offset by $17.0 million resulting from increased natural gas production from drilling. Our average realized price received for natural gas decreased by $3.78 per Mcf, or 46%, from $8.26 per Mcf in the three months ended March 31, 2008 to $4.48 per Mcf in the three months ended March 31, 2009.

Crude oil revenues decreased by $2.9 million, or 31%, from $9.2 million in the three months ended March 31, 2008 to $6.3 million in the same period of 2009. Of the $2.9 million decrease, $10.3 million was the result of decreased crude oil prices, partially offset by $7.4 million resulting from increased crude oil production from drilling. Our average realized price received for crude oil decreased by $59.99 per Bbl, or 62%, from $97.00 per Bbl in the three months ended March 31, 2008 to $37.01 per Bbl in the same period of 2009.

NGL revenues increased by $1.5 million, or 80%, from $1.9 million in the three months ended March 31, 2008 to $3.4 million in the same period of 2009. Of the $1.5 million increase, $6.2 million was the result of increased NGL production, primarily due to a new processing plant in the East Texas region, partially offset by $4.7 million resulting from decreased realized prices for NGLs. Our average realized price received for NGLs decreased by $32.01 per Bbl, or 58%, from $54.94 per Bbl in the three months ended March 31, 2008 to $22.93 per Bbl in the same period of 2009.

Effects of derivatives.    Our natural gas and crude oil revenues may change significantly from period to period as a result of changes in commodity prices or production volumes. As part of our risk management strategy, we use derivative financial instruments to hedge natural gas and, to a lesser extent, oil prices.

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Because we do not apply hedge accounting to our commodity derivatives or Interest Rate Swaps, we record realized and mark-to-market gains and losses in the derivatives line of our consolidated statements of income rather than deferring such amounts in accumulated other comprehensive income. See note 6 in the notes to our unaudited consolidated financial statements included elsewhere in this prospectus supplement for a tabular schedule of the effects of derivatives on our consolidated statements of income for the three months ended March 31, 2009 and 2008.

For the derivatives related to the oil and gas segment, we received $16.3 million and $0.6 million in cash settlements in the three months ended March 31, 2009 and 2008. The following table reconciles natural gas and crude oil revenues to realized prices, as adjusted for derivative activities in the three months ended March 31, 2009 and 2008:

	Three months ended March 31,
	2009	2008	2009	2008
	($ in thousands)		(per Mcf)
Natural gas revenues, before impact of derivatives	$52,821	$80,513	$4.48	$8.26
Cash settlements on natural gas derivatives(1)	14,962	569	1.27	0.06
Natural gas revenues, adjusted for derivatives	$67,783	$81,082	$5.75	$8.32

	Three months ended March 31,
	2009	2008	2009	2008
	($ in thousands)		(per Bbl)
Crude oil revenues before impact of derivatives	$6,328	$9,215	$37.01	$  97.00
Cash settlements on crude oil derivatives(1)	1,350	—	7.89	—
Crude oil revenues, adjusted for derivatives	$7,678	$9,215	$44.90	$979.00

(1) As a result of the original forecasted transactions settling, we mark-to-market our derivative positions and record the gains or losses on the derivatives line of our consolidated statements of income. These cash settlements relate to those derivative gains or losses.

Other income.    Other income increased by $1.3 million, or 191%, from $0.7 million in the three months ended March 31, 2008 to $2.0 million in the same period of 2009, primarily due to a royalty recovery from a lessee in the Appalachia region.

Expenses.    Aggregate operating costs and expenses increased primarily due to increased operating, general and administrative, exploration and DD&A expenses. We also incurred impairment charges of $1.2 million in the three months ended March 31, 2009.

Operating expenses increased by $0.6 million, or 4%, from $14.2 million, or $1.35 per Mcfe, in the three months ended March 31, 2008 to $14.8 million, or $1.08 per Mcfe, in the same period of 2009. This increase is due primarily to increased compressor rentals and increased processing fees, both of which were driven by the increase in production and general growth in infrastructure.

Taxes other than income decreased by $1.1 million, or 18%, from $5.9 million in the three months ended March 31, 2008 to $4.8 million in the same period of 2009, primarily due to decreased severance taxes paid resulting from decreased natural gas, crude oil and NGL prices.

General and administrative expenses increased by $0.5 million, or 12%, from $4.6 million in the three months ended March 31, 2008 to $5.1 million in the same period of 2009, primarily due to increased staffing costs in the East Texas and Mid-Continent regions.

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Exploration expenses in the three months ended March 31, 2009 and 2008 consisted of the following:

	Three months ended March 31,
($ in thousands)	2009	2008
Dry hole costs	$  1,689	$   718
Geological and geophysical	738	680
Unproved leasehold	8,702	2,834
Other	319	448
Standby rig charges	9,864	—
Total	$21,312	$4,680

Exploration expenses increased by $16.6 million, or 355%, from $4.7 million in the three months ended March 31, 2008 to $21.3 million in the same period of 2009. Dry hole costs increased by $1.0 million, or 135%, from $0.7 million in the three months ended March 31, 2008 to $1.7 million in the same period of 2009. This increase was due to the write-off of one well in the Woodford Shale play in the Mid-Continent region. Unproved leasehold expenses increased by $5.9 million, or 207%, from $2.8 million in the three months ended March 31, 2008 to $8.7 million in the same period of 2009. This increase was primarily due to increased amortization of unproved properties located in the East Texas and Mid-Continent regions.

Costs related to unproved properties are capitalized and periodically evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management. We continue to experience an increase in lease expirations and unproved leasehold expense caused by current economic conditions which have impacted our future drilling plans thereby increasing the amount of expected lease expirations. Effective January 1, 2009, we changed our accounting process to amortize additional insignificant unproved properties over the average estimated life of the leases versus amortizing some leases and assessing other leases on an occurrence basis. As a result of amortizing additional leases, we recorded additional unproved leasehold expense, which is included in exploration expense on the consolidated statements of income, of $6.3 million in the three months ended March 31, 2009. The impact of this change on net income in the three months ended March 31, 2009 was a decrease of $3.9 million, net of income taxes. The impact of this change decreased basic and diluted earnings per share in the three months ended March 31, 2009 by $0.09.

In the first quarter of 2009, our oil and gas segment opted to defer drilling of many wells due to unfavorable economic conditions. As a result, we amended certain drilling rig contracts to delay commencement of drilling until January 2010. In the three months ended March 31, 2009, we incurred a liability of approximately $9.9 million for lump sum delay fees, minimum daily standby fees and demobilization fees expected to be paid during the standby period. These fees and costs are recorded in accounts payable and accrued liabilities on the consolidated balance sheets and as exploration expense on the consolidated statements of income. We will continue to evaluate economic conditions through the remainder of 2009 to determine whether or not to defer additional drilling. This could result in additional exploration expenses of up to approximately $14.8 million for 2009.

We recorded impairment charges related to our oil and gas segment properties of $1.2 million. These charges were primarily related to market declines in the spot and future oil and gas prices.

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DD&A expenses increased by $14.4 million, or 50%, from $26.6 million in the three months ended March 31, 2008 to $40.0 million in the same period of 2009, primarily due to the 30% increase in equivalent production and higher depletion rates in 2009 when compared to 2008. Our average depletion rate increased by $0.39 per Mcfe, or 15%, from $2.53 per Mcfe in the three months ended March 31, 2008 to $2.92 per Mcfe in the three months ended March 31, 2009 primarily due to increased development costs and the sale of and reduced contributions from properties with lower depletion rates.

Year ended December 31, 2008 compared with year ended December 31, 2007

The following table sets forth a summary of certain financial and other data for our oil and gas segment and the percentage change for the years ended December 31, 2008 and 2007:

	Year ended December 31,		% Change	Year ended December 31,
	2008	2007		2008	2007
	($ in thousands, except as noted)			(per Mcfe)(1)
Revenues
Natural gas	$368,801	$262,169	41%	$  8.89	$  6.94
Crude oil	46,529	22,439	107%	91.95	69.04
NGL	21,292	5,678	275%	54.32	41.75
Gain on the sale of property and equipment	30,634	12,235	150%
Other income	2,074	720	188%
Total revenues	$469,330	$303,241	55%	$10.01	$  7.47
Expenses
Operating	$  59,459	$  46,713	27%	$  1.27	$  1.15
Taxes other than income	23,336	17,847	31%	0.50	0.44
General and administrative	21,284	16,281	31%	0.45	0.40
Production costs	$104,079	$  80,841	29%	$  2.22	$  1.99
Exploration	42,436	28,608	48%	0.91	0.71
Impairments	19,963	2,586	672%	0.43	0.06
Depreciation, depletion and amortization	132,276	87,223	52%	2.82	2.15
Total expenses	$298,754	$199,258	50%	$  6.37	$  4.91
Operating income	$170,576	$103,983	64%	$  3.64	$  2.56
Production
Natural gas (MMcf)	41,493	37,802	10%
Crude oil (MBbl)	506	325	56%
NGL (MBbl)	392	136	188%
Total production (MMcfe)	46,881	40,569	16%

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

Production.    Approximately 89% and 93% of production in the years ended December 31, 2008 and 2007 was natural gas. Total production increased by 6.3 Bcfe, or 16%, from 40.6 Bcfe in 2007 to 46.9 Bcfe in the same period of 2008, primarily due to increased production in the East Texas and Mid-Continent regions, partially offset by decreased production in the Appalachian, Mississippi and Gulf Coast regions.

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In 2008, we drilled a successful horizontal Lower Bossier (Haynesville) Shale well in Harrison County, Texas. Based on this successful horizontal test, we had four rigs drilling horizontal Lower Bossier (Haynesville) Shale wells as of December 31, 2008.

The following table summarizes total natural gas, crude oil and NGL production and total natural gas, crude oil and NGL revenues by region for the years ended December 31, 2008 and 2007:

	Natural gas, crude oil and NGL production		Natural gas, crude oil and NGL revenues
			Year ended December 31,
Region	2008	2007	2008	2007
	(MMcfe)		($ in thousands)
East Texas	13,409	7,986	$129,105	$59,333
Appalachia	11,497	12,426	107,282	86,936
Mid-Continent	7,646	4,129	59,969	24,980
Mississippi	7,340	7,551	69,916	53,737
Gulf Coast	6,989	8,477	70,350	65,300
Total	46,881	40,569	$436,622	$290,286

In 2008, we drilled a total of 285 gross (179.6 net) wells, including 274 gross (172.3 net) development wells and 12 gross (7.3 net) exploratory wells. All wells were successful except (i) 15 gross (11.8 net) development wells, including 11 gross (8.8 net) development wells under evaluation at December 31, 2008 and (ii) 6 gross (3.8 net) exploratory wells, including one exploratory well under evaluation at December 31, 2008.

In 2007, we drilled a total of 289 gross (213.0 net) wells, including 271 gross (203.6 net) development wells and 18 gross (9.4 net) exploratory wells. All wells were successful except six gross (5.1 net) development wells and seven gross (4.2 net) exploratory wells, including four (2.6 net) wells under evaluation at December 31, 2007.

The increased production in the East Texas region is due primarily to aggressive drilling and additional processing for sales points which were previously sold as wet gas, but are now processed through PVR’s Crossroads plant, which was placed into service in April 2008.

The decrease in the Appalachian region is due primarily to the sale of oil and gas royalty interests to PVR in October 2007. Production in the Mississippi region was relatively constant from 2007 to 2008.

The increase in production in the Mid-Continent region is due primarily to higher CBM production and high production wells in the Granite Wash and Woodford Shale areas.

The decrease in production in the Gulf Coast region is due primarily to decreased natural gas production resulting from depletion of certain prospects within that region. In addition, the Gulf Coast region, particularly the Bayou Postillion area, experienced disruptions in production due to inclement weather.

Revenues.    Natural gas revenues increased by $106.6 million, or 41%, from $262.2 million in 2007 to $368.8 million in 2008. Of the $106.6 million increase, $81.0 million was the result of increased realized prices for natural gas and $25.6 million was the result of increased natural gas production from drilling. Our average realized price received for natural gas increased by $1.95 per Mcf, or 28%, from $6.94 per Mcf in 2007 to $8.89 per Mcf in 2008.

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Crude oil revenues increased by $24.1 million, or 107%, from $22.4 million in 2007 to $46.5 million in 2008. Of the $24.1 million increase, $12.5 million was the result of increased crude oil production and $11.6 million was the result of higher realized prices for crude oil. Our average realized price received for crude oil increased by $22.91 per Bbl, or 33%, from $69.04 per Bbl in 2007 to $91.95 per Bbl in 2008.

NGL revenues increased by $15.6 million, or 275%, from $5.7 million in 2007 to $21.3 million in 2008. Of the $15.6 million increase, $10.7 million was the result of increased NGL production and $4.9 million was the result of higher realized prices for NGLs. Our average realized price received for NGLs increased by $12.57 per Bbl, or 30%, from $41.75 per Bbl in 2007 to $54.32 per Bbl in 2008.

Effects of derivatives.    Our natural gas and crude oil revenues may change significantly from period to period as a result of changes in commodity prices or production volumes. As part of our risk management strategy, we use derivative financial instruments to hedge natural gas and, to a lesser extent, oil prices.

In 2006, we discontinued hedge accounting prospectively for our remaining and future commodity derivatives. Consequently, we began recognizing realized and mark-to-market gains and losses in the derivatives line of our consolidated statements of income rather than deferring such amounts in accumulated other comprehensive income. See note 8 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a tabular schedule of the effects of derivatives on our consolidated statements of income for the years ended December 31, 2008 and 2007.

For the derivatives related to the oil and gas segment, we paid $7.6 million in cash settlements in 2008 and we received cash settlements of $14.1 million in cash settlements in 2007. The following table reconciles natural gas and crude oil revenues to realized prices, as adjusted for derivative activities for the years ended December 31, 2008 and 2007:

	Year ended December 31,
	2008		2007		2008		2007
	($ in thousands)				(per Mcf)
Natural gas revenues, as reported	$368,801		$262,169		$  8.89		$  6.94
Derivatives gains included in natural gas revenues(1)	—		(222	)	—		(0.01	)
Natural gas revenues before impact of derivatives	$368,801		$261,947		$  8.89		$  6.93
Cash settlements on natural gas derivatives(2)	(7,339	)	14,863		(0.18	)	0.39
Natural gas revenues, adjusted for derivatives	$361,462		$276,810		$  8.71		$  7.32
	($ in thousands)				(per Bbl)
Crude oil revenues, as reported	$  46,529		$  22,439		$91.95		$69.04
Derivatives losses included in crude oil revenues(1)	—		502		—		1.54
Crude oil revenues before impact of derivatives	$  46,529		$  22,941		$91.95		$70.58
Cash settlements on crude oil derivatives(2)	(281	)	(735	)	(0.55	)	(2.26	)
Crude oil revenues, adjusted for derivatives	$  46,248		$  22,206		$91.40		$68.32

(1) As a result of the original forecasted transactions settling, we reclassified the remaining amounts in accumulated other comprehensive income to earnings in 2007. As a result, in 2008, no derivatives gains or losses were reported as part of natural gas, crude oil and NGL revenues.

(2) As a result of the original forecasted transactions settling, we mark-to-market our derivative positions and record the gains or losses on the derivatives line of our consolidated statements of income. These cash settlements relate to those derivative gains or losses. Had we not elected to discontinue hedge accounting for our commodity derivatives in 2006, these cash settlements would have been recognized in the natural gas and crude oil revenues lines on our consolidated statements of income.

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Gain on sale of property and equipment.    In 2008, we recognized $30.6 million of gains on the sales of property and equipment, primarily related to the sale of all of our working interest in unproved properties in Louisiana. In 2007, we recognized $12.2 million of net gains on sales of property and equipment primarily related to the September 2007 sale of non-operated working interests in oil and gas properties.

Other income.    Other income increased by $1.4 million, or 188% from $0.7 million in 2007 to $2.1 million in 2008, primarily due to increased gathering revenues in the East Texas region resulting from increased production in that region and an overall increase in gathering fees per Mcf that we charged.

Expenses.    Aggregate operating costs and expenses increased by $99.5 million, or 50%, from $199.3 million in 2007 to $298.8 million in 2008, primarily due to increased operating expenses, taxes other than income, general and administrative, exploration expenses, $20.0 million of impairment expenses in 2008 and increased DD&A expenses.

Operating expenses increased by $12.8 million, or 27%, from $46.7 million, or $1.15 per Mcfe, in 2007 to $59.5 million, or $1.27 per Mcfe, in 2008. This increase is due primarily to increased compressor rentals in East Texas and in the Mid-Continent region related to increased production and capital expenditures in those regions; increased repairs and maintenance expenses in the Mississippi, Mid-Continent and East Texas regions; and new processing fees related to the Crossroads plant, which began operations in the second quarter of 2008.

Taxes other than income increased by $5.5 million, or 31%, from $17.8 million in 2007 to $23.3 million in 2008, primarily due to an increase in severance and ad valorem taxes related to higher commodity prices and increased production.

General and administrative expenses increased by $5.0 million, or 31%, from $16.3 million in 2007 to $21.3 million in 2008, primarily due to increased staffing costs in the East Texas and Mid-Continent regions.

Exploration expenses in the years ended December 31, 2008 and 2007 consisted of the following:

	Year ended December 31,
($ in thousands)	2008	2007
Dry hole costs	$14,435	$11,689
Geological and geophysical	4,171	2,769
Unproved leasehold	21,412	13,036
Other	2,418	1,114
Total	$42,436	$28,608

Exploration expenses increased by $13.8 million, or 48%, from $28.6 million in 2007 to $42.4 million in 2008. In 2008, the dry hole costs were primarily due to the write-off of six wells in the Appalachian region, which were non-economic. In 2007, the dry hole costs were primarily due to the write-off of three exploratory wells in the Gulf Coast region and one exploratory well in the East Texas region in 2007. Geological and geophysical expenses increased due to seismic expenses incurred primarily in East Texas and South Louisiana, which was driven by increased growth of drilling prospects. Unproved leasehold expenses increased primarily due to the abandonment of property in the Mid-Continent and Appalachian regions. Other expenses increased due to increased delay rentals in the Gulf Coast region primarily related to lease renewals on certain prospects.

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We recorded $20.0 million of impairment charges in 2008 related to declines in spot and future oil and gas prices which reduced the estimated reserve bases of fields on certain properties in the Mid-Continent and Appalachian regions. These changes in reserve estimates in 2008 were primarily due to a decrease in fourth quarter oil and gas prices and a decline in well performance. We recorded $2.6 million of impairment charges in 2007 related to changes in estimates of the reserve bases of fields on certain properties in the Gulf Coast and Mid-Continent regions. These changes in reserve estimates were primarily due to declines in well performance.

DD&A expenses increased by $45.1 million, or 52%, from $87.2 million in 2007 to $132.3 million in the same period of 2008, primarily due to the increase in equivalent production and higher depletion rates. Our average depletion rate increased by $0.67 per Mcfe, or 31%, from $2.15 per Mcfe in 2007 to $2.82 per Mcfe in 2008 due to increased drilling costs in the East Texas and Mid-Continent regions and revisions in reserve estimates. The higher drilling costs were due primarily to increased rig day rates and increased steel costs.

Year ended December 31, 2007 compared with year ended December 31, 2006

The following table sets forth a summary of certain financial and other data for our oil and gas segment and the percentage change for the years ended December 31, 2007 and 2006:

	Year ended December 31,			% Change	Year ended December 31,
	2007	2006			2007	2006
	($ in thousands, except as noted)				(per Mcfe)(1)
Revenues
Natural gas	$262,169	$212,919		23%	$  6.94	$  7.35
Crude oil	22,439	17,634		27%	69.04	61.23
NGL	5,678	3,603		58%	41.75	38.33
Gain on the sale of property and equipment	12,235	(234	)	5329%
Other income	720	2,034		(65)%
Total revenues	$303,241	$235,956		29%	$  7.47	$  7.55
Expenses
Operating	$  46,713	$  27,403		70%	$  1.15	$  0.88
Taxes other than income	17,847	11,810		51%	0.44	0.38
General and administrative	16,281	12,826		27%	0.40	0.41
Production costs	80,841	52,039		55%	1.99	1.67
Exploration	28,608	34,330		(17)%	0.71	1.10
Impairments	2,586	8,517		(70)%	0.06	0.27
Depreciation, depletion and amortization	87,223	56,237		55%	2.15	1.80
Total expenses	$199,258	$151,123		32%	$  4.91	$  4.84
Operating income	$103,983	$  84,833		23%	$  2.56	$  2.71
Production
Natural gas (MMcf)	37,802	28,968		30%
Crude oil (MBbl)	325	288		13%
NGL (MBbl)	136	94		45%
Total production (MMcfe)	40,569	31,260		30%

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

Production.    Approximately 93% of production in 2007 and 2006 was natural gas. Total production increased by 9.3 Bcfe, or 30%, from 31.3 Bcfe in 2006 to 40.6 Bcfe in 2007 primarily due to increased production in the East Texas, Mid-Continent, Mississippi and Gulf Coast regions, partially offset by decreased production in the Appalachian region.

The following table summarizes total natural gas, crude oil and NGL production and total natural gas, crude oil and NGL revenues by region for the years ended December 31, 2007 and 2006:

	Natural gas, crude oil and NGL production		Natural gas, crude oil and NGL revenues
	Year ended December 31,		Year ended December 31,
Region	2007	2006	2007	2006
	(MMcfe)		($ in thousands)
East Texas	7,986	4,546	$59,333	$33,656
Appalachia	12,426	12,759	86,936	7,420
Mid-Continent	4,129	1,248	24,980	96,683
Mississippi	7,551	6,411	53,737	47,801
Gulf Coast	8,477	6,296	65,300	45,596
Total	40,569	31,260	$290,286	$234,156

We drilled a total of 289 gross (213.0 net) wells during 2007, including 271 gross (203.6 net) development wells and 18 gross (9.4 net) exploratory wells. All wells were successful except six gross (5.1 net) development wells and seven gross (4.2 net) exploratory wells, with four (2.6 net) wells under evaluation as of December 31, 2007.

The increased production in the East Texas region was due primarily to aggressive drilling and development in the region, as well as contributions from acquisitions in the region in 2007. The increase in production in the Mid-Continent region is due primarily to the development program in this region and due to contributions resulting from an acquisition in the Arkoma Basin. Production in the Appalachian region remained relatively constant from 2006 to 2007. The increase in production in the Mississippi region is due primarily to the development program in this region, which included contributions from two wells that were drilled horizontally in late 2006 and early 2007, as well as contributions from two acquisitions in the Gwinville Field. The increase in production in the Gulf Coast region is due primarily to exploration successes in South Louisiana.

Revenues.    Natural gas revenues increased by $49.3 million, or 23%, from $212.9 million in 2006 to $262.2 million in 2007. Of the $49.3 million increase, $64.9 million was the result of increased natural gas production, partially offset by a $15.6 million decrease resulting from lower realized prices for natural gas. Our average realized price received for natural gas decreased by $0.41 per Mcf, or 6%, from $7.35 per Mcf in 2006 to $6.94 per Mcf in 2007.

Crude oil revenues increased by $4.8 million, or 27%, from $17.6 million in 2006 to $22.4 million in 2007. Of the $4.8 million increase, $2.5 million was the result of higher realized prices for crude oil and $2.3 million was the result of increased crude oil production. Our average realized price received for crude oil increased by $7.81 per Bbl, or 13%, from $61.23 per Bbl in 2006 to $69.04 per Bbl in 2007.

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NGL revenues increased by $2.1 million, or 58%, from $3.6 million in 2006 to $5.7 million in 2007. Of the $2.1 million increase, $1.6 million was the result of increased NGL production and $0.5 million was the result of higher realized prices for NGLs. Our average realized price received for NGLs increased by $3.42 per Bbl, or 9%, from $38.33 per Bbl to $41.75 per Bbl in 2007.

Effects of derivatives.    For the derivatives related to the oil and gas segment, we received cash settlements of $14.1 million and $10.5 million in 2007 and 2006. The following table reconciles natural gas and crude oil revenues to realized prices, as adjusted for derivative activities for the years ended December 31, 2007 and 2006:

	Year ended December 31,
	2007			2006			2007			2006
	($ in thousands)						(per Mcf)
Natural gas revenues, as reported	$	262,169		$	212,919		$	6.94		$	7.35
Derivatives gains included in natural gas revenues(1)		(222	)		(448	)		(0.01	)		(0.02	)
Natural gas revenues before impact of derivatives	$	261,947		$	212,471		$	6.93		$	7.33
Cash settlements on natural gas derivatives(2)		14,863			10,711			0.39			0.37
Natural gas revenues, adjusted for derivatives	$	276,810		$	223,182		$	7.32		$	7.70
		($ in thousands)						(per Bbl)
Crude oil revenues, as reported	$	22,439		$	17,634		$	69.04		$	61.23
Derivatives losses included in crude oil revenues(1)		502			457			1.54			1.59
Crude oil revenues before impact of derivatives	$	22,941		$	18,091		$	70.58		$	62.82
Cash settlements on crude oil derivatives(2)		(735	)		(222	)		(2.26	)		(0.77	)
Crude oil revenues, adjusted for derivatives	$	22,206		$	17,869		$	68.32		$	62.05

(1) As a result of the original forecasted transactions settling, we reclassified the remaining amounts in accumulated other comprehensive income to earnings in 2007. As a result, in 2008, no derivatives gains or losses were reported as part of natural gas, crude oil and NGL revenues.

(2) As a result of the original forecasted transactions settling, we mark-to-market our derivative positions and record these gains or losses on the derivatives line on the Consolidated Statements of Income. These cash settlements relate to those derivative gains or losses. Had we not elected to discontinue hedge accounting on our commodity derivatives in 2006, these cash settlements would have been recognized in the natural gas and crude oil revenues lines on our consolidated statements of income.

Gain on sale of property and equipment.    In 2007, we recognized a $12.2 million gain on the sale property and equipment primarily related to the September 2007 sale of non-operated working interests in oil and gas properties.

Other income.    Other income decreased by $1.3 million, or 65%, from $2.0 million in 2006 to 0.7 million in 2007. This decrease is primarily due to an increase in fees paid by us to PVR for marketing our natural gas. This fee arrangement began in September 2006, and the increase in the fee was due primarily to a full year of the fee in 2007, as well as an increase in production in the East Texas and Mid-Continent regions.

Expenses.    Aggregate operating costs and expenses increased by $48.2 million, or 32%, from $151.1 million in 2006 to $199.3 million in 2007 primarily due to increases in operating expenses, taxes other than income, general and administrative expenses and DD&A expenses, partially offset by a decrease in exploration expenses and the impairment of properties.

Operating expenses increased by $19.3 million, or 70%, from $27.4 million, or $0.88 per Mcfe, in 2006 to $46.7 million, or $1.15 per Mcfe, in 2007. In addition to a general increase in oilfield

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service costs and activity in all operating areas, the increase was due to the 30% production increase and additional expenses in a number of operating areas related to workovers, water disposal, gathering, compression and maintenance.

Taxes other than income increased by $6.0 million, or 51%, from $11.8 million in 2006 to $17.8 million in 2007 primarily due to the 24% increase in natural gas, crude oil and NGL revenues and a severance tax credit received in 2006 related to production in the Cotton Valley play in East Texas and property tax adjustments in West Virginia.

General and administrative expenses increased by $3.5 million, or 27%, from $12.8 million in 2006 to $16.3 million in 2007 primarily due to an expansion of operations across the oil and gas segment, increased drilling activity and acquisitions, increased consulting costs and increased staffing and benefits costs. General and administrative costs, on a Mcfe basis, remained relatively constant at $0.40 in 2007 compared with $0.41 in 2006.

DD&A expenses increased by $31.0 million, or 55%, from $56.2 million in 2006 to $87.2 million in 2007 primarily due to the 30% increase in equivalent production and higher depletion rates. Our average depletion rate increased from $1.80 per Mcfe in 2006 to $2.15 per Mcfe in 2007 primarily due to increased development costs and the sale of and reduced contributions from properties with lower depletion rates.

Exploration expenses in the years ended December 31, 2007 and 2006 consisted of the following:

	Year ended December 31,
($ in thousands)	2007	2006
Dry hole costs	$11,689	$15,178
Geological and geophysical	2,769	6,237
Unproved leasehold	13,036	9,410
Other	1,114	3,505
Total	$28,608	$34,330

Exploration expenses decreased by $5.7 million, or 17%, from $34.3 million in 2006 to $28.6 million in 2007 primarily due to decreases in dry hole costs and geological and geophysical costs, partially offset by an increase in unproved leasehold expenses. Dry hole costs decreased primarily due to write-offs of three exploratory wells in 2007 compared to eight wells in 2006. Geological and geophysical expenses decreased primarily due to a decrease in core-hole drilling, as well as a reduction in seismic purchases. Unproved leasehold expenses increased primarily due to a $2.7 million write-off of a prospect in the Williston Basin. Other costs decreased primarily due to a decrease in delay rental payments. In 2006, we incurred $1.8 million of delay rent charges caused by drilling delays in Louisiana.

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

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PVR coal and natural resource management segment

Three months ended March 31, 2009 compared with three months ended March 31, 2008

The following table sets forth a summary of certain financial and other data for the PVR coal and natural resource management segment and the percentage change for the three months ended March 31, 2009 and 2008:

	Three months ended March 31,						% Change
($ in thousands, except as noted)	2009			2008
Revenues
Coal royalties	$	30,630		$	23,962		28%
Coal services		1,888			1,862		1%
Timber		1,317			1,584		(17)%
Oil and gas royalty		703			1,234		(43)%
Other		3,714			1,652		125%
Total revenues	$	38,252		$	30,294		26%
Expenses
Coal royalties expense		1,224			2,512		(51)%
Other operating		883			231		282%
Taxes other than income		425			371		15%
General and administrative		3,352			3,185		5%
Depreciation, depletion and amortization		7,394			6,413		15%
Total expenses	$	13,278		$	12,712		4%
Operating income	$	24,974		$	17,582		42%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,748			7,640		15%
Average royalties revenues per ton ($/ton)	$	3.50		$	3.14		12%
Less royalties expense per ton ($/ton)		(0.14	)		(0.33	)	(58)%
Average net coal royalties per ton ($/ton)	$	3.36		$	2.81		20%

Revenues.    Coal royalties revenues increased by $6.6 million, or 28%, from $24.0 million in the three months ended March 31, 2008 to $30.6 million in the same period of 2009, primarily due to the increase in the average sales price of coal received by lessees and the overall increase in production from certain subleased properties. Coal royalties expense decreased by $1.3 million, or 51%, from $2.5 million in the three months ended March 31, 2008 to $1.2 million in the same period of 2009, primarily due to decreased production from certain subleased properties in the Central Appalachian region. The average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, increased by $0.55 per ton, or 20%, from $2.81 per ton in the three months ended March 31, 2008 to $3.36 per ton in the same period of 2009. The increase in average net coal royalty per ton was due primarily to the higher royalty revenues per ton received from PVR’s lessees in all regions.

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The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the three months ended March 31, 2009 and 2008:

	Coal production		Coal royalties revenues						Coal royalties per ton
									Three months ended March 31,
Region	2009	2008	2009			2008			2009			2008
	(tons in thousands)		($ in thousands)						($ per ton)
Central Appalachia	4,658	4,811	$	21,683		$	18,579		$	4.66		$	3.86
Northern Appalachia	1,057	674		1,951			1,134			1.85			1.68
Illinois Basin	1,261	1,033		3,241			1,938			2.57			1.88
San Juan Basin	1,772	1,122		3,755			2,311			2.12			2.06
Total	8,748	7,640	$	30,630		$	23,962		$	3.50		$	3.14
Less coal royalties expense(1)				(1,224	)		(2,512	)		(0.14	)		(0.33	)
Net coal royalties revenues			$	29,406		$	21,450		$	3.36		$	2.81

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

Coal production in the Central Appalachian region remained relatively constant from the three months ended March 31, 2008 to the same period of 2009. Coal production in the Northern Appalachian region increased by 0.4 million tons, or 57%, from 0.7 million tons in the three months ended March 31, 2008 to 1.1 million tons in the same period of 2009. This increase was due primarily to increased production on PVR’s longwall mining operations in the region. Coal production in the Illinois Basin region increased by 0.3 million tons, or 22%, from 1.0 million tons in the three months ended March 31, 2008 to 1.3 million tons in the same period of 2009. This increase was due primarily to more efficient mining conditions by certain lessees in Western Kentucky. Coal production in the San Juan Basin region increased by 0.7 million tons, or 58%, from 1.1 million tons in the three months ended March 31, 2008 to 1.8 million tons in the same period of 2009. This increase was due primarily to new mining contracts obtained by lessees in the region.

Coal services revenues remained relatively constant from the three months ended March 31, 2008 to the same period of 2009. Timber revenues decreased by $0.3 million, or 17%, from $1.6 million in the three months ended March 31, 2008 to $1.3 million in the same period of 2009 primarily due to decreased harvesting of timber resulting from weakened market conditions. Oil and gas royalty revenues decreased by $0.5 million, or 43%, from $1.2 million in the three months ended March 31, 2008 to $0.7 million in the same period of 2009, primarily due to decreased natural gas prices. Other revenues increased by $2.0 million, or 125%, from $1.7 million in the three months ended March 31, 2008 to $3.7 million in the same period of 2009, primarily due to forfeited minimum rentals that PVR recorded as revenue in the three months ended March 31, 2009.

Expenses.    Other operating expenses increased by $0.7 million, or 282%, from $0.2 million in the three months ended March 31, 2008 to $0.9 million in the same period of 2009, primarily due to increased core drilling expenses related to coal reserves that PVR acquired in May 2008, and increased coal exploration expenses, which were due to coal reserve study expenses incurred in the three months ended March 31, 2009. Both taxes other than income and general and administrative expenses remained relatively constant from the three months ended March 31, 2008 to the same period of 2009. DD&A expenses increased by $1.0 million, or 15%, from $6.4 million in the three months ended March 31, 2008 to $7.4 million in the same period of 2009, primarily due to higher depletion expenses resulting from increased overall coal production.

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Year ended December 31, 2008 compared with year ended December 31, 2007

The following table sets forth a summary of certain financial and other data for the PVR coal and natural resource management segment and the percentage change for the years ended December 31, 2008 and 2007:

	Year ended December 31,						% Change
($ in thousands, except as noted)	2008			2007
Revenues
Coal royalties	$	122,834		$	94,140		30%
Coal services		7,355			7,252		1%
Timber		6,943			1,711		306%
Oil and gas royalty		5,989			1,864		221%
Other		10,206			6,672		53%
Total revenues	$	153,327		$	111,639		37%
Expenses
Coal royalties expense	$	9,534		$	5,540		72%
Other operating		2,406			2,531		(5)%
Taxes other than income		1,680			1,110		51%
General and administrative		12,606			10,957		15%
Depreciation, depletion and amortization		30,805			22,690		36%
Total expenses	$	57,031		$	42,828		33%
Operating income	$	96,296		$	68,811		40%
Operating statistics
Royalty coal tons produced by lessees (tons in thousands)		33,690			32,528		4%
Average royalties revenues per ton ($/ton)	$	3.65		$	2.89		26%
Less royalties expense per ton ($/ton)		(0.28	)		(0.17	)	65%
Average net coal royalties per ton ($/ton)	$	3.37		$	2.72		24%

Revenues.    Coal royalties revenues increased by $28.7 million, or 30%, from $94.1 million in 2007 to $122.8 million in 2008 primarily due to increased production in the Central Appalachian and Illinois Basin regions and increased sales prices in those regions. Coal royalties expense increased by $4.0 million, or 72%, from $5.5 million in 2007 to $9.5 million in 2008, primarily due to the increase in production on PVR’s subleased property in the Central Appalachian region and is due to higher average sales prices for coal in the Central Appalachian region. The average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, increased by $0.65 per ton, or 24%, from $2.72 per ton in 2007 to $3.37 per ton in 2008. The increase in average net coal royalty per ton was due primarily to the higher royalty revenues per ton received by PVR’s lessees in the region. The increase in royalty revenues per ton received in Central Appalachia was due primarily to both increased coal production and higher average sales prices for coal in that region.

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The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the years ended December 31, 2008 and 2007:

	Coal production		Coal royalties revenues						Coal royalties per ton
									Year ended December 31,
	2008	2007	2008			2007			2008			2007
	(tons in thousands)		($ in thousands)						($ per ton)
Central Appalachia	19,587	18,827	$	93,577		$	68,815		$	4.78		$	3.66
Northern Appalachia	3,578	4,194		6,568			6,434			1.84			1.53
Illinois Basin	4,584	3,779		10,451			7,432			2.28			1.97
San Juan Basin	5,941	5,728		12,238			11,459			2.06			2.00
Total	33,690	32,528	$	122,834		$	94,140		$	3.65		$	2.89
Less coal royalties expense(1)				(9,534	)		(5,540	)		(0.28	)		(0.17	)
Net coal royalties revenues			$	113,300		$	88,600		$	3.37		$	2.72

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

Coal production in the Central Appalachian region increased by 0.8 million tons, or 4%, from 18.8 million tons in 2007 to 19.6 million tons in 2008. This increase was due primarily to longwall mining and the timing of mining equipment added to PVR’s properties in that region during 2008. Coal production in the Northern Appalachian region decreased by 0.6 million tons, or 15%, from 4.2 million tons in 2007 to 3.6 million tons in 2008. This decrease was due primarily to adverse longwall mining conditions. Coal production in the Illinois Basin region increased by 0.8 million tons, or 21%, from 3.8 million tons in 2007 to 4.6 million tons in 2008. This increase was due primarily to a full year of production in 2008 on the coal reserves that were acquired in June 2007. Coal production in the San Juan Basin region remained relatively constant from 2007 to 2008.

Coal services revenues remained relatively constant from 2007 to 2008. Timber revenues increased by $5.2 million, or 306%, from $1.7 million in 2007 to $6.9 million in 2008 primarily due to increased harvesting from PVR’s September 2007 forestland acquisition. Oil and gas royalty revenues increased by $4.1 million, or 221%, from $1.9 million in 2007 to $6.0 million in 2008, primarily due to the increased royalties resulting from PVR’s October 2007 oil and gas royalty interest acquisition. Other revenues increased by $3.5 million, or 53%, from $6.7 million in 2007 to $10.2 million in 2008, primarily due to increased coal transportation, or wheelage, fees attributable to better longwall production and an increase in sales prices in 2008, increased forfeiture income and a $0.8 million gain on the settlement of sterilized coal.

Expenses.    Other operating expenses remained relatively constant from 2007 to 2008. Taxes other than income increased by $0.6 million, or 51%, from $1.1 million in 2007 to $1.7 million in 2008, primarily due to increased severance taxes resulting from PVR’s September 2007 forestland acquisition and October 2007 oil and gas royalty interest acquisition. General and administrative expenses increased by $1.6 million, or 15%, from $11.0 million in 2007 to $12.6 million in 2008, primarily due to increased staffing costs. DD&A expenses increased by $8.1 million, or 36%, from $22.7 million in 2007 to $30.8 million in 2008 primarily due to increased depletion resulting from PVR’s September 2007 forestland acquisition, October 2007 oil and gas royalty interest acquisition and May 2008 coal reserves and forestland acquisition.

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Year ended December 31, 2007 compared with year ended December 31, 2006

The following table sets forth a summary of certain financial and other data for the PVR coal and natural resource management segment and the percentage change for the years ended December 31, 2007 and 2006:

	Year ended December 31,				% Change
($ in thousands, except as noted)	2007		2006
Revenues
Coal royalties	$  94,140		$  98,163		(4)%
Coal services	7,252		5,864		24%
Timber	1,711		1,024		67%
Oil and gas royalty	1,864		957		95%
Other	6,672		6,973		(4)%
Total revenues	$111,639		$112,981		(1)%
Expenses
Coal royalties expense	$    5,540		$    6,927		(20)%
Other operating	2,531		1,673		51%
Taxes other than income	1,110		934		19%
General and administrative	10,957		9,604		14%
Depreciation, depletion and amortization	$  22,690		$  20,399		11%
Total expenses	$  42,828		$  39,537		8%
Operating income	$  68,811		$  73,444		(6)%
Operating statistics
Royalty coal tons produced by lessees (tons in thousands)	32,528		32,778		(1)%
Average royalties revenues per ton ($/ton)	$      2.89		$      2.99		(3)%
Less royalties expense per ton ($/ton)	(0.17	)	(0.21	)	(19)%
Average net coal royalties per ton ($/ton)	$      2.72		$      2.78		(2)%

Revenues.    Coal royalties revenues decreased by $4.1 million, or 4%, from $98.2 million in 2006 to $94.1 million in 2007, primarily due to a lower average royalty per ton. Coal royalties expense decreased by $1.4 million, or 20%, from $6.9 million in 2006 to $5.5 million in 2007 primarily due to a decrease in production from subleased properties in the Central Appalachian region. The average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, remained relatively constant from 2006 to 2007.

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The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the years ended December 31, 2007 and 2006:

	Coal production		Coal royalties revenues						Coal royalties per ton
									Year ended December 31,
	2007	2006	2007			2006			2007			2006
	(tons in thousands)		($ in thousands)						($ per ton)
Central Appalachia	18,827	20,156	$	68,815		$	76,542		$	3.66		$	3.80
Northern Appalachia	4,194	5,009		6,434			7,314			1.53			1.46
Illinois Basin	3,779	2,540		7,432			4,768			1.97			1.88
San Juan Basin	5,728	5,073		11,459			9,539			2.00			1.88
Total	32,528	32,778	$	94,140		$	98,163		$	2.89		$	2.99
Less coal royalties expense(1)				(5,540	)		(6,927	)		(0.17	)		(0.21	)
Net coal royalties revenues			$	88,600		$	91,236		$	2.72		$	2.78

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

Coal production in PVR’s Central Appalachian region decreased by 1.4 million tons, or 7%, from 20.2 million tons in 2006 to 18.8 million tons in 2007. This decrease was due primarily to delays in the move of the longwall due to adverse mining conditions, the closing of certain mines in 2006 in PVR’s Central Appalachian region and permitting issues in the Central Appalachian region involving properties on which PVR’s coal reserves are located. Coal production in PVR’s Northern Appalachian region decreased by 0.8 million tons, or 16%, from 5.0 million tons in 2006 to 4.2 million tons in 2007. This decrease was due primarily to delays in the move of the longwall due to development delays, as well as the depletion of reserves in one mine. Coal production in PVR’s Illinois Basin region increased by 1.3 million tons, or 49%, from 2.5 million tons in 2006 to 3.8 million tons in 2007. This increase was due primarily to the June 2007 acquisition of coal reserves in Western and Hopkins Counties, Kentucky. Coal production in PVR’s San Juan Basin region increased by 0.6 million tons, or 13%, from 5.1 million tons in 2006 to 5.7 million tons in 2007. This increase was due primarily to an increase in spot market orders of coal due to the depletion of adjacent reserves not owned by PVR.

Coal services revenues increased by $1.4 million, or 24%, from $5.9 million in 2006 to $7.3 million in 2007 primarily due to the completed construction of a coal services facility in Knott County, Kentucky, which began operations in October 2006. Timber revenues increased by $0.7 million, or 67%, from $1.0 million in 2006 to $1.7 million in 2007 primarily due to increased harvesting from PVR’s September 2007 forestland acquisition. Oil and gas royalty revenues increased by $0.9 million, or 95%, from $1.0 million in 2006 to $1.9 million in 2007 primarily due to the increased royalties resulting from PVR’s October 2007 oil and gas royalty interest acquisition. Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fee income, remained relatively constant from 2006 to 2007.

Expenses.    Other operating expenses increased by $0.8 million, or 51%, from $1.7 million in 2006 to $2.5 million in 2007 primarily due to an increase in mine maintenance and core-hole drilling expenses on PVR’s Central Appalachian and Illinois Basin properties. General and administrative expenses increased by $1.4 million, or 14%, from $9.6 million in 2006 to $11.0 million in 2007 primarily due to increased staffing costs. DD&A expenses increased by $2.3 million, or 11%, from $20.4 million in 2006 to $22.7 million in 2007 primarily due to increased depletion resulting from PVR’s September 2007 forestland acquisition and October 2007 oil and gas royalty interest acquisition. In addition, PVR began depreciating its coal services facility in Knott County, Kentucky, which began operations in October 2006.

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PVR natural gas midstream segment

Three months ended March 31, 2009 compared with three months ended March 31, 2008

The following table sets forth a summary of certain financial and other data for the PVR natural gas midstream segment and the percentage change for the three months ended March 31, 2009 and 2008:

	Three months ended March 31,						% Change
($ in thousands, except as noted)	2009			2008
Revenues
Residue gas	$	81,194		$	61,667		32%
Natural gas liquids		30,606			56,197		(46)%
Condensate		2,903			6,216		(53)%
Gathering, processing and transportation fees		2,676			968		176%
Total natural gas midstream revenues(1)	$	117,379		$	125,048		(6)%
Equity earnings in equity investment		1,119			—		—
Producer services		9			1,472		(99)%
Total revenues	$	118,507		$	126,520		(6)%
Expenses
Cost of midstream gas purchased(1)	$	100,620		$	99,697		1%
Operating		6,783			4,050		67%
Taxes other than income		798			701		14%
General and administrative		4,244			3,333		27%
Depreciation and amortization		9,109			5,087		79%
Total operating expenses	$	121,554		$	112,868		8%
Operating income	$	(3,047	)	$	13,652		(122)%
Operating statistics
System throughput volumes (MMcf)		32,280			17,287		87%
System throughput volumes (MMcfd)		359			190		89%
Gross margin	$	16,759		$	25,351		(34)%
Impact of derivatives		3,792			(8,414	)	(145)%
Gross margin, adjusted for impact of derivatives	$	20,551		$	16,937		21%
Gross margin ($/Mcf)	$	0.52		$	1.47		(65)%
Impact of derivatives ($/Mcf)		0.12			0.49		(124)%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.64		$	0.98		(35)%

(1) In the three months ended March 31, 2009, PVR recorded $21.2 million of natural gas midstream revenue and $21.2 million for the cost of midstream gas purchased related to the purchase of natural gas from Penn Virginia Oil & Gas, L.P. and the subsequent sale of that gas to third parties. PVR takes title to the gas prior to transporting it to third parties. These transactions do not impact the gross margin.

Gross Margin.    PVR’s gross margin is the difference between PVR’s natural gas midstream revenues and PVR’s cost of midstream gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and

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other fees primarily from natural gas volumes connected to PVR’s gas processing plants. Cost of midstream gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts.

Natural gas midstream revenues decreased by $7.6 million, or 6%, from $125.0 million in the three months ended March 31, 2008 to $117.4 million in the same period of 2009. Cost of midstream gas purchased increased by $0.9 million, or 1%, from $99.7 million in the three months ended March 31, 2008 to $100.6 million in the same period of 2009. The gross margin decreased by $8.6 million, or 34%, from $25.4 million in the three months ended March 31, 2008 to $16.8 million in the same period of 2009. The gross margin decrease was a result of decreased commodity pricing, partially offset by margins earned from increased system throughput volume production. The increased volume was from areas exposed to both commodity prices and fixed fees. There were lower frac spreads during the three months ended March 31, 2009 compared to the same period of 2008. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis.

System throughput volumes increased by 169 MMcfd, or 89%, from 190 MMcfd in the three months ended March 31, 2008 to 359 MMcfd in the same period of 2009. This increase in throughput volumes is due primarily to the continued successful development by producers operating in the vicinity of the Panhandle System, as well as PVR’s success in contracting and connecting new supply. The Crossroads plant in East Texas, which became fully operational in April 2008, and the acquisition of Lone Star, which was consummated in the third quarter of 2008, also contributed to the volume increase.

During the three months ended March 31, 2009, PVR generated a majority of the gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See note 6 in the notes to our unaudited consolidated financial statements included elsewhere in this prospectus supplement for a description of PVR’s derivatives program. Adjusted for the impact of PVR’s commodity derivative instruments, PVR’s gross margin increased by $3.7 million, or 21%, from $16.9 million in the three months ended March 31, 2008 to $20.6 in the same period of 2009. On a per Mcf basis, the gross margin, adjusted for the impact of PVR’s commodity derivatives, decreased by $0.34 Mcf, or 35%, from $0.98 per Mcf in the three months ended March 31, 2008 to $0.64 in the same period of 2009. These changes are primarily due to the contribution of fixed fee volumes at the Crossroads plant and from the Lone Star acquisition.

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

Producer services revenues.    Producer services revenues decreased by $1.5 million, or 99%, from $1.5 million in the three months ended March 31, 2008 to less than $0.1 million in the same period of 2009 primarily due to the relative changes in natural gas indices from the purchasing and selling of natural gas.

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

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Operating expenses increased by $2.7 million, or 67%, from $4.1 million in the three months ended March 31, 2008 to $6.8 million in the same period of 2009. The increase in operating expenses was due primarily to increased costs for chemicals and lubricants, repairs and maintenance expenses and increased compressor rentals, all of which were driven by PVR’s expanding footprint in the Texas and Oklahoma Panhandle, expansion projects and recent acquisitions. Taxes other than income remained relatively constant from the three months ended March 31, 2008 to the same period of 2009. General and administrative expenses increased by $0.9 million, or 27%, from $3.3 million in the three months ended March 31, 2008 to $4.2 million in the same period of 2009, primarily due to increased staffing costs. Depreciation and amortization expenses increased by $4.0 million, or 79%, from $5.1 million in the three months ended March 31, 2008 to $9.1 million in the same period of 2009. The increase in depreciation and amortization expense was primarily due to capital spending on expansion projects, such as the Spearman and Crossroads plants and PVR’s 2008 acquisitions.

Year ended December 31, 2008 compared with year ended December 31, 2007

The following table sets forth a summary of certain financial and other data for the PVR natural gas midstream segment and the percentage change for the years ended December 31, 2008 and 2007:

	Year ended December 31,
($ in thousands, except as noted)	2008			2007			% Change
Revenues
Residue gas	$	452,535		$	242,129		87%
Natural gas liquids		229,765			172,144		33%
Condensate		26,009			13,889		87%
Gathering, processing and transportation fees		11,693			5,012		133%
Total natural gas midstream revenues(1)	$	720,002		$	433,174		66%
Equity earnings in equity investment		2,408			—		—
Producer services		5,843			4,632		26%
Total revenues	$	728,253		$	437,806		66%
Expenses
Cost of midstream gas purchased(1)	$	612,530		$	343,293		78%
Operating		20,737			12,893		61%
Taxes other than income		2,578			1,926		34%
General and administrative		14,300			11,958		20%
Impairments		31,801			—		—
Depreciation and amortization		27,361			18,822		45%
Total expenses	$	709,307		$	388,892		82%
Operating income	$	18,946		$	48,914		(61)%
Operating statistics
System throughput volumes (MMcf)		98,683			67,810		46%
System throughput volumes (MMcfd)		270			186		45%
Gross margin	$	107,472		$	89,881		20%
Impact of derivatives		(31,709	)		(13,184	)	141%
Gross margin, adjusted for impact of derivatives	$	75,763		$	76,697		(1)%
Gross margin ($/Mcf)	$	1.09		$	1.33		(18)%
Impact of derivatives ($/Mcf)		(0.32	)		(0.19	)	68%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.77		$	1.14		(32)%

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(1) 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 our subsidiary PVOG LP and the subsequent sale of that gas to third parties. PVR takes title to the gas prior to transporting it to third parties. These transactions do not impact the gross margin.

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

Natural gas midstream revenues increased by $286.8 million, or 66%, from $433.2 million in 2007 to $720.0 million in 2008. Cost of midstream gas purchased increased by $269.2 million, or 78%, from $343.3 million in 2007 to $612.5 million in 2008. The gross margin increased by $17.6 million, or 20%, from $89.9 million in 2007 to $107.5 million in 2008. The gross margin increase was a result of increased commodity pricing, increased system throughput volume production and higher fractionation, or frac spreads, during 2008 compared to 2007. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis.

System throughput volumes increased by 84 MMcfd, or 45%, from 186 MMcfd in 2007 to 270 MMcfd in 2008. This increase in throughput volumes is due primarily to the Crossroads plant in East Texas, which became fully operational in 2008, and to the Lone Star acquisition, which was consummated in the third quarter of 2008. Also, the continued successful development by producers operating in the vicinity of the Panhandle System, as well as our success in contracting and connecting new supply contributed to the increase in throughput volume.

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

During 2008, PVR generated a majority of the gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. See “Business—Our contracts—PVR natural gas midstream segment,” for discussion of the types of contracts utilized by the PVR natural gas midstream segment. As part of its risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See note 8 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a description of our derivative program in the years ended December 31, 2008 and 2007. Adjusted for the impact of our commodity derivative instruments for which we discontinued hedge accounting in 2006, PVR’s gross margin remained relatively constant from 2007 to 2008. On a per Mcf basis, the gross margin, adjusted for the impact of our commodity derivative instruments for which we discontinued hedge accounting in 2006, decreased by $0.37, or 32%, from $1.14 per Mcf in 2007 to $0.77 in 2008. Gross margins during the first part of 2008 continued to increase given the favorable pricing environment, such as higher commodity prices and frac spreads, and increased

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system throughput volumes. However, margins decreased towards the end of the year due to a significant decrease in the prices of NGLs as a result of reduced industrial demand in a weakening economy. The gross margin on a Mcf basis decreased in 2008 due to an increase in fee-based system throughput volumes. These volumes are associated with the expansions and acquisitions made during 2008.

Producer services revenues.    Producer services revenues increased by $1.2 million, or 26%, from $4.6 million in 2007 to $5.8 million in 2008 primarily due to an increase in agent fees for the marketing of our and third parties’ natural gas production. Agent fees increased primarily due to increases in our natural gas production as well as increases in the price of natural gas.

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

Expenses.    Total operating costs and expenses increased primarily due to increases in operating expenses, taxes other than income, general and administrative expenses and depreciation and amortization, as well as a goodwill impairment loss.

Operating expenses increased by $7.8 million, or 61%, from $12.9 million in 2007 to $20.7 million in 2008, primarily due to expenses related to PVR’s expanding footprint in areas of operation, including acquisitions and the addition of the Spearman and Crossroads plants. These expenses include increased repairs and maintenance expenses, increased compressor rentals, chemical and treating expenses and increased employee expenses. General and administrative expenses increased by $2.3 million, or 20%, from $12.0 million in 2007 to $14.3 million in 2008 primarily due to increased staffing costs. Taxes other than income increased by $0.7 million, or 34%, from $1.9 million in 2007 to $2.6 million in 2008. Depreciation and amortization expenses increased by $8.6 million, or 45%, from $18.8 million in 2007 to $27.4 million in 2008. Increases in both taxes other than income and depreciation and amortization expenses were primarily due to capital spending on the Spearman and Crossroads plants and acquisitions, including increased payroll taxes resulting from increased staffing.

In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, we test goodwill for impairment on an annual basis, at a minimum, and more frequently if a triggering event occurs. The goodwill testing during the fourth quarter of 2008 identified a goodwill impairment loss of $31.8 million. 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). 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 peer company based weighted average cost of capital of 12%.

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See note 12 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a further description of the impairment of goodwill.

Year ended December 31, 2007 compared with year ended December 31, 2006

The following table sets forth a summary of certain financial and other data for the PVR natural gas midstream segment and the percentage change for the years ended December 31, 2007 and 2006:

	Year ended December 31,
($ in thousands, except as noted)	2007			2006			% Change
Revenues
Residue gas	$	242,129		$	259,764		(7)%
Natural gas liquids		172,144			130,675		32%
Condensate		13,889			9,989		39%
Gathering, processing and transportation fees		5,012			2,287		119%
Total natural gas midstream revenues	$	433,174		$	402,715		8%
Producer services		4,632			2,195		111%
Total revenues	$	437,806		$	404,910		8%
Expenses
Cost of midstream gas purchased	$	343,293		$	334,594		3%
Operating		12,893			11,403		13%
Taxes other than income		1,926			1,420		36%
General and administrative		11,958			11,023		8%
Depreciation and amortization		18,822			17,094		10%
Total expenses	$	388,892		$	375,534		4%
Operating income	$	48,914		$	29,376		67%
Operating statistics
System throughput volumes (MMcf)		67,810			61,995		9%
System throughput volumes (MMcfd)		186			170		9%
Gross margin	$	89,881		$	68,121		32%
Impact of derivatives		(13,184)			(17,483	)	(25)%
Gross margin, adjusted for impact of derivatives	$	76,697		$	50,638		51%
Gross margin ($/Mcf)	$	1.33		$	1.10		21%
Impact of derivatives ($/Mcf)		(0.19	)		(0.28	)	(32)%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	1.14		$	0.82		39%

Gross margin.    Natural gas midstream revenues increased by $30.5 million, or 8%, from $402.7 million in 2006 to $433.2 million in 2007. Cost of midstream gas purchased increased by $8.7 million, or 3%, from $334.6 million in 2006 to $343.3 million in 2007. PVR’s gross margin increased by $21.8 million, or 32%, from $68.1 million in 2006 to $89.9 million in 2007. The gross margin increase was a result of a higher frac spread during 2007 and higher volumes of processed gas.

System throughput volumes at PVR’s gas processing plants and gathering systems increased by 16 MMcfd, or 9%, from 170 MMcfd in 2006 to 186 MMcfd in 2007. This increase is the result of

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higher volumes of processed gas, which is the portion of the system throughput volumes that is actually processed at the processing facility. The increase in processed gas was attributable to PVR’s success in contracting and connecting new supply to PVR’s facilities. Much of this new gas was a result of continued successful development by the producers operating in the vicinity of PVR’s systems. Additionally, the pipeline PVR acquired in 2006 allowed PVR to connect a number of PVR’s gathering systems directly to its Beaver plant, bringing its utilization of processing capacity to 100%.

During 2007, PVR generated a majority of its gross margin from contractual arrangements under which its gross margin is exposed to increases and decreases in the price of natural gas and NGLs. See “Business—Our contracts—PVR natural gas midstream segment,” for a discussion of the types of contracts utilized by the PVR natural gas midstream segment. As part of PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. Adjusted for the impact of our commodity derivative instruments for which we discontinued hedge accounting in 2006, PVR’s gross margin increased by $26.1 million, or 51%, from $50.6 million in 2006 to $76.7 million in 2007. On a per Mcf basis, PVR’s gross margin, adjusted for the impact of our commodity derivative instruments for which we discontinued hedge accounting in 2006, increased by $0.32, or 39%, from $0.82 per Mcf in 2006 to $1.14 in 2007.

Producer services revenues.    Producer services revenues increased by $2.4 million, or 111%, from $2.2 million in 2006 to $4.6 million in 2007 primarily due to an increase in agent fees for the marketing of our and third parties’ natural gas production. Agent fees increased primarily due to increases in our natural gas production as well as increases in the price of natural gas.

Expenses.    Total operating costs and expenses remained relatively constant in 2007 compared to 2006.

Operating expenses increased by $1.5 million, or 13%, from $11.4 million in 2006 to $12.9 million in 2007 primarily due to a full year of operations in 2007 on the pipeline and related compression facilities in Texas and Oklahoma that PVR acquired in 2006 and increased fees from compressor rentals. General and administrative expenses increased by $1.0 million, or 8%, from $11.0 million in 2006 to $12.0 million in 2007 primarily due to increased staffing costs. Taxes other than income increased by $0.5 million, or 36%, from $1.4 million in 2006 to $1.9 million in 2007. Depreciation and amortization expenses increased by $1.7 million, or 10%, from $17.1 million in 2006 to $18.8 million in 2007. Increases in both taxes other than income and depreciation and amortization expenses were primarily due to capital spending on organic growth and acquisition opportunities occurring in both 2006 and 2007.

Eliminations and other

Other and eliminations primarily represents corporate functions such as interest expense, income tax expense, oil and gas segment derivatives and elimination of intercompany sales.

Corporate operating expenses.    Corporate operating expenses primarily consist of general and administrative expenses other than from our oil and gas segment, the PVR coal and natural resource management segment and the PVR natural gas midstream segment. Corporate operating expenses decreased by $0.8 million, or 10%, from $7.5 million in the three months ended March 31, 2008 to $6.7 million in the same period of 2009. This decrease was primarily due

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to consulting costs that were incurred in the three months ended March 31, 2008 and due to decreased incentive compensation paid in the three months ended March 31, 2009 as compared to the same period of 2008.

Corporate operating expenses increased by $1.2 million, or 4%, from $30.2 million in the year ended December 31, 2007 to $31.6 million in the year ended December 31, 2008 primarily due to increased DD&A expenses resulting from capitalized costs incurred on a software implementation project. Corporate operating expenses increased by $13.2 million, or 77%, from $17.2 million in the year ended December 31, 2006 to $30.4 million in the year ended December 31, 2007, primarily due to increased general and administrative expenses resulting from wage increases, increased consulting expenses and the recognition of additional stock-based compensation expenses.

Interest expense.    Our consolidated interest expense increased by $1.8 million, or 16%, from $10.7 million in the three months ended March 31, 2008 to $12.5 million in the same period of 2009. Our consolidated interest expense increased by $6.9 million, or 18%, from $37.4 million in 2007 to $44.3 million in 2008. Our consolidated interest expense increased by $12.6 million, or 51%, from $24.8 million in 2006 to $37.4 million in 2007. Our consolidated interest expense is comprised of the following for the three months ended March 31, 2009 and 2008 and the years ended December 31, 2008, 2007 and 2006:

	Three months ended March 31,				Year ended December 31,
Source	2009		2008		2008		2007		2006
($ in thousands)
Penn Virginia borrowings	$(6,812	)	$(6,605	)	$(20,612	)	$(23,768	)	$(8,837	)
Penn Virginia capitalized interest	364		814		2,038		3,685		2,817
Penn Virginia interest rate swaps	(438	)	(24	)	(1,015	)	2		9
PVR borrowings	(4,868	)	(5,687	)	(23,641	)	(18,861	)	(19,661	)
PVR capitalized interest	77		488		675		786		335
PVR interest rate swaps	(825	)	267		(1,706	)	737		505
Total interest expense	$(12,502	)	$(10,747	)	$(44,261	)	$(37,419	)	$(24,832	)

Total interest expense related to our borrowings, capitalized interest and Interest Rate Swaps increased by $1.1 million, or 18%, from $5.8 million in the three months ended March 31, 2008 to $6.9 million in the same period of 2009. This increase in interest expense is due primarily to the increase in our average debt balance, which increased from $374.5 million in the three months ended March 31, 2008 to $594.5 million in the same period of 2009. Our oil and gas segment capitalized $0.4 million and $0.8 million in the three months ended March 31, 2009 and 2008. Both the borrowings and the capitalized interest for these periods were related to our oil and gas segment’s drilling program and unproved properties where it is anticipated exploratory and development testing will occur.

The increase in PVR’s interest expense is primarily due to the effects of the PVR Interest Rate Swap settlements in a decreased LIBOR environment. These settlements were partially mitigated by the decrease in PVR’s effective interest rate excluding the effects of the PVR Interest Rate Swaps, which decreased from 5.0% in the three months ended March 31, 2008 to 3.3% in the same period of 2009. PVR capitalized $0.5 million in interest costs in the three months ended March 31, 2008 primarily related to the construction of the Spearman and Crossroads plants. In connection with periodic settlements, we recognized $0.8 million in net hedging losses in the

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three months ended March 31, 2009 and $0.3 million in net hedging gains in the three months ended March 31, 2008 on the PVR Interest Rate Swaps in interest expense.

Total interest expense related to our borrowings, capitalized interest and Interest Rate Swaps remained relatively constant from the year ended December 31, 2007 to the year ended December 31, 2008. Total interest expense related to our borrowings, capitalized interest and Interest Rate Swaps increased by $14.1, or 234%, from $6.0 million in 2006 to $20.1 million in 2007. Our oil and gas segment capitalized $2.0 million, $3.7 million and $2.8 million of interest in 2008, 2007 and 2006. Both the borrowings and the capitalized interest for these periods were related to our oil and gas segment’s drilling program and unproved properties where it is anticipated exploratory and development testing will occur. In addition, the borrowings were also related to $88.2 million and $72.7 million in proved property acquisitions that we made in 2007 and 2006. We did not make any proved property acquisitions in 2008. In connection with periodic settlements, we recognized $1.0 million in net hedging losses on the Interest Rate Swaps in interest expense in 2008.

Interest expense from PVR borrowings, PVR capitalized interest and PVR Interest Rate Swaps increased by $7.4, or 42%, from $17.3 million in the year ended December 31, 2007 to $24.7 million in the year ended December 31, 2008. This increase is primarily due to the increase in PVR’s average debt balance, which increased from $289.3 million in 2007 to $478.5 million in 2008. Interest expense from PVR borrowings, PVR capitalized interest and PVR Interest Rate Swaps decreased by $1.5 million, or 8%, from $18.8 million in 2006 to $17.3 million in 2007 primarily due to a $114.6 million principal payment made by PVR on the PVR Revolver in December 2006.

PVR capitalized $0.7 million and $0.8 million in interest costs in 2008 and 2007 primarily related to the construction of the Spearman and Crossroads plants and $0.3 million in 2006 related to the construction of a coal services facility in October 2006. In connection with periodic settlements, PVR recognized $1.7 million in net hedging losses on the PVR Interest Rate Swaps in interest expense in 2008. In connection with periodic settlements, PVR recognized $0.7 million and $0.5 million in net hedging gains on the PVR Interest Rate Swaps in interest expense in 2007 and 2006.

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

PVR determines the fair values its commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. 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.

Consolidated derivative gains were $10.3 million in the three months ended March 31, 2009. Consolidated derivative losses were $25.9 million in the three months ended March 31, 2008. These gains and losses were due primarily to changes in fair value. Cash received for settlements totaled $19.1 million in the three months ended March 31, 2009 and cash paid for settlements totaled $9.0 million in the three months ended March 31, 2008. Consolidated derivative gains

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were $46.6 million in the year ended December 31, 2008. Consolidated derivative losses were $47.3 million in the year ended December 31, 2007. Consolidated derivative gains were $19.5 in the year ended December 31, 2006. These gains and losses were due primarily to changes in fair value. Cash paid for settlements totaled $46.1 million, $3.7 million and $8.9 million in the years ended December 31, 2008, 2007 and 2006.

Our consolidated derivative activity for the three months ended March 31, 2009 and 2008 and the years ended December 31, 2008, 2007 and 2006 is summarized below:

	Three months ended March 31,						Year ended December 31,
($ in thousands)	2009			2008			2008			2007			2006
Oil and gas segment unrealized derivative gain (loss)	$	1,104		$	(34,246	)	$	37,365		$	(15,842	)	$	20,268
Oil and gas segment realized gain (loss)		16,312			569			(7,620	)		14,128			10,489
PVR unrealized derivative gain (loss)		(9,997	)		17,298			55,303			(27,789	)		8,176
PVR realized gain (loss)		2,836			(9,522	)		(38,466	)		(17,779	)		(19,436	)
Consolidated derivative gain (loss)	$	10,255		$	(25,901	)	$	46,582		$	(47,282	)	$	19,497

Noncontrolling interest.    Noncontrolling interest primarily represents PVR’s net income allocated to the limited partner units owned by the public. Net income attributable to the noncontrolling interest reduced our consolidated income from operations by $3.7 million and $20.0 million in the three months ended March 31, 2009 and 2008. The decrease in noncontrolling interest in the three months ended March 31, 2009 compared to the same period of 2008 was primarily due to the decrease in PVR’s net income from $34.5 million in the three months ended March 31, 2008 to $9.5 million in the same period of 2009. Noncontrolling interest reduced our consolidated income from operations by $60.4 million, $30.3 million and $43.0 million in the years ended December 31, 2008, 2007 and 2006. The increase in noncontrolling interest for the year ended December 31, 2008 compared to the same period of 2007 was primarily due to the increase in PVR’s net income from $56.6 million in 2007 to $104.5 million in 2008. The decrease in noncontrolling interest for the year ended December 31, 2007 compared to the same period of 2006 was primarily due to the decrease in PVR’s net income from $73.9 million in 2006 to $56.6 million in 2007.

Summary of critical accounting policies and estimates

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

Oil and gas reserves

The estimates of oil and gas reserves are the single most critical estimate included in our consolidated financial statements. Reserve estimates become the basis for determining depletive write-off rates, recoverability of historical cost investments and the fair value of properties subject to potential impairments. There are many uncertainties inherent in estimating crude oil and natural gas reserve quantities, including projecting the total quantities in place, future

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production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are less precise than those of producing properties due to the lack of a production history. Accordingly, these estimates are subject to change as additional information becomes available.

Proved reserves are the estimated quantities of crude oil, condensate and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those reserves that are expected to be recovered from new wells or undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

There are several factors which could change our estimates of oil and gas reserves. Significant rises or declines in product prices could lead to changes in the amount of reserves as production activities become more or less economical. An additional factor that could result in a change of recorded reserves is the reservoir decline rates differing from those assumed when the reserves were initially recorded. Estimation of future production and development costs is also subject to change partially due to factors beyond our control, such as energy costs and inflation or deflation of oil field service costs. Additionally, we perform impairment tests pursuant to SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, when significant events occur, such as a market move to a lower price environment or a material revision to our reserve estimates. For the three months ended March 31, 2009, we recorded impairment charges related to our oil and gas segment properties of $1.2 million. 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 9 in the notes to our unaudited consolidated financial statements and note 14 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a detailed description of the impairment of our oil and gas properties.

Oil and gas properties

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

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A portion of the carrying value of our oil and gas properties is attributable to unproved properties. At December 31, 2008, the costs attributable to unproved properties were $154.8 million. We regularly assess on a property-by-property basis the impairment of individual unproved properties whose acquisition costs are relatively significant. Unproved properties whose acquisition costs are not relatively significant are amortized in the aggregate over the lesser of five years or the average remaining lease term. As exploration work progresses and the reserves on significant properties are proven, capitalized costs of these properties will be subject to depreciation and depletion. If the exploration work is unsuccessful, the capitalized costs of the properties related to the unsuccessful work will be expensed. The timing of any write-downs of these unproven properties, if warranted, depends upon the nature, timing and extent of future exploration and development activities and their results.

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.

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.

Natural gas midstream gross margin

PVR’s gross margin is the difference between its natural gas midstream revenues and its cost of midstream gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to PVR’s gas processing plants. 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

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upon actual volumes delivered. Cost of midstream gas purchased consists of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts.

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 and the calculation of the cost of midstream gas purchased may take up to 30 days following the month of production. Therefore, PVR makes 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.

Derivative activities

From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas, crude oil and NGL 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.

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 until the hedged transactions settled. When we discontinued hedge accounting for commodity derivatives, a net loss remained in accumulated other comprehensive income 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.

During the first quarter of 2009, both we and PVR discontinued hedge accounting for all of our Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for both our and the PVR Interest Rate Swaps are recognized in earnings currently. Our results of operations are affected by the changes in fair value, which fluctuates with changes in interest rates.

Because we no longer apply hedge accounting for our commodity derivatives or Interest Rate Swaps, 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 or Interest Rate Swap contracts. 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. See note 6 in the notes

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to our unaudited consolidated financial statements and note 8 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a further description of our and PVR’s derivatives programs.

Depreciation, depletion and amortization

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

PVR depletes coal properties on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by PVR’s own geologists and outside consultants. PVR’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. 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), and proceeds from disposition as a gain or loss on the sales of property and equipment.

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 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a more detailed description of our intangible assets.

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 acquisitions and business combinations 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

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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 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 an asset 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 a goodwill impairment loss of $31.8 million. 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). 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 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. See note 12 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a description of goodwill and the related impairment charge.

Fair value measurements

We adopted SFAS No. 157, Fair Value Measurements, effective January 1, 2008, for financial assets and liabilities measured on a recurring basis. FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”), delayed the application of SFAS No. 157 for nonfinancial assets and liabilities to fiscal years and interim periods beginning after November 15, 2008. Prior to the adoption of FSP FAS 157-2, we only applied fair value measurements to our financial assets and liabilities. Effective January 1, 2009, SFAS No. 157 now applies to both financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis.

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SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 requires fair value measurements to be classified and disclosed in one of the following three categories:

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

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

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

We use the following methods and assumptions to estimate the fair values of certain assets and liabilities:

• 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.

• Deferred compensation: The fair values for deferred compensation are based on quoted market prices of the underlying securities, which are Level 1 inputs.

• Oil and gas segment properties: In accordance with the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, oil and gas properties of $5.6 million were written down to their fair value of $4.4 million, resulting in impairment. See note 9 in the notes to our unaudited consolidated financial statements included elsewhere in this prospectus supplement for a further description of the impairment charge. The fair value of the oil and gas properties is estimated to be the present value of future net cash flows from the underlying reserves, using a forward strip commodity price discounted at a rate commensurate with the risk and remaining life of the asset. This is a Level 3 input.

• 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 a combination of costless collar and swap derivative contracts to hedge against the variability in its 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 the end of the relevant period. PVR determines the fair values of 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 6 in the notes to our unaudited consolidated financial statements and note 8 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement.

• Interest Rate Swaps: We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under our 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

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published interest rate yield curves as of the date of the estimate. Each of these is a Level 2 input. See note 6 in the notes to our unaudited consolidated financial statements and note 8 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement.

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.

New accounting pronouncements

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 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 three months ended March 31, 2009, we will recast our financial statements to retroactively apply the increase in interest expense resulting from the adoption to all periods presented. See note 7 in the notes to our unaudited consolidated financial statements and note 18 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a discussion of the Convertible Notes.

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Revised oil and gas standard

In December 2008, the SEC released the final rule for Modernization 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.

Environmental matters

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

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

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As of March 31, 2009 and December 31, 2008, PVR’s environmental liabilities were $1.1 million and $1.2 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. For a summary of the environmental laws and regulations applicable to PVR’s operations, see “Business—Government regulation and environmental matters.”

Recent accounting pronouncements

See note 3 in the notes to our unaudited consolidated financial statements and note 3 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a description of recent accounting pronouncements.

Quantitative and qualitative disclosures about market risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are as follows:

• Price risk

• Interest rate risk

• Customer credit risk

As a result of our and PVR’s risk management activities as discussed below, we are also exposed to counterparty risk with financial institutions with whom we enter into these risk management positions. Sensitivity to these risks has heightened due to the recent deterioration of the global economy, including financial and credit markets.

At March 31, 2009, PVR reported a net commodity derivative asset related to the natural gas midstream segment of $12.9 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 $42.3 million, 80% of which was concentrated with three counterparties. 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.

Price risk

We produce and sell natural gas, crude oil, NGLs and coal. As a result, our financial results are affected when prices for these commodities fluctuate. Such effects can be significant. Our price risk management program permits the utilization of derivative financial instruments (such as futures, forwards, option contracts and swaps) to seek to mitigate the price risks associated with

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fluctuations in natural gas, NGL and crude oil prices as they relate to our anticipated production and PVR’s natural gas midstream business. The derivative financial instruments are placed with major financial institutions that we believe are of acceptable credit risk. The fair values of our price risk management activities are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

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 NGL prices decline or we drill uneconomic wells, it is reasonably possible we could have a significant impairment.

The PVR natural gas midstream segment has completed a number of acquisitions in recent years. See “—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.

In the three months ended March 31, 2009 and the year ended December 31, 2008, we reported consolidated net derivative gains of $10.3 million and $46.6 million. 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 contracts were deferred in accumulated other comprehensive income until the hedged transactions settled. When we discontinued hedge accounting for commodity derivatives, a net loss of $12.1 million remained in accumulated other comprehensive income. 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. As of December 31, 2008, neither we nor PVR had any net losses remaining in accumulated other comprehensive income.

Because we no longer apply hedge accounting for our commodity derivatives and Interest Rate Swaps, 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 derivative gains or losses recognized due to fluctuations in the value of our commodity derivative and Interest Rate Swap contracts. 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

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could be significant in a volatile pricing environment. See note 6 in the notes to our unaudited consolidated financial statements and note 8 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a further description of our and PVR’s derivatives programs.

Oil and gas segment

The following table lists our open mark-to-market commodity derivative agreements and their fair values as of March 31, 2009:

	As of March 31, 2009
	Average Volume per day	Weighted average price						Estimated fair value
		Additional put option		Floor		Ceiling
Natural gas costless collars	(in MMBtu)			(per MMBtu)				($ in thousands)
Second quarter 2009	15,000			$	4.25	$	5.70	$	791
Third quarter 2009	15,000			$	4.25	$	5.70		633
Fourth quarter 2009	15,000			$	4.25	$	5.70		(89	)
First quarter 2010	35,000			$	4.96	$	7.41		(101	)
Second quarter 2010	30,000			$	5.33	$	8.02		1,077
Third quarter 2010	30,000			$	5.33	$	8.02		653
Fourth quarter 2010	30,000			$	5.42	$	8.67		276
First quarter 2011	30,000			$	5.42	$	8.67		(730	)
Natural gas three-way collars	(in MMBtu)			(per MMBtu)
Second quarter 2009	40,000	$	6.38	$	8.75	$	10.79		8,577
Third quarter 2009	40,000	$	6.38	$	8.75	$	10.79		8,234
Fourth quarter 2009	30,000	$	6.83	$	9.50	$	13.60		6,358
First quarter 2010	30,000	$	6.83	$	9.50	$	13.60		5,527
Natural gas swaps	(in MMBtu)			(per MMBtu)
Second quarter 2009	40,000			$	4.91				4,095
Third quarter 2009	40,000			$	4.91				2,735
Fourth quarter 2009	40,000			$	4.91				(105	)
Crude oil three-way collars	(in Bbl)			(per Bbl)
Second quarter 2009	500	$	80.00	$	110.00	$	179.00		1,372
Third quarter 2009	500	$	80.00	$	110.00	$	179.00		1,326
Fourth quarter 2009	500	$	80.00	$	110.00	$	179.00		1,261
Settlements to be paid in subsequent period									421
Oil and gas segment commodity derivatives—net asset								$	42,311

We estimate that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, oil and gas segment operating income for the remainder of 2009 would increase or decrease by approximately $28.6 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, oil and gas segment operating income for the remainder of 2009 would increase or decrease by approximately 4.4 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at anticipated levels. These estimated changes in gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

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We estimate that a $1.00 per MMBtu increase in the natural gas purchase price would decrease the fair value of the natural gas three-way collars by $23.8 million. We estimate that a $1.00 per MMBtu decrease in the natural gas purchase price would increase the fair value of the natural gas three-way collars by $23.0 million. We estimate that for a $5.00 per barrel increase in the crude oil price, the fair value of the crude oil three-way collar would decrease by $0.1 million. We estimate that for a $5.00 per barrel decrease in the crude oil price, the fair value of the crude oil three-way collar would increase by $0.1 million. These estimated changes exclude potential cash receipts or payments in settling these derivative positions.

PVR natural gas midstream segment

The following table lists PVR’s open mark-to-market commodity derivative agreements and their fair values as of March 31, 2009:

	As of March 31, 2009
	Average volume per day		Weighted average price				Estimated fair value
			Additional put option	Floor		Ceiling
	(in Bbl	)		(per Bbl	)		($ in thousands	)
Crude oil three-way collars
Second quarter 2009 through fourth quarter 2009	1,000		$70.00	$90.00		$119.25	$4,939
	(in MMBtu	)		(per MMBtu	)
Frac spread collar
Second quarter 2009 through fourth quarter 2009	6,000			$9.09		$13.94	5,594
Settlements to be received in subsequent period							2,366
Natural gas midstream segment commodity derivatives—net asset							$12,899

We estimate that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, natural gas midstream gross margin and operating income for the remainder of 2009 would decrease or increase by approximately $3.7 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, natural gas midstream gross margin and operating income for the remainder of 2009 would increase or decrease by approximately $3.7 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at anticipated levels. These estimated changes in gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

We estimate that for a $5.00 per barrel increase in the crude oil price, the fair value of the crude oil three-way collar would decrease by $0.3 million. We estimate that for a $5.00 per barrel decrease in the crude oil price, the fair value of the crude oil three-way collar would increase by $0.2 million. In addition, we estimate that a $1.00 per MMBtu increase or decrease in the natural gas purchase price and a $4.65 per barrel (the estimated equivalent of $5.00 per barrel of crude oil) increase or decrease in the NGL sales price would affect the fair value of the frac spread collar by $0.2 million. These estimated changes exclude potential cash receipts or payments in settling these derivative positions.

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Interest rate risk

As of March 31, 2009 and December 31, 2008, we had $390.0 million and $332.0 million of outstanding indebtedness under our Revolver, which carries a variable interest rate throughout its term. We entered into the Interest Rate Swaps to effectively convert the interest rate on $50.0 million of the amount outstanding under our Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 5.34% plus the applicable margin until December 2010. The Interest Rate Swaps are accounted for as cash flow hedges in accordance with SFAS No. 133. A 1% increase in short-term interest rates on the floating rate debt outstanding under our Revolver (net of amounts fixed through hedging transactions) as of March 31, 2009 would cost us approximately $3.4 million in additional interest expense. A 1% increase in short-term interest rates on the floating rate debt outstanding under the Revolver (net of amounts fixed through hedging transactions) as of December 31, 2008 would cost us approximately $2.8 million in additional interest expense.

As of March 31, 2009 and December 31, 2008, PVR had $595.1 million and $568.1 million of outstanding indebtedness under the PVR Revolver, which carries a variable interest rate throughout its term. PVR entered into the PVR Interest Rate Swaps to effectively convert the interest rate on $310.0 million of the amount outstanding under the PVR Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 3.54% plus the applicable margin until March 2010. From March 2010 to December 2011, the notional amounts of the PVR Interest Rate Swaps total $250.0 million with PVR paying a weighted average fixed rate of 3.37% 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 $100 million, with PVR paying a weighted average fixed rate of 2.09% 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. A 1% increase in short-term interest rates on the floating rate debt outstanding under the PVR Revolver (net of amounts fixed through hedging transactions) as of March 31, 2009 would cost us approximately $2.9 million in additional interest expense. A 1% increase in short-term interest rates on the floating rate debt outstanding under the PVR Revolver (net of amounts fixed through hedging transactions) as of December 31, 2008 would cost us approximately $2.8 million in additional interest expense.

In the first quarter of 2009, both we and PVR discontinued hedge accounting for all of the Interest Rate Swaps and PVR Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for both our and the PVR Interest Rate Swaps are recognized in earnings currently. Our results of operations are affected by the volatility of changes in fair value, which fluctuates with changes in interest rates. These fluctuations could be significant. See note 6 in the notes to our unaudited consolidated financial statements and note 8 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a further description of our and PVR’s derivatives programs.

Customer credit risk

We are exposed to the credit risk of our customers and lessees. Approximately 48% and 57% of our consolidated accounts receivable at March 31, 2009 and December 31, 2008 resulted from our oil and gas segment, approximately 39% and 33% resulted from the PVR natural gas midstream segment and approximately 13% and 10% resulted from the PVR coal and natural resource

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management segment. Approximately $17.4 million and $26.8 million of the PVR natural gas midstream segment’s receivables at March 31, 2009 and December 31, 2008 were related to three customers: Tenaska Marketing Ventures, Conoco, Inc. and Louis Dreyfus Energy Services. Approximately 40% and 46% of PVR’s natural gas midstream segment receivables and 16% of our consolidated receivables at March 31, 2009 and December 31, 2008 related to these three natural gas midstream customers. Approximately $12.2 million of our oil and gas segment receivables at March 31, 2009 were related to three customers: Chesapeake Operating, Inc. Crosstex Gulf Coast Marketing Ltd. and Dominion E&P, Inc. Approximately 21% of our oil and gas segment’s receivables and 11% of our consolidated receivables at March 31, 2009 related to these three oil and gas customers. Approximately $20.3 million of our oil and gas segment receivables at December 31, 2008 were related to three customers: Dominion Field Services, Inc., Antero Resources Corporation and Chesapeake Energy. 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 exist in regard to these customers.

These customer concentrations increase our exposure to credit risk on our consolidated receivables, since the financial insolvency of any of these customers could have a significant impact on our results of operations. If our customers or lessees become financially insolvent, they may not be able to continue to operate or meet their payment obligations. Any material losses as a result of customer defaults could harm and have an adverse effect on our business, financial condition or results of operations. Substantially all of our trade accounts receivable are unsecured.

To mitigate the risks of nonperformance by our customers, we perform ongoing credit evaluations of our existing customers. We monitor individual customer payment capability in granting credit arrangements to new customers by performing credit evaluations, seek to limit credit to amounts we believe the customers can pay and maintain reserves we believe are adequate to cover exposure for uncollectable accounts. As of March 31, 2009, no receivables were collateralized, and we recorded a $1.4 million allowance for doubtful accounts in the oil and gas segment. 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.

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Business

Overview

We are an independent oil and gas company primarily engaged in the development, exploration and production of natural gas and crude oil through our wholly owned subsidiary, PVOG. We also own partner interests in PVR, which is involved in the coal and natural resource management and natural gas midstream businesses, and PVG, which owns PVR’s general partner. For the twelve months ended March 31, 2009, the Restricted Group had net income of $109.1 million and Adjusted EBITDAX of $346.6 million, including cash distributions from PVG and PVR. See “Summary—Summary historical financial data” for a reconciliation of net income to Adjusted EBITDAX. Of the Adjusted EBITDAX amount, $301.4 million was generated from our oil and gas business and $45.1 million was received from cash distributions in respect of our partner interests in PVG and PVR.

Our oil and gas business

We have a geographically diverse asset base with core areas of operation in the East Texas, Mid-Continent, Appalachian, Mississippi and Gulf Coast regions of the United States. As of December 31, 2008, we had proved natural gas and oil reserves of approximately 916 Bcfe, of which 82% were natural gas and 51% were proved developed, with an SEC pre-tax PV-10 value of $908.0 million and standardized measure of discounted future net cash flows of $729.4 million. See “Summary—Summary reserve, production and operating data” for a reconciliation of PV-10 to standardized measure of discounted future net cash flows.

For the three months ended March 31, 2009 and the year ended December 31, 2008, we had average daily production of 152.3 MMcfe and 128.1 MMcfe. Our properties generally have long reserve lives and reasonably stable and predictable well production characteristics with a ratio of proved reserves to production (based on production for the year ended December 31, 2008) of approximately 19.5 years. At December 31, 2008, we owned 1.2 million net acres of leasehold interests, approximately 37% of which were undeveloped.

As of December 31, 2008, 97% of our proved reserves were located in primarily longer-lived, lower-risk basins in East Texas, the Mid-Continent, Appalachia and Mississippi, which comprised 43%, 15%, 19% and 15% of the proved reserves. Our Gulf Coast properties, representing 3% of proved reserves, are shorter-lived and have higher impact exploratory prospects. In 2008, we produced 46.9 Bcfe, a 16% increase compared to 40.6 Bcfe in 2007, with East Texas, the Mid-Continent, Appalachia, Mississippi and the Gulf Coast comprising 29%, 16%, 25%, 16% and 16% of total production volumes. In the three years ended December 31, 2008, we drilled 785 gross (544.4 net) wells, of which 94% were successful in producing natural gas in commercial quantities. For a more detailed discussion of our reserves and production, see “—Properties.”

The primary development play types that our oil and gas operations are focused on include the horizontal Lower Bossier (Haynesville) Shale play in East Texas, the horizontal Granite Wash play in the Mid-Continent, the multi-lateral horizontal CBM play in Appalachia and the predominantly horizontal Selma Chalk play in Mississippi.

We have grown our reserves and production primarily through development and exploratory drilling, complemented to a lesser extent by making strategic acquisitions. In 2008, we replaced 604% of our 2008 production entirely through the drillbit by adding approximately 283 Bcfe of

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proved reserves from extensions, discoveries and additions, net of revisions. In 2008, capital expenditures in our oil and gas segment were $641.7 million, of which $481.4 million, or 75%, was related to development drilling, $23.8 million, or 4%, was related to exploratory drilling, $95.5 million, or 15%, was related to leasehold acquisitions and $36.8 million, or 6%, was related to pipelines, gathering and facilities.

Our partner interests in PVG and PVR

We are indirectly involved in PVR’s coal and natural resource management and natural gas midstream businesses through our partner interests in PVR and PVG. We own the sole general partner of PVG and an approximate 77% limited partner interest in PVG, which in turn owns the sole 2% general partner interest and an approximate 37% limited partner interest in PVR. As part of its ownership of PVR’s general partner, PVG owns the rights, referred to as “incentive distribution rights,” to receive an increasing percentage of PVR’s quarterly distributions of available cash after certain levels of cash distributions have been achieved.

PVG consolidates PVR’s results into its financial statements because PVG controls PVR’s general partner. We consolidate PVG’s results into our financial statements because we control PVG’s general partner. PVG and PVR function with capital structures that are independent of each other and of us. While we report consolidated financial results of PVR’s coal and natural resource management and natural gas midstream businesses, the only cash we receive from those businesses is in the form of cash distributions we receive from PVG and PVR in respect of our partner interests in each of them. For the three months ended March 31, 2009 and the year ended December 31, 2008, these distributions were $11.6 million and $44.0 million.

PVR manages coal properties and enters into long-term leases with experienced, third-party mine operators. PVR provides them the right to mine its coal reserves in exchange for royalty payments, which generate stable and predictable cash flows and limit its exposure to declines in coal prices. PVR does not operate any mines, and as a result, does not directly have any operational risk or production costs. As of December 31, 2008, PVR owned or controlled approximately 827 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. 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 also owns and operates natural gas midstream assets located in Oklahoma and Texas. These assets include approximately 4,069 miles of natural gas gathering pipelines and five natural gas processing facilities having 300 MMcfd of total capacity. In the three months ended March 31, 2009 and the year ended December 31, 2008, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 32.3 Bcf and 98.7 Bcf. PVR’s 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.

Business strengths

Geographically diverse, primarily lower-risk and longer-lived reserve base.    We have successfully grown and diversified our asset base through entry into five key oil and gas regions, which we believe helps reduce our dependence on any single area, thereby reducing operational, production and reserve growth risk. At December 31, 2008, 97% of our proved reserves were

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located in primarily longer-lived lower-risk basins in Appalachia, Mississippi, East Texas and the Mid-Continent. Wells in these regions are generally characterized by predictable production profiles. Furthermore, our proved reserves generally have long production lives with a ratio of proved reserves to production of approximately 19.5 years based on average daily production of 128.1 MMcfe in the year ended December 31, 2008.

Consistent track record of efficient proved reserve and production growth.    For the three years ended December 31, 2008, we were able to replace 572% of our production at a cost of $2.21 per Mcfe. For the three years ended December 31, 2008, we increased our proved reserves and production at annualized compounded growth rates of 35% and 20%. We have achieved these results from a combination of organic growth through drilling and selective asset acquisitions that have enhanced our competitive position. In the three years ended December 31, 2008, we drilled 785 gross (544.4 net) wells, of which 94% were successful in producing natural gas in commercial quantities.

Conservative financial profile.    We have historically operated with relatively conservative levels of leverage and have also maintained relatively strong interest coverage ratios by industry standards for companies of our size. At March 31, 2009, after giving effect to the issuance and sale of shares of our common stock on May 22, 2009 and the application of the net proceeds therefrom to repay a portion of the borrowings outstanding under our Revolver, the ratio of the Restricted Group’s debt to proved developed reserves would have been $1.12 per Mcfe, and the Restricted Group’s debt to Adjusted EBITDAX would have been 1.5x for the twelve months ended March 31, 2009.

Additional cash flow from PVG and PVR.    Our partner interests in PVG and PVR have historically provided us with growing quarterly cash distributions. Based on PVG’s and PVR’s current annualized distribution rates of $1.52 and $1.88 per unit, we would receive aggregate annualized distributions of $46.3 million in respect of our partner interests in the year ended December 31, 2009. PVR expects to grow its coal reserves and expand its midstream operations through accretive acquisitions and development projects. We believe that PVR’s growth strategy, if successfully implemented, will provide us with a growing source of cash flow from our partner interests in PVG and PVR.

Advantages of our relationship with PVR.    During 2006, PVR began marketing our natural gas production in Louisiana, Oklahoma and Texas, allowing PVR to add a new source of revenues. In 2008, PVR constructed the Crossroads plant, an 80 MMcfd gas processing plant in the Bethany Field in East Texas, and entered into a gas gathering and processing agreement with us. The Crossroads plant provides fee-based gas processing services to our oil and gas business in the East Texas region, as well as other producers.

Experienced management and technical teams.    Our key executives have an average of over 25 years of industry experience. Our executive management team is supported by technical and operating managers who also have substantial industry experience and expertise within the basins in which we operate.

Business strategy

Growth primarily through development drilling.    We anticipate spending approximately $130.0 million to $140.0 million on oil and gas capital expenditures in 2009. We currently plan to allocate up to approximately 96% of capital expenditures in 2009 to development drilling and related projects in our core areas of East Texas, the Mid-Continent, Appalachia and Mississippi.

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We are applying horizontal drilling technology in each of these core areas which may result in increased reserve additions, higher production rates and increased rates of return. Capital spending levels in each of our core areas is expected to be significantly lower in 2009 than 2008.

Exploratory drilling provides operational balance and future development growth opportunities.    We intend to apply up to approximately 4% of capital expenditures in 2009 to our exploratory activities, including potentially higher-risk, higher-reward exploratory prospects in the Marcellus Shale in Pennsylvania. Capital for other exploratory prospects in the Mid-Continent, Appalachian and Gulf Coast regions has been deferred until commodity prices increase and access to the capital markets allows for increased equity or debt financing.

Pursue selective acquisition opportunities in existing basins.    Historically, we have pursued acquisitions of properties that we believe have development potential and that are consistent with our lower-risk drilling strategies. Our experienced team of management and technical professionals looks for new opportunities to increase reserves and production that complement our existing core properties. As a result of the current deterioration in the global economy, including financial and credit markets, minimal capital expenditures are anticipated as part of near-term oil and gas capital expenditures. In 2008, we made approximately $95.5 million of leasehold and other oil and gas acquisitions.

Manage risk exposure through an active hedging program.    We actively manage our exposure to commodity price fluctuations by hedging the commodity price risk for our expected proved developed production through the use of derivatives, typically three-way collar contracts. The level of our hedging activity and the duration of the instruments employed depend upon our cash flow at risk, available hedge prices and our operating strategy. As of May 31, 2009, we had hedged approximately 73%, 56% and 12% of our 2009, 2010 and 2011 proved developed production. See “Management’s discussion and analysis of financial condition and results of operations—Quantitative and qualitative disclosures about market risk—Price risk—Oil and gas segment” for a discussion of our hedging program.

Our contracts

Oil and gas segment

Transportation.    We have entered into contracts which provide firm transportation capacity rights for specified volumes per day on a pipeline system for terms ranging from one to 15 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.

Marketing.    We generally sell our natural gas using spot market and short-term fixed price physical contracts. In the three months ended March 31, 2009, 16% and 18% of our oil and gas segment revenues and 5% and 6% of our total consolidated revenues resulted from two of our oil and gas customers, Dominion Field Services, Inc. and Crosstex Energy Services, L.P. In the year ended December 31, 2008, approximately 15% and 14% of our oil and gas segment revenues and 6% and 5% of our total consolidated revenues resulted from those same two oil and gas customers.

PVR coal and natural resource management segment

PVR earns most of its coal royalties revenues under long-term leases that generally require its lessees to make royalty payments to it based on the higher of a percentage of the gross sales price or a fixed price per ton of coal they sell. The balance of PVR’s coal royalties revenues is

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earned under long-term leases that require the lessees to make royalty payments to PVR based on fixed royalty rates that escalate annually. A typical lease either expires upon exhaustion of the leased reserves or has a five to ten-year base term, with the lessee having an option to extend the lease for at least five years after the expiration of the base term. Substantially all of PVR’s leases require the lessee to pay minimum rental payments to PVR in monthly or annual installments, even if no mining activities are ongoing. These minimum rentals are recoupable, usually over a period from one to three years from the time of payment, against the production royalties owed to PVR once coal production commences.

Substantially all of PVR’s leases impose obligations on the lessees to diligently mine the leased coal using modern mining techniques, indemnify PVR for any damages it incurs in connection with the lessee’s mining operations, including any damages PVR may incur due to the lessee’s failure to fulfill reclamation or other environmental obligations, conduct mining operations in compliance with all applicable laws, obtain its written consent prior to assigning the lease and maintain commercially reasonable amounts of general liability and other insurance. Substantially all of the leases grant PVR the right to review all lessee mining plans and maps, enter the leased premises to examine mine workings and conduct audits of lessees’ compliance with lease terms. In the event of a default by a lessee, substantially all of the leases give PVR the right to terminate the lease and take possession of the leased premises.

In addition, PVR earns revenues under coal services contracts, timber contracts and oil and gas leases. PVR’s coal services contracts generally provide that the users of PVR’s coal services pay PVR a fixed fee per ton of coal processed at its facilities. All of PVR’s coal services contracts are with lessees of PVR’s coal reserves and these contracts generally have terms that run concurrently with the related coal lease. PVR’s timber contracts generally provide that the timber companies pay PVR a fixed price per thousand board feet of timber harvested from PVR’s property. PVR receives royalties under its oil and gas leases based on a percentage of the revenues the producers receive for the oil and gas they sell.

PVR natural gas midstream segment

PVR’s natural gas midstream business generates revenues primarily from gas purchase and processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. During the three months ended March 31, 2009 and the year ended December 31, 2008, PVR’s natural gas midstream business generated a majority of its gross margin from two types of contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs: (i) gas purchase/keep-whole and (ii) percentage-of-proceeds. As of December 31, 2008, approximately 27% of PVR’s system throughput volumes were gathered or processed under gas purchase/keep-whole contracts, 45% were gathered or processed under percentage-of-proceeds contracts and 28% were gathered or processed under fee-based gathering contracts. A majority of the gas purchase/keep-whole and percentage-of-proceeds contracts include fee-based components such as gathering and compression charges. There is also a processing fee floor included in many of the gas purchase/keep-whole contracts that ensures a minimum processing margin should the actual margins fall below the floor.

In the three months ended March 31, 2009, 25% and 14% of PVR’s natural gas midstream segment revenues and 15% and 8% of our total consolidated revenues were related to two of PVR’s natural gas midstream customers, Conoco, Inc. and Louis Dreyfus Energy Services. In the

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year ended December 31, 2008, 27% and 13% of PVR’s natural gas midstream segment revenues and 16% and 8% of our total consolidated revenues were related to these same natural gas midstream customers.

Gas purchase/keep-whole arrangements.    Under gas purchase/keep-whole arrangements, PVR generally purchases natural gas at the wellhead at either (i) a percentage discount to a specified index price, (ii) a specified index price less a fixed amount or (iii) a combination of (i) and (ii). PVR then gathers the natural gas to one of its plants where it is processed to extract the entrained NGLs, which are then sold to third parties at market prices. PVR resells the remaining natural gas to third parties at an index price which typically corresponds to the specified purchase index. Because the extraction of the NGLs from the natural gas during processing reduces the BTU content of the natural gas, PVR retains a reduced volume of gas to sell after processing. Accordingly, under these arrangements, PVR’s revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and its revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. PVR has generally been able to mitigate its exposure in the latter case by requiring the payment under many of its gas purchase/keep-whole arrangements of minimum processing charges which ensure that PVR receives a minimum amount of processing revenues. The gross margins that PVR realizes under the arrangements described in clauses (i) and (iii) above also decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price.

Percentage-of-proceeds arrangements.    Under percentage-of-proceeds arrangements, PVR generally gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed-upon percentage of the proceeds of those sales based on either an index price or the price actually received for the gas and NGLs. Under these types of arrangements, PVR’s revenues and gross margins increase as natural gas prices and NGL prices increase, and its revenues and gross margins decrease as natural gas prices and NGL prices decrease.

Fee-based arrangements.    Under fee-based arrangements, PVR receives fees for gathering, compressing and/or processing natural gas. The revenues PVR earns from these arrangements are directly dependent on the volume of natural gas that flows through its systems and are independent of commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, PVR’s revenues from these arrangements would be reduced due to the related reduction in drilling and development of new supply.

In many cases, PVR provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of PVR’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts were signed and customer requirements. The contract mix and, accordingly, exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

Natural gas marketing contracts.    PVR is also engaged in natural gas marketing by aggregating third-party volumes and selling those volumes into interstate and intrastate pipeline systems such as Enogex and ONEOK and at market hubs accessed by various interstate pipelines. Connect Energy Services, LLC, PVR’s wholly owned subsidiary, has earned fees from Penn Virginia Oil & Gas, L.P., or PVOG LP, our wholly owned subsidiary, since September 1, 2006, for marketing a portion of PVOG LP’s natural gas production. Revenues from this business do not generate qualifying income for a publicly traded limited partnership, but PVR does not expect it to have an

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impact on its tax status, as it does not represent a significant percentage of PVR’s operating income. In the years ended December 31, 2008 and 2007, PVR’s natural gas marketing activities generated $5.8 million and $4.6 million in net revenues. Fees paid to the PVR natural gas midstream segment by our oil and gas segment are eliminated in consolidation.

Properties

Title to properties

The following map shows the general locations of our oil and gas production and exploration, PVR’s coal reserves and related infrastructure investments and PVR’s natural gas gathering and processing systems as of December 31, 2008:

We believe that we have satisfactory title to all of our properties and the associated oil, natural gas and coal reserves in accordance with standards generally accepted in the oil and natural gas, coal and natural resource management and natural gas midstream industries.

Our facilities

We are headquartered in Radnor, Pennsylvania, with additional offices in Oklahoma, Tennessee, Texas and West Virginia. All of our office facilities are leased, except for PVR’s West Virginia office, which it owns. We believe that our properties are adequate for our current needs.

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Oil and gas segment properties

As is customary in the oil and gas industry, we make only a cursory review of title to farmout acreage and to undeveloped oil and gas leases upon execution of any contracts. Prior to the commencement of drilling operations, a thorough title examination is conducted and curative work is performed with respect to significant defects. To the extent title opinions or other investigations reflect defects, we cure such title defects. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on a property, we could suffer a loss of our investment in the property. Prior to completing an acquisition of producing oil and gas assets, we obtain title opinions on all material leases. Our oil and gas properties are subject to customary royalty interests, liens for current taxes and other burdens that we believe do not materially interfere with the use or materially affect the value of such properties.

Production and pricing

The following table sets forth production, average realized prices and production expenses with respect to our properties in the oil and gas segment for the years ended December 31, 2008, 2007 and 2006:

	Year ended December 31,
($ in thousands)	2008			2007			2006
Production data:
Natural gas (MMcf)		41,493			37,802			28,968
Crude oil (MBbl)		506			325			288
NGL (MBbl)		392			136			94
Total production (MMcfe)		46,881			40,569			31,260
Average realized prices(1):
Natural gas ($/Mcf)
Natural gas revenues, as reported	$	8.89		$	6.94		$	7.35
Derivatives (gains) losses included in natural gas revenues		—			(0.01	)		(0.02	)
Natural gas revenues before impact of derivatives	$	8.89		$	6.93		$	7.33
Cash settlements on natural gas derivatives(2)		(0.18	)		0.39			0.37
Natural gas revenues, adjusted for derivatives	$	8.71		$	7.32		$	7.70
Crude oil ($/Bbl)
Crude oil revenues, as reported	$	91.95		$	69.04		$	61.23
Derivatives (gains) losses included in crude oil revenues		—			1.54			1.59
Crude oil revenues before impact of derivatives	$	91.95		$	70.58		$	62.82
Cash settlements on crude oil derivatives(2)		(0.55	)		(2.26	)		(0.77	)
Crude oil revenues, adjusted for derivatives	$	91.40		$	68.32		$	62.05
Production Expenses ($/Mcfe):
Lease operating	$	1.27		$	1.15		$	0.88
Taxes other than income		0.50			0.44			0.38
General and administrative		0.45			0.40			0.41
Total production expenses	$	2.22		$	1.99		$	1.67

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(1) In 2006, we discontinued hedge accounting prospectively for our remaining and future commodity derivatives. Consequently, we began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income. The derivatives (gains) losses included in natural gas revenues and crude oil revenues represent the reclassifications out of accumulated other comprehensive income related to the derivatives for which we discontinued hedge accounting in 2006. The average realized prices represent the effects of the derivatives for which we discontinued hedge accounting on our natural gas and crude oil revenues.

(2) Cash settlements on derivatives represent the realized portion of the commodity derivatives and are recorded on the derivatives line on our consolidated statements of income. Had we not elected to discontinue hedge accounting, the cash settlements would have been recognized in the natural gas and crude oil revenues lines on our consolidated statements of income.

Proved reserves

The following table presents certain information regarding our proved reserves as of December 31, 2008, 2007 and 2006. The proved reserve estimates presented below were prepared by Wright and Company, Inc., independent petroleum engineers. No reserve estimate has been filed with any federal authority or agency since January 1, 2008. For additional information regarding estimates of proved reserves, the preparation of such estimates by Wright and Company, Inc. and other information about our oil and gas reserves, see the supplemental information on oil and gas producing activities (unaudited) in the notes to our audited consolidated financial statements for the years ended December 31, 2008, 2007 and 2006. Our estimates of proved reserves in the following table are consistent with those filed by us with other federal agencies.

As of December 31,	Natural gas	Oil and condensate	Natural gas equivalents	Standardized measure(1)	Year-end prices used(2)
	(Bcf)	(MMbbls)	(Bcfe)	($ millions)	($/MMbtu)	($/Bbl)
2008
Developed	411	9.9	470	$692
Undeveloped	343	17.1	446	37
Total	754	27.0	916	$729	$5.71	$44.60
2007
Developed	373	4.5	399	$788
Undeveloped	215	10.7	281	184
Total	588	15.2	680	$972	$6.80	$95.95
2006
Developed	326	3.0	345	$545
Undeveloped	131	1.9	142	60
Total	457	4.9	487	$605	$5.64	$61.05

(1) Standardized measure is the present value of proved reserves further reduced by the present value (discounted at 10%) of estimated future income taxes on cash flows using prices in effect at a fiscal year end and estimated future costs as of that fiscal year end. For information on the changes in the standardized measure of discounted future net cash flows, see the supplemental information on oil and gas producing activities (unaudited) in the notes to our audited consolidated financial statements for the years ended December 31, 2008, 2007 and 2006.

(2) Natural gas and oil prices were based on sales prices per Mcf and Bbl in effect at year end, with the representative price of natural gas adjusted for basis premium and BTU content to arrive at the appropriate net price.

In accordance with the SEC’s guidelines, the engineers’ estimates of future net revenues from our properties and the standardized measure thereof are based on oil and natural gas sales prices in effect as of December 31, 2008, and estimated future costs as of December 31, 2008. The prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations.

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Prices for oil and gas are subject to substantial seasonal fluctuations as well as fluctuations resulting from numerous other factors. See “Management’s discussion and analysis of financial condition and results of operations.”

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. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Therefore, the standardized measure amounts shown above should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. The information set forth in the foregoing tables includes revisions of certain volumetric reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in production prices.

Production and reserves by region

The following table sets forth by region the estimated quantities of provided reserves as of December 31, 2008:

	Proved reserves as of December 31, 2008
Region	Proved reserves (Bcfe)	% Total proved reserves	% Proved developed
Appalachia	170	19%	74%
Mississippi	155	17%	71%
East Texas	419	46%	31%
Mid-Continent	141	15%	55%
Gulf Coast	31	3%	89%
Total	916	100%	51%

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The following table sets forth by region the average daily production and total production for the years ended December 31, 2008, 2007 and 2006:

	Average daily production for the year ended December 31,			Total production for the year ended December 31,
Region	2008	2007	2006	2008	2007	2006
		(MMcfe)			(MMcfe)
Appalachia	31.4	34.0	35.0	11,497	12,424	12,759
Mississippi	20.1	20.7	17.6	7,340	7,551	6,411
East Texas	36.6	21.9	12.5	13,409	7,986	4,546
Mid-Continent	20.9	11.3	3.4	7,646	4,131	1,248
Gulf Coast	19.1	23.2	17.3	6,989	8,477	6,296
Total	128.1	111.1	85.8	46,881	40,569	31,260

Our acreage

The following table sets forth our developed and undeveloped acreage as of December 31, 2008. The acreage is located primarily in the East Texas, Mid-Continent, Appalachian, Mississippi, and Gulf Coast regions of the United States.

	As of December 31, 2008
(in thousands)	Gross acreage	Net acreage
Developed	888	771
Undeveloped	790	453
Total	1,678	1,224

Wells drilled

The following table sets forth the gross and net numbers of exploratory and development wells that we drilled during the years ended December 31, 2008, 2007 and 2006. The number of wells drilled refers to the number of wells reaching total depth at any time during the respective year. Net wells equal the number of gross wells multiplied by our working interest in each of the gross wells. Productive wells represent either wells which were producing oil or gas or which were capable of production.

	Year ended December 31,
	2008		2007		2006
	Gross	Net	Gross	Net	Gross	Net
Development
Productive	259	160.5	265	198.5	187	138.9
Non-productive	4	3.0	6	5.1	3	2.4
Under evaluation	11	8.8	—	—	—	—
Total development	274	172.3	271	203.6	190	141.3
Exploratory
Productive	6	3.5	11	5.2	13	7.2
Non-productive	5	2.8	3	1.6	6	2.3
Under evaluation	1	1.0	4	2.6	1	1.0
Total exploratory	12	7.3	18	9.4	20	10.5
Total	286	179.6	289	213.0	210	151.8

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The eleven development wells under evaluation at December 31, 2008 included seven Cotton Valley wells in East Texas, one horizontal Lower Bossier (Haynesville) Shale well in East Texas, one additional well in East Texas and two wells in the Mid-Continent region. The exploratory well under evaluation at December 31, 2008 was in the Mid-Continent region.

The four exploratory wells under evaluation as of December 31, 2007 included two Devonian Shale wells in West Virginia, one New Albany Shale well in Illinois and one horizontal CBM well in West Virginia. In 2008, we determined that all four wells were not commercially viable. Accordingly, we charged $4.3 million to expense related to those wells.

The exploratory well under evaluation as of December 31, 2006 was a Cotton Valley well in East Texas. In 2007, we determined that this well was commercially viable and reclassified $1.1 million to wells, equipment and facilities based on the determination of proved reserves.

Productive wells

The following table sets forth the number of productive oil and gas wells in which we had a working interest at December 31, 2008. Productive wells are wells that are producing oil or gas or that are capable of commercial production.

At December 31, 2008
Operated wells		Non-operated wells		Total
Gross	Net	Gross	Net	Gross	Net
1,652	1,415	670	93	2,322	1,508

In addition to the above working interest wells, we own royalty interests in 2,611 gross wells.

Coal reserves and production

As of December 31, 2008, PVR owned or controlled approximately 827 million tons of proven and probable coal reserves located on approximately 495,000 acres (including fee and leased acreage) in Illinois, Kentucky, New Mexico, Virginia and West Virginia. PVR’s coal reserves are in various surface and underground mine seams located on the following properties:

• Central Appalachia Basin: properties located in eastern Kentucky, southwestern Virginia and southern West Virginia;

• Northern Appalachia Basin: properties located in northern West Virginia;

• Illinois Basin: properties located in southern Illinois and western Kentucky; and

• San Juan Basin: properties located in the four corners area of New Mexico.

Coal reserves are coal tons that can be economically extracted or produced at the time of determination considering legal, economic and technical limitations. All of the estimates of PVR’s coal reserves are classified as proven and probable reserves. Proven and probable coal reserves are defined as follows:

Proven coal reserves.    Proven coal reserves are reserves for which: (i) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; (ii) grade and/or quality are computed from the results of detailed sampling; and (iii) the sites for inspection, sampling and

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measurement are spaced so closely, and the geologic character is so well defined, that the size, shape, depth and mineral content of reserves are well-established.

Probable coal reserves.    Probable coal reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are more widely spaced or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

In areas where geologic conditions indicate potential inconsistencies related to coal reserves, PVR performs additional exploration to ensure the continuity and mineability of the coal reserves. Consequently, sampling in those areas involves drill holes or channel samples that are spaced closer together than those distances cited above.

Coal reserve estimates are adjusted annually for production, unmineable areas, acquisitions and sales of coal in place. The majority of PVR’s coal reserves are high in energy content, low in sulfur and suitable for either the steam or metallurgical market.

The amount of coal that a lessee can profitably mine at any given time is subject to several factors and may be substantially different from “proven and probable coal reserves.” Included among the factors that influence profitability are the existing market price, coal quality and operating costs.

The following tables set forth production data for the years ended December 31, 2008, 2007 and 2006 and reserve information as of December 31, 2008 with respect to each of PVR’s properties:

	Production for the year ended December 31,
Property	2008	2007	2006
(tons in millions)
Central Appalachia	19.6	18.8	20.2
Northern Appalachia	3.6	4.2	5.0
Illinois Basin	4.6	3.8	2.5
San Juan Basin	5.9	5.7	5.1
Total	33.7	32.5	32.8

	Proven and probable reserves as of December 31, 2008
Property	Underground	Surface	Total	Steam	Metallurgical	Total
(tons in millions)
Central Appalachia	440.8	149.0	589.8	502.5	87.3	589.8
Northern Appalachia	26.4	—	26.4	26.4	—	26.4
Illinois Basin	154.9	10.8	165.7	165.7	—	165.7
San Juan Basin	—	44.9	44.9	44.9	—	44.9
Total	622.1	204.7	826.8	739.5	87.3	826.8

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The following table sets forth the coal reserves PVR owned and leased with respect to each of its coal properties as of December 31, 2008:

Property	Owned	Leased	Total controlled
(tons in millions)
Central Appalachia	454.4	135.4	589.8
Northern Appalachia	26.4	—	26.4
Illinois Basin	135.5	30.2	165.7
San Juan Basin	41.1	3.8	44.9
Total	657.4	169.4	826.8

The following table sets forth PVR’s coal reserve activity for each of its coal properties for the years ended December 31, 2008, 2007 and 2006:

	Year ended December 31,
Property	2008		2007		2006
(tons in millions)
Reserves—beginning of year	818.4		765.4		689.1
Purchase of coal reserves	34.6		60.0		96.2
Tons mined by lessees	(33.7	)	(32.5	)	(32.8	)
Revisions of estimates and other	7.5		25.5		12.9
Reserves—end of year	826.8		818.4		765.4

Other natural resource management assets

Coal preparation and loading facilities

PVR generates coal services revenues from fees it charges to its lessees for the use of its coal preparation and loading facilities, which are located in Virginia, West Virginia and Kentucky. The facilities provide efficient methods to enhance lessee production levels and exploit PVR’s reserves.

Timber and oil and gas royalty interests

PVR owns approximately 243,000 acres of forestland in Kentucky, Virginia and West Virginia. Approximately 26% of PVR’s forestland is located on the approximately 62,000 acres in West Virginia that PVR acquired in September 2007. See “Management’s discussion and analysis of financial condition and results of operations—Acquisitions and divestitures” for a discussion of PVR’s forestland acquisition. The balance of PVR’s forestland is located on properties that also contain its coal reserves.

PVR owns royalty interests in approximately 10.9 Bcfe of proved oil and gas reserves located on approximately 56,000 acres in Kentucky, Virginia and West Virginia. Approximately 85% of PVR’s oil and gas royalty interests are associated with the leases of property in eastern Kentucky and southwestern Virginia that PVR acquired from us in October 2007. See “Management’s discussion and analysis of financial condition and results of operations—Acquisitions and divestitures” for a discussion of PVR’s oil and gas royalty interest acquisition.

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Natural gas midstream systems

PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. PVR owns, leases or has rights-of-way to the properties where the majority of its natural gas midstream facilities are located. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

PVR owned five natural gas processing facilities having 300 MMcfd of total capacity as of December 31, 2008. PVR’s natural gas midstream operations currently include four natural gas gathering and processing systems and two stand-alone natural gas gathering systems, including: (i) the Panhandle gathering and processing facilities in the Texas/Oklahoma panhandle area; (ii) the Crossroads gathering and processing facilities in East Texas; (iii) the Crescent gathering and processing facilities in central Oklahoma; (iv) the Arkoma gathering system in eastern Oklahoma; (v) the North Texas gathering and pipeline facilities in the Fort Worth Basin; and (vi) the Hamlin gathering and processing facilities in west-central Texas. These assets included approximately 4,069 miles of natural gas gathering pipelines as of December 31, 2008. In addition, PVR owns a 25% member interest in Thunder Creek, a joint venture that gathers and transports CBM in Wyoming’s Powder River Basin.

The following table sets forth information regarding PVR’s natural gas midstream assets:

					Year ended December 31, 2008
Asset	Type	Approximate length	Approximate wells connected	Current processing capacity	Average system throughput		Utilization of processing capacity
		(miles)		(MMcfd)	(MMcfd)		(%)
Panhandle system	Gathering pipelines and processing facility	1,648	1,037	160	181.0	(1)	100%
Crossroads system	Gathering pipelines and processing facility	8	—	80	36.0		45%
Crescent system	Gathering pipelines and processing facility	1,698	850	40	22.5		56%
Hamlin system	Gathering pipelines and processing facility	506	243	20	6.3		32%
Arkoma system	Gathering pipelines	78	81	—	14.0	(2)
North Texas system	Gathering pipelines	131	39	—	10.0	(2)
Total		4,069	2,250	300	269.8

(1) Includes gas processed at other systems connected to the Panhandle System via the pipeline acquired in June 2006.

(2) Gathering only volumes.

Commodity derivative contracts

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.

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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 “Management’s discussion and analysis of financial condition and results of operations—Quantitative and qualitative disclosures about market risk—Price risk.” 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 quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of the end of the relevant period. 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.

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 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.

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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 “Management’s discussion and analysis of financial condition and results of operations—Quantitative and qualitative disclosures about market risk—Price risk.” 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.

See note 8 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a further description of our and PVR’s derivative programs.

PVG and PVR distributions

PVG cash distributions

PVG paid cash distributions of $1.40 per common unit during the year ended December 31, 2008. In the first and second quarters of 2009, PVG paid cash distributions of $0.38 ($1.52 on an annualized basis) per common unit with respect to the fourth quarter of 2008 and the first quarter of 2009. These distributions were unchanged from the previous distribution paid on November 19, 2008. For the remainder of 2009, PVG expects to pay quarterly cash distributions of at least $0.38 ($1.52 on an annualized basis) per common unit.

PVR cash distributions

PVR paid cash distributions of $1.82 per common unit during the year ended December 31, 2008. In the first and second quarters of 2009, PVR paid cash distributions of $0.47 ($1.88 on an annualized basis) per common unit with respect to the fourth quarter of 2008 and the first quarter of 2009. These distributions were unchanged from the previous distribution paid on November 14, 2008. For the remainder of 2009, PVR expects to pay quarterly cash distributions of at least $0.47 ($1.88 on an annualized basis) per common unit.

PVR incentive distribution rights

In accordance with PVR’s partnership agreement, incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of PVR’s available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. The minimum quarterly distribution is $0.25 ($1.00 on an annualized basis) per unit. PVR’s general partner currently holds 100% of the incentive distribution rights, but may transfer these rights separately from its general partner interest to an affiliate (other than an individual) or to another entity as part of the merger or consolidation of PVR’s general partner with or into such entity or the transfer of all or substantially all of PVR’s general partner’s assets to another entity without the prior approval of PVR’s unitholders if the transferee agrees to be bound by the provisions of PVR’s partnership agreement. Prior to September 30, 2011, other

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transfers of the incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding PVR common units. On or after September 30, 2011, the incentive distribution rights will be freely transferable. The incentive distribution rights are payable as follows:

If for any quarter:

• PVR has distributed available cash from operating surplus to its common unitholders in an amount equal to the minimum quarterly distribution; and

• PVR has distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, PVR will distribute any additional available cash from operating surplus for that quarter among the unitholders and its general partner in the following manner:

• First, 98% to all unitholders, and 2% to PVR’s general partner, until each unitholder has received a total of $0.275 per unit for that quarter;

• Second, 85% to all unitholders, and 15% to PVR’s general partner, until each unitholder has received a total of $0.325 per unit for that quarter;

• Third, 75% to all unitholders, and 25% to PVR’s general partner, until each unitholder has received a total of $0.375 per unit for that quarter; and

• Thereafter, 50% to all unitholders and 50% to PVR’s general partner.

Since 2001, PVR has increased its quarterly cash distribution from $0.25 ($1.00 on an annualized basis) per unit to $0.47 ($1.88 on an annualized basis) per unit, which is its most recently declared distribution. These increased cash distributions by PVR have placed PVG, as the owner of PVR’s general partner, at the maximum target cash distribution level as described above and, as a consequence, since reaching such level, PVG, as the owner of PVR’s general partner, has received 50% of available cash in excess of $0.375 per unit.

Cash distributions received

In conjunction with the initial public offering of PVG, we contributed our general partner interest, incentive distribution rights and most of our limited partner interest in PVR to PVG in exchange for the general partner interest and a limited partner interest in PVG. We are currently entitled to receive quarterly cash distributions from PVG and PVR on our limited partner interests in PVG and PVR. As a result of our partner interest in PVG and PVR, we received total distributions from PVG and PVR of $11.6 million and $10.4 million in the three months ended March 31, 2009 and 2008 and $44.0 million and $29.8 million in the years ended December 31, 2008 and 2007 as shown in the following table:

	Three months ended March 31,		Year ended December 31,
($ in thousands)	2009	2008	2008	2007
Penn Virginia GP Holdings, L.P.	$11,429	$10,268	$43,435	$29,200
Penn Virginia Resource Partners, L.P.(1)	127	164	583	640
Total	$11,556	$10,432	$44,018	$29,840

(1) Includes PVR distributions for restricted units held by employees and directors.

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We have historically received increasing distributions from our partner interests in PVG and PVR. Based on PVG’s and PVR’s current annualized distribution rates of $1.52 and $1.88 per unit, we would receive aggregate annualized distributions of $46.3 million in respect of our partner interests in the year ended December 31, 2009. As a result of PVR’s 2008 unit offering, we recognized a gain in shareholders’ equity and PVG recognized gains in its partners’ capital. See note 3 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a summary of significant accounting policies and note 6 in the notes to our audited consolidated financial statements included elsewhere in this prospectus supplement for a description of the PVR unit offering.

Prior to PVG’s initial public offering in December 2006, we indirectly owned common units representing an approximate 37% limited partner interest in PVR, as well as the sole 2% general partner interest and all of the incentive distribution rights in PVR. We received total distributions from PVR of $28.6 million in 2006, allocated among our limited partner interest, general partner interest and incentive distribution rights as shown in the following table:

($ in thousands)	Year ended December 31, 2006
Limited partner interest	$23,039
General partner interest (2%)	1,254
Incentive distribution rights	4,273
Total	$28,566

Competition

Oil and gas segment

The oil and natural gas industry is very competitive, and we compete with a substantial number of other companies that are large, well-established and have greater financial and operational resources than we do, which may adversely affect our ability to compete or grow our business. Many such companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also carry on refining operations, electricity generation and the marketing of refined products. Competition is particularly intense in the acquisition of prospective oil and natural gas properties and oil and gas reserves. Our competitive position depends on our geological, geophysical and engineering expertise, our financial resources, our ability to develop properties and our ability to select, acquire and develop proved reserves. We compete with other oil and natural gas companies to secure drilling rigs and other equipment necessary for the drilling and completion of wells and recruiting and retaining qualified personnel, including geologists, geo-physicists, engineers and other specialists. Such equipment and labor may be in short supply from time to time. Shortages of equipment, labor or materials may result in increased costs or the inability to obtain such resources as needed. We also compete with major and independent oil and gas companies in the marketing and sale of oil and natural gas, and the oil and natural gas industry in general competes with other industries supplying energy and fuel to industrial, commercial and individual consumers.

PVR coal and natural resource management segment

The coal industry is intensely competitive primarily as a result of the existence of numerous producers. PVR’s lessees compete with both large and small coal producers in various regions of

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the United States for domestic sales. The industry has undergone significant consolidation which has led to some of the competitors of PVR’s lessees having significantly larger financial and operating resources than most of PVR’s lessees. PVR’s lessees compete on the basis of coal price at the mine, coal quality (including sulfur content), transportation cost from the mine to the customer and the reliability of supply. Continued demand for PVR’s coal and the prices that PVR’s lessees obtain are also affected by demand for electricity, demand for metallurgical coal, access to transportation, environmental and government regulations, technological developments and the availability and price of alternative fuel supplies, including nuclear, natural gas, oil and hydroelectric power. Demand for PVR’s low sulfur coal and the prices PVR’s lessees will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances which permit the high sulfur coal to meet CAA requirements.

PVR natural gas midstream segment

PVR experiences competition in all of its natural gas midstream markets. PVR’s competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, process, transport and market natural gas. Many of PVR’s competitors have greater financial resources and access to larger natural gas supplies than PVR does.

The ability to offer natural gas producers competitive gathering and processing arrangements and subsequent reliable service is fundamental to obtaining and keeping gas supplies for PVR’s gathering systems. The primary concerns of the producer are:

• the pressure maintained on the system at the point of receipt;

• the relative volumes of gas consumed as fuel and lost;

• the gathering/processing fees charged;

• the timeliness of well connects;

• the customer service orientation of the gatherer/processor; and

• the reliability of the field services provided.

Government regulation and environmental matters

The operations of our oil and gas business and PVR’s coal and natural resource management business and PVR’s natural gas midstream business are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted.

Oil and gas segment

State regulatory matters.    Various aspects of our oil and natural gas operations are regulated by administrative agencies under statutory provisions of the states where such operations are conducted. All of the jurisdictions in which we own or operate producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas. These provisions include permitting regulations regarding the drilling of wells, maintaining bonding requirements to drill or operate wells, locating wells, the method of

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drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area and the unitization or pooling of crude oil and natural gas properties. In addition, state conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. The effect of these regulations is to limit the amounts of crude oil and natural gas we can produce from our wells and to limit the number of wells or the locations at which we can drill.

Federal Energy Regulatory Commission.    The FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the NGA, and the Natural Gas Policy Act of 1978, or the NGPA. In the past, the federal government has regulated the prices at which oil and gas could be sold. The Natural Gas Wellhead Decontrol Act of 1989 removed all NGA and NGPA price and nonprice controls affecting producers’ wellhead sales of natural gas effective January 1, 1993. While sales by producers of their own natural gas production and all sales of crude oil, condensate and NGLs can currently be made at market prices, Congress could reenact price controls in the future.

Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and 636-C, or Order No. 636, which require interstate pipelines to provide transportation separate, or “unbundled,” from the pipelines’ sale of gas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis that is equal for all gas supplies. Although Order No. 636 does not directly regulate gas producers like us, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations. In particular, the FERC has issued Order Nos. 637, 637-A and 637-B which, among other things, (i) permit pipelines to charge different maximum cost-based rates for peak and off-peak periods, (ii) encourage auctions for pipeline capacity, (iii) require pipelines to implement imbalance management services and (iv) restrict the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow orders.

The Energy Policy Act of 2005 amended the NGA and the NGPA and gave the FERC the authority to assess civil penalties of up to $1 million per day per violation for violations of rules, regulations and orders issued under these acts. In addition, the FERC has issued regulations that make it unlawful for any entity in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of the FERC to use any manipulative or deceptive device or contrivance.

While any additional FERC action on these matters would affect us only indirectly, these changes are intended to further enhance competition in, and prevent manipulation of, natural gas markets. We cannot predict what further action the FERC will take on these matters, nor can we predict whether the FERC’s actions will achieve its stated goal of increasing competition in, and preventing manipulation of, natural gas markets. However, we do not believe that we will be treated materially differently than other natural gas producers with which we compete.

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

OSHA. We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.

PVR coal and natural resource management segment

General regulation applicable to coal lessees.    PVR’s lessees are obligated to conduct mining operations in compliance with all applicable federal, state and local laws and regulations. These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation and restoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining, water pollution, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife protection, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws and management of electrical equipment containing polychlorinated biphenyls, or PCBs. These extensive and comprehensive regulatory requirements are closely enforced, PVR’s lessees regularly have on-site inspections and violations during mining operations are not unusual in the industry, notwithstanding compliance efforts by PVR’s lessees. However, none of the violations to date, or the monetary penalties assessed, have been material to us, PVR or, to our knowledge, to PVR’s lessees. Although many new safety requirements have been instituted recently, PVR does not currently expect that future compliance will have a material adverse effect on PVR.

While it is not possible to quantify the costs of compliance by PVR’s lessees with all applicable federal, state and local laws and regulations, those costs have been and are expected to continue to be significant. The lessees post performance bonds pursuant to federal and state mining laws

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and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. We do not accrue for such costs because PVR’s lessees are contractually liable for all costs relating to their mining operations, including the costs of reclamation and mine closure. However, PVR does require some smaller lessees to deposit into escrow certain funds for reclamation and mine closure costs or post performance bonds for these costs. Although we believe that the lessees typically accrue adequate amounts for these costs, their future operating results would be adversely affected if they later determined these accruals to be insufficient. Compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers.

In addition, the utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities which could affect demand for coal mined by PVR’s lessees. The possibility exists that new legislation or regulations may be adopted which have a significant impact on the mining operations of PVR’s lessees or their customers’ ability to use coal and may require PVR, its lessees or their customers to change operations significantly or incur substantial costs.

Air emissions.    The CAA and corresponding state and local laws and regulations affect all aspects of PVR’s business, both directly and indirectly. The CAA directly impacts PVR’s lessees’ coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants. There have been a series of recent federal rulemakings that are focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and additional measures required under Environmental Protection Agency, or EPA, laws and regulations will make it more costly to build and operate coal-fired power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel alternative in the planning and building of power plants in the future. Any reduction in coal’s share of power generating capacity could negatively impact PVR’s lessees’ ability to sell coal, which could have a material effect on PVR’s coal royalties revenues.

The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels.

The EPA has promulgated rules, referred to as the “NOx SIP Call,” that require coal-fired power plants and other large stationary sources in 21 eastern states and Washington D.C. to make substantial reductions in nitrogen oxide emissions in an effort to reduce the impacts of ozone transport between states. Additionally, in March 2005, the EPA issued the final Clean Air Interstate Rule, or CAIR, which would have permanently capped nitrogen oxide and sulfur dioxide emissions in 28 eastern states and Washington, D.C. beginning in 2009 and 2010. CAIR required those states to achieve the required emission reductions by requiring power plants to

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either participate in an EPA-administered “cap-and-trade” program that caps emission in two phases, or by meeting an individual state emissions budget through measures established by the state. The stringency of the caps under CAIR may have required many coal-fired sources to install additional pollution control equipment, such as wet scrubbers, to comply. This increased sulfur emission removal capability required by CAIR could have resulted in decreased demand for lower sulfur coal, which may have potentially driven down prices for lower sulfur coal. On July 11, 2008, the D.C. Circuit Court of Appeals vacated CAIR in its entirety. The EPA subsequently filed a petition for rehearing or, in the alternative, for a remand of the case without vacatur. On December 23, 2008, the Court issued an opinion to remand without vacating CAIR. Therefore, CAIR will remain in effect while the EPA conducts rulemaking to modify CAIR to comply with the Court’s July 2008 opinion. The Court declined to impose a schedule by which the EPA must complete the rulemaking, but reminded the EPA that the Court does “not intend to grant an indefinite stay of the effectiveness of this Court’s decision.” The EPA is considering its options on how to proceed.

In March 2005, the EPA finalized the Clean Air Mercury Rule, or CAMR, which was to establish a two-part, nationwide cap on mercury emissions from coal-fired power plants beginning in 2010. It was the subject of extensive controversy and litigation and, in February 2008, the U.S. Circuit Court of Appeals for the District of Columbia vacated CAMR. The EPA appealed the decision to the U.S. Supreme Court in October 2008, but withdrew its petition for certiorari on February 6, 2009. However, a utility group continues to seek certiorari, challenging the court of appeals decision to overturn CAMR. In the meantime, the EPA plans to develop standards consistent with the court of appeal’s ruling. In addition, various states have promulgated or are considering more stringent emission limits on mercury emissions from coal-fired electric generating units.

The EPA has adopted new, more stringent national air quality standards for ozone and fine particulate matter. As a result, some states will be required to amend their existing state implementation plans to attain and maintain compliance with the new air quality standards. In March 2007, the EPA published final rules addressing how states would implement plans to bring regions designated as non-attainment for fine particulate matter into compliance with the new air quality standard. Under the EPA’s final rule, states had until April 2008 to submit their implementation plans to the EPA for approval. Because coal mining operations and coal-fired electric generating facilities emit particulate matter, PVR’s lessees’ mining operations and their customers could be affected when the new standards are implemented by the applicable states.

Likewise, the EPA’s regional haze program to improve visibility in national parks and wilderness areas required affected states to develop implementation plans by December 2007 that, among other things, identify facilities that will have to reduce emissions and comply with stricter emission limitations. This program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas. In addition, this program may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide and particulate matter.

The U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the new source review provisions of the CAA. The EPA has alleged that certain modifications have been made to these facilities without first obtaining permits required under the new source review program. Several of these lawsuits have settled, but others remain pending. On April 2, 2007, the U.S. Supreme Court ruled in one such case, Environmental Defense v. Duke Energy Corp. The Court held that the EPA is not required to use an “hourly rate test” in determining whether a modification to a coal burning

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utility requires a permit under the new source review program, thus allowing the EPA to apply a test based on average annual emissions. The use of an annual emissions test could subject more coal-fired utility modification projects to the permitting requirements of the CAA New Source Review Program, such as those that allow plants to run for more hours in a given year. However, Duke is expected to continue to contest remaining issues in the case, and so litigation in this and other pending cases will likely continue. Depending on the ultimate resolution of these cases, demand for PVR’s coal could be affected, which could have an adverse effect on PVR’s coal royalties revenues.

Carbon dioxide emissions.    The Kyoto Protocol to the United Nations Framework Convention on Climate Change calls for developed nations to reduce their emissions of greenhouse gases to 5% below 1990 levels by 2012. Carbon dioxide, which is a major byproduct of the combustion of coal and other fossil fuels, is subject to the Kyoto Protocol. The Kyoto Protocol went into effect on February 16, 2005 for those nations that ratified the treaty. In 2002, the United States withdrew its support for the Kyoto Protocol, and the United States is not participating in this treaty. Since the Kyoto Protocol became effective, there has been increasing international pressure on the United States to adopt mandatory restrictions on carbon dioxide emissions. In addition, on April 2, 2007 the U.S. Supreme Court held in Massachusetts v. EPA that unless the EPA affirmatively concludes that greenhouse gases are not causing climate change, the EPA must regulate greenhouse gas emissions from new automobiles under the CAA. The Court remanded the matter to the EPA for further consideration. This litigation did not directly concern the EPA’s authority to regulate greenhouse gas emissions from stationary sources, such as coal mining operations or coal-fired power plants. However, the Court’s decision is likely to influence another lawsuit currently pending in the U.S. Court of Appeals for the District of Columbia Circuit, involving a challenge to the EPA’s decision not to regulate carbon dioxide from power plants and other stationary sources under a CAA new source performance standard rule, which specifies emissions limits for new facilities. The court remanded that question to the EPA for further consideration in light of the ruling in Massachusetts v. EPA. On July 11, 2008, the EPA released an advanced notice of proposed rulemaking to regulate greenhouse gases under the CAA in response to the ruling in Massachusetts v. EPA. The notice did not contain a definitive proposal of what a greenhouse gas regulatory program would look like, but it presented the EPA’s analyses and policy alternatives for consideration. The EPA stated that promulgating a program under the CAA would take years to issue. Any decision in this case or any regulatory action by the EPA limiting greenhouse gas emissions from power plants could impact the demand for PVR’s coal, which could have an adverse effect on PVR’s coal royalties revenues.

The permitting of a number of proposed new coal-fired power plants has also recently been contested by environmental organizations for concerns related to greenhouse gas emissions from new plants. For instance, in October 2007, state regulators in Kansas became the first to deny an air emissions construction permit for a new coal-fired power plant based on the plant’s projected emissions of carbon dioxide. State regulatory authorities in Florida and North Carolina have also rejected the construction of new coal-fired power plants based on the uncertainty surrounding the potential costs associated with greenhouse gas emissions from these plants under future laws limiting the emission of carbon dioxide.

In addition, permits for several new coal-fired power plants without limits imposed on their greenhouse gas emissions have been appealed by environmental organizations to the EPA’s Environmental Appeals Board, or EAB, and other judicial forums under the CAA. For example, in June 2008, a Georgia court voided a CAA permit and halted the construction of a coal-fired

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power plant for failure to address carbon dioxide emissions. Likewise, in November 2008, in another case, In re Deseret Power Electric Cooperative, the EAB remanded the permitting decision back to the Region to reopen the record and reconsider whether carbon dioxide is a pollutant subject to regulation under the CAA with instructions to consider its nationwide implications. In December 2008, the EPA Administrator issued an interpretive rule determining that phrase in the CAA “not subject to regulation” does not include pollutants for which only monitoring and reporting is required. Because carbon dioxide is such a pollutant, this interpretive rule has the effect of precluding any consideration of carbon dioxide emissions in connection with federal permitting under the CAA. Environmental groups filed a Petition for Reconsideration of the interpretive rule. On February 17, 2009, the EPA stated that it would grant the Petition for Reconsideration and allow public comment, but it declined to stay the effectiveness of the interpretive rule at that time.

A number of states have also either passed legislation or announced initiatives focused on decreasing or stabilizing carbon dioxide emissions associated with the combustion of fossil fuels, and many of these measures have focused on emissions from coal-fired electric generating facilities. For example, ten northeastern and mid-Atlantic states have agreed to implement a regional cap-and-trade program, referred to as the Regional Greenhouse Gas Initiative, or RGGI, to stabilize carbon dioxide emissions from regional power plants beginning in 2009. This initiative aims to reduce emissions of carbon dioxide to levels roughly corresponding to average annual emissions between 2000 and 2004. The members of RGGI agreed to seek to establish in statute and/or regulation a carbon dioxide trading program and have each state’s component of the regional program effective no later than December 31, 2008. Auctions for carbon dioxide allowances under the program began in September 2008. Following the RGGI model, seven Western states and four Canadian provinces have also formed a regional greenhouse gas reduction initiative known as the Western Regional Climate Action Initiative, which calls for an overall reduction of regional greenhouse gas emissions from major industrial and commercial sources, including fossil-fuel fired power plants, in participating states through trading of emissions credits beginning in 2012. Similarly, in 2007, six Midwestern states and one Canadian province signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions, including developing a market-based, multi-sector cap. Some states have passed laws individually. For example, in 2006, the governor of California signed Assembly Bill 32 into law, requiring the California Air Resources Board to develop regulations and market mechanisms to reduce California’s greenhouse gas emissions by 25% by 2020 with mandatory caps beginning in 2012 for significant sources. In 2007, New Jersey passed a greenhouse gas reduction that would be economy wide, requiring emissions to drop to 1990 levels by 2020 and that emissions be capped at 80% of 2006 levels by 2050.

Several different pieces of legislation were introduced in Congress in 2007 and 2008 to reduce greenhouse gas emissions in the United States. Newly elected President Obama, stated in his campaign that climate change policy would be a priority of his administration, and the Democratic majority in Congress has indicated that it will seek to enact legislation to reduce greenhouse gas emissions. It is possible that future federal and state initiatives to control and put a price on carbon dioxide emissions could result in increased costs associated with coal consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for coal consumption could result in some customers switching to alternative sources of fuel, which could negatively impact PVR’s lessees’ coal sales, and thereby have an adverse effect on PVR’s coal royalties revenues.

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Surface Mining Control and Reclamation Act of 1977.    The Surface Mining Control and Reclamation Act of 1977, or SMCRA, and similar state statutes establish minimum national operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities. SMCRA also imposes on mine operators the responsibility of restoring the land to its original state and compensating the landowner for types of damages occurring as a result of mining operations, and requires mine operators to post performance bonds to ensure compliance with any reclamation obligations. Moreover, regulatory authorities may attempt to assign the liabilities of PVR’s coal lessees to another entity such as PVR if any of its lessees are not financially capable of fulfilling those obligations on the theory that PVR “owned” or “controlled” the mine operator in such a way for liability to attach. To our knowledge, no such claims have been asserted against PVR to date. In conjunction with mining the property, PVR’s coal lessees are contractually obligated under the terms of their leases to comply with all state and local laws, including SMCRA, with obligations including the reclamation and restoration of the mined areas by grading, shaping and reseeding the soil. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan. Additionally, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is 31.5 cents per ton on surface-mined coal and 13.5 cents per ton on underground-mined coal. This tax was set to expire on June 30, 2006, but the program was extended until September 30, 2021.

Federal and state laws require bonds to secure PVR’s lessees’ obligations to reclaim lands used for mining and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for mining companies to secure new surety bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable. It is possible that surety bonds issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Any failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on PVR’s lessees’ ability to produce coal, which could affect PVR’s coal royalties revenues.

Hazardous materials and wastes.    The Federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, or the Superfund law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources.

Some products used by coal companies in operations generate waste containing hazardous substances. PVR could become liable under federal and state Superfund and waste management statutes if its lessees are unable to pay environmental cleanup costs. CERCLA authorizes the EPA and, in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek recovery from the responsible classes of persons of the costs they

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incurred in connection with such response. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment. The Resource Conservation and Recovery Act, or RCRA, and corresponding state laws and regulations exclude many mining wastes from the regulatory definition of hazardous wastes. Currently, the management and disposal of coal combustion by-products are also not regulated at the federal level and not uniformly at the state level. If rules are adopted to regulate the management and disposal of these by-products, they could add additional costs to the use of coal as a fuel and may encourage power plant operators to switch to a different fuel.

Clean Water Act.    PVR’s coal lessees’ operations are regulated under CWA with respect to discharges of pollutants, including dredged or fill material into waters of the United States. Individual or general permits under Section 404 of the CWA are required to conduct dredge or fill activities in jurisdictional waters of the United States. Surface coal mining operators obtain these permits to authorize such activities as the creation of slurry ponds, stream impoundments and valley fills. Uncertainty over what legally constitutes a navigable water of the United States within the CWA’s regulatory scope may adversely impact the ability of PVR’s coal lessees to secure the necessary permits for their mining activities. Some surface mining activities require a CWA Section 404 “dredge and fill” permit under the CWA for valley fills and the associated sediment control ponds. On June 5, 2007, in response to the U.S. Supreme Court’s divided opinion in Rapanos v. United States, the EPA and the U.S. Army Corps of Engineers, or the Corps, issued joint guidance to EPA regions and Corps districts interpreting the geographic extent of regulatory jurisdiction under Section 404 of the CWA. Specifically, the guidance places jurisdictional water bodies into two groups: waters where the agencies will assert regulatory jurisdiction “categorically” and waters where the agencies will assert jurisdiction on a case-by-case basis following a “significant nexus analysis.” It remains to be seen how this guidance will affect the permitting process for obtaining additional permits for valley fills and sediment ponds although it is likely to add uncertainty and delays in the issuance of new permits. Some valley fill surface mining activities have the potential to impact headwater streams that are not relatively permanent, which could therefore trigger a detailed “significant nexus analysis” to determine whether a Section 404 permit would be required. Such analyses could require the extensive collection of additional field data and could lead to delays in the issuance of CWA Section 404 permits for valley fill surface mining operations.

Recent federal district court decisions in West Virginia, and related litigation filed in federal district court in Kentucky, have created additional uncertainty regarding the future ability to obtain certain general permits authorizing the construction of valley fills for the disposal of overburden from mining operations. The Corps is authorized by Section 404 of the CWA to issue “nationwide” permits for specific categories of dredging and filling activities that are similar in nature and that are determined to have minimal adverse environmental effects. Nationwide Permit 21 authorizes the disposal of dredged or fill material from surface coal mining activities into the waters of the United States. A July 2004 decision by the Southern District of West Virginia in Ohio Valley Environmental Coalition v. Bulen enjoined the Huntington District of the Corps from issuing further permits pursuant to Nationwide Permit 21. While the decision was vacated by the Fourth Circuit Court of Appeals in November 2005, it has been remanded to the District Court for the Southern District of West Virginia for further proceedings. Moreover, a similar lawsuit has been filed in the U.S. District Court for the Eastern District of Kentucky that seeks to enjoin the issuance of permits pursuant to Nationwide Permit 21 by the Louisville District of the Corps.

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In the event similar lawsuits prove to be successful in adjoining jurisdictions, PVR’s lessees may be required to apply for individual discharge permits pursuant to Section 404 of the CWA in areas where they would have otherwise utilized Nationwide Permit 21. Such a change could result in delays in PVR’s lessees obtaining the required mining permits to conduct their operations, which could in turn have an adverse effect on PVR’s coal royalties revenues.

Individual CWA Section 404 permits for valley fills associated with surface mining activities are also subject to certain legal challenges and uncertainty. On September 22, 2005, in the case Ohio Valley Environmental Coalition (“OVEC”) v. United States Army Corps of Engineers, environmental group plaintiffs filed suit in the U.S. District Court for the Southern District of West Virginia challenging the Corps’ decision to issue individual CWA Section 404 permits for certain mining projects. Alex Energy, Inc., or Alex Energy, a lessee of PVR that operates the Republic No. 2 Mine in Kanawha County, West Virginia, intervened as a defendant in this litigation when the plaintiffs’ amended their complaint to add the December 22, 2005 individual CWA Section 404 permit for the Republic No. 2 Mine, or the Republic No. 2 Permit. On March 23, 2007, the district court rescinded several challenged CWA Section 404 permits, including the Republic No. 2 Permit, and remanded the permit applications to the Corps for further proceedings. In addition, the district court enjoined the permit holders, including Alex Energy, from all activities authorized under the rescinded permits. As part of the OVEC litigation, the environmental groups have also challenged the CWA Section 404 permit issued to Alex Energy for the Republic No. 1 Mine, also located in Kanawha County, West Virginia.

The Corps, Alex Energy, other impacted mining companies, and mining associations appealed the March 23, 2007 ruling to the U.S. Court of Appeals for the Fourth Circuit. On February 13, 2009, the Fourth Circuit reversed and vacated the District Court’s March 23, 2007 opinion and order that had rescinded the challenged permits and vacated the District Court’s injunction of activity under those permits and reversed a related order by the District Court that would have required yet additional permits under the CWA. One of the three judges dissented from this decision and would have upheld the decision rescinding the permits and enjoining future activity but agreed with the other two judges on the other parts of the decision. This decision may be subject to further appellate review including by the Fourth Circuit itself. We are unable to predict the outcome of any further appellate review that may be obtained.

In December 2007, plaintiff environmental groups brought a similar suit against the issuance of a CWA Section 404 permit for a surface coal mine in the U.S. District Court for the Eastern District of Kentucky, alleging identical violations. The Corps has voluntarily suspended its consideration of the permit application in that case for agency re-evaluation. While the final outcome of these cases remains uncertain, if lawsuits challenging the use of valley fills ultimately limits or prohibits the mining methods or operations of PVR’s lessees, it could have an adverse effect on PVR’s coal royalties revenues. In addition, it is possible that similar litigation affecting recently issued, pending or future individual or general CWA Section 404 permits relevant to the mining and related operations of PVR’s lessees could adversely impact PVR’s coal royalties revenues.

In December 2008, the Department of Interior published the Excess Spoil, Coal Mine Waste and Buffers for Perennial and Intermittent Streams rule under SMCRA in part to clarify when valley fills are permitted. The rule would require a 100-foot buffer around all waters, including streams, lakes, ponds and wetlands. However, the rule would exempt certain activities, such as permanent spoil fills and coal waste disposal facilities, and allow mining that changes a waterway’s flow, providing the mining company repairs damage later. Companies could also receive a permit to dispose of waste within the buffer zone if they explain why an alternative is not reasonably

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possible or is not necessary to meet environmental requirements. Environmental groups have brought lawsuits challenging the rule. It is unclear what impact the rule will have on the previously discussed lawsuits related to valley fills or any mining operations undertaken by PVR’s lessees in the future.

Total Maximum Daily Load, or TMDL, regulations under the CWA establish a process to calculate the maximum amount of a pollutant that a water body can receive and still meet state water quality standards and to allocate pollutant loads among the point- and non-point pollutant sources discharging into that water body. This process applies to those waters that states have designated as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, discharging to such waters will be required to meet new TMDL allocations for these stream segments. The adoption of new TMDL-related allocations for streams to which PVR’s lessees’ coal mining operations discharge could require more costly water treatment and could adversely affect PVR’s lessees’ coal production.

The CWA also requires states to develop anti-degradation policies to ensure non-impaired water bodies in the state do not fall below applicable water quality standards. These and other regulatory developments may restrict PVR’s lessees’ ability to develop new mines or could require PVR’s lessees to modify existing operations, which could have an adverse effect on PVR’s coal business.

The Safe Drinking Water Act, or the SDWA, and its state equivalents affect coal mining operations by imposing requirements on the underground injection of fine coal slurries, fly ash and flue gas scrubber sludge, and by requiring permits to conduct such underground injection activities. In addition to establishing the underground injection control program, the SDWA also imposes regulatory requirements on owners and operators of “public water systems.” This regulatory program could impact PVR’s lessees’ reclamation operations where subsidence or other mining-related problems require the provision of drinking water to affected adjacent homeowners.

Endangered Species Act.    The Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying PVR’s lessees from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to areas where PVR’s properties are located are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect PVR’s lessees’ ability to mine coal from PVR’s properties in accordance with current mining plans.

Mine health and safety laws.    The operations of PVR’s coal lessees are subject to stringent health and safety standards that have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive health and safety standards on all mining operations. In addition, as part of the Mine Health and Safety Acts of 1969 and 1977, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease.

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Recent mining accidents in West Virginia and Kentucky have received national attention and instigated responses at the state and national level that are likely to result in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. In January 2006, West Virginia passed a law imposing stringent new mine safety and accident reporting requirements and increased civil and criminal penalties for violations of mine safety laws. On March 7, 2006, New Mexico Governor Bill Richardson signed into law an expanded miner safety program including more stringent requirements for accident reporting and the installation of additional mine safety equipment at underground mines. Similarly, on April 27, 2006, Kentucky Governor Ernie Fletcher signed mine safety legislation that includes requirements for increased inspections of underground mines and additional mine safety equipment and authorizes the assessment of penalties of up to $5,000 per incident for violations of mine ventilation or roof control requirements.

On June 15, 2006, the President signed the “Miner Act,” which was new mining safety legislation that mandates improvements in mine safety practices, increases civil and criminal penalties for non-compliance, requires the creation of additional mine rescue teams and expands the scope of federal oversight, inspection and enforcement activities. Pursuant to the Miner Act, the Mine Safety Health Administration, or MSHA, has promulgated new emergency rules on mine safety and revised MSHA’s civil penalty assessment regulations, which resulted in an across-the-board increase in penalties from the existing regulations. These requirements may add significant costs to PVR’s lessees’ operations, particularly for underground mines, and could affect the financial performance of PVR’s lessees’ operations.

Implementing and complying with these new laws and regulations could adversely affect PVR’s lessees’ coal production and could therefore have an adverse effect on PVR’s coal royalties revenues.

Mining permits and approvals.    Numerous governmental permits or approvals are required for mining operations. In connection with obtaining these permits and approvals, PVR’s coal lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations.

Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations which have outstanding environmental violations. Although, like other coal companies, PVR’s lessees’ have been cited for violations in the ordinary course of business, to our knowledge, none of them have had one of their permits suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including PVR’s lessees, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically, PVR’s lessees submit the necessary permit applications between 12 and 24 months before they plan to begin mining a new area. In PVR’s experience, permits generally are approved within 12 months after a completed application is submitted. In

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the past, PVR’s lessees have generally obtained their mining permits without significant delay. PVR’s lessees have obtained or applied for permits to mine a majority of the reserves that are currently planned to be mined over the next five years. PVR’s lessees are also in the planning phase for obtaining permits for the additional reserves planned to be mined over the following five years. However, there are no assurances that they will not experience difficulty in obtaining mining permits in the future. See “—PVR coal and natural resource management segment—Clean Water Act.”

OSHA. PVR’s lessees and PVR’s own business are subject to OSHA. See “—Oil and gas segment—OSHA.”

PVR natural gas midstream segment

General regulation.    PVR’s natural gas gathering facilities generally are exempt from the FERC’s jurisdiction under the NGA, but FERC regulation nevertheless could significantly affect PVR’s gathering business and the market for its services. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines into which PVR’s gathering pipelines deliver. However, we cannot assure you that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

For example, the FERC will assert jurisdiction over an affiliated gatherer that acts to benefit its pipeline affiliate in a manner that is contrary to the FERC’s policies concerning jurisdictional services adopted pursuant to the NGA. In addition, natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that the FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. PVR’s gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. PVR’s gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on PVR’s natural gas midstream operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

In Texas, PVR’s gathering facilities are subject to regulation by the Texas Railroad Commission, which has the authority to ensure that rates, terms and conditions of gas utilities, including certain gathering facilities, are just and reasonable and not discriminatory. PVR’s operations in Oklahoma are regulated by the Oklahoma Corporation Commission, which prohibits PVR from charging any unduly discriminatory fees for its gathering services. We cannot predict whether PVR’s gathering rates will be found to be unjust, unreasonable or unduly discriminatory.

PVR is subject to ratable take and common purchaser statutes in Texas and Oklahoma. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting PVR’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and Texas and

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Oklahoma have adopted complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering rates and access. We cannot assure you that federal and state authorities will retain their current regulatory policies in the future.

Texas and Oklahoma administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, which requires certain natural gas pipelines to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. PVR also operates a NGL pipeline that is subject to regulation by the U.S. Department of Transportation under the Hazardous Liquids Pipeline Safety Act of 1979, as amended, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. In response to recent pipeline accidents, Congress and the U.S. Department of Transportation have instituted heightened pipeline safety requirements. Certain of PVR’s gathering facilities are exempt from these federal pipeline safety requirements under the rural gathering exemption. We cannot assure you that the rural gathering exemption will be retained in its current form in the future.

Failure to comply with applicable regulations under the NGA, the NGPSA and certain state laws can result in the imposition of administrative, civil and criminal remedies.

Air emissions.    PVR’s natural gas midstream operations are subject to the CAA and comparable state laws and regulations. See “—PVR coal and natural resource management segment.” These laws and regulations govern emissions of pollutants into the air resulting from the activities of PVR’s processing plants and compressor stations and also impose procedural requirements on how PVR conducts its natural gas midstream operations. Such laws and regulations may include requirements that PVR obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, strictly comply with the emissions and operational limitations of air emissions permits PVR is required to obtain or utilize specific equipment or technologies to control emissions. PVR’s failure to comply with these requirements could subject it to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. PVR will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

Hazardous materials and wastes.    PVR’s natural gas midstream operations could incur liability under CERCLA and comparable state laws resulting from the disposal or other release of hazardous substances or wastes originating from properties PVR owns or operates, regardless of whether such disposal or release occurred during or prior to PVR’s acquisition of such properties. See “—PVR coal and natural resource management segment—Hazardous materials and wastes.” Although petroleum, including natural gas and NGLs are generally excluded from CERCLA’s definition of “hazardous substance,” PVR’s natural gas midstream operations do generate wastes in the course of ordinary operations that may fall within the definition of a CERCLA “hazardous substance,” or be subject to regulation under state laws.

PVR’s natural gas midstream operations generate wastes, including some hazardous wastes, which are subject to RCRA and comparable state laws. However, RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy. Unrecovered petroleum product wastes, however, may still be regulated

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under RCRA as solid waste. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas and NGLs in pipelines may also generate some hazardous wastes. Although PVR believes that it is unlikely that the RCRA exemption will be repealed in the near future, repeal would increase costs for waste disposal and environmental remediation at PVR’s facilities.

PVR currently owns or leases numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although PVR believes that the operators of such properties used operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under such properties or on or under other locations where such wastes have been taken for disposal. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, PVR could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination, whether from prior owners or operators or other historic activities or spills) or to perform remedial plugging or pit closure operations to prevent future contamination. PVR has ongoing remediation projects underway at several sites, but it does not believe that the costs associated with such cleanups will have a material adverse impact on PVR’s operations or revenues.

Water discharges.    PVR’s natural gas midstream operations are subject to the CWA. See “—PVR coal and natural resource management segment—Clean Water Act.” Any unpermitted release of pollutants, including NGLs or condensates, from PVR’s systems or facilities could result in fines or penalties as well as significant remedial obligations.

OSHA.    PVR’s natural gas midstream operations are subject to OSHA. See “—Oil and gas segment—OSHA.”

Employees and labor relations

We and our subsidiaries had a total of 397 employees at May 31, 2009, including 165 employees who directly supported PVR’s operations. We consider our current employee relations to be favorable.

Legal proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. See “—Government regulation and environmental matters” for a more detailed discussion of our material environmental obligations.

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Transactions with related persons

Relationship with PVG and PVR

PVG is a NYSE-listed limited partnership formed by us to hold the general partner interest, all of the incentive distribution rights and substantially all of our limited partner interests in PVR. PVG completed the initial public offering of its common units in December 2006. As of May 31, 2009, we indirectly held the non-economic general partner interest in PVG, as well as 30,077,429 common units representing, in the aggregate, a 77.0% limited partner interest in PVG.

PVR is a NYSE-listed limited partnership, which manages coal and natural resource properties and related assets and operates a natural gas midstream gathering and processing business. As of May 31, 2009, we indirectly held 51,178 common units representing an approximate 0.1% limited partner interest in PVR, and PVG indirectly held the sole 2% general partner interest and all of the incentive distribution rights in PVR and directly held 19,587,049 common units representing, in the aggregate, a 37.8% limited partner interest in PVR.

Transactions with PVG

In general, PVG pays quarterly cash distributions of all of its available cash to the holders of its common units. PVG’s available cash is its cash on hand at the end of the quarter after the payment of its expenses and the establishment of cash reserves for future capital expenditures and operational needs. We are entitled to distributions on our limited partner interests in PVG. In 2008, we received $43.4 million of distributions from PVG. In February 2009 and May 2009, we received distributions of $11.4 million and $11.4 million from PVG with respect to the fourth quarter of 2008 and the first quarter of 2009.

Transactions with PVR

Quarterly cash distributions by PVR.    The general partner of PVR, which is a wholly owned subsidiary of PVG, is entitled to distributions on its general partner interest in PVR, and we and PVG are entitled to distributions on our limited partner interests in PVR. In general, PVR pays quarterly cash distributions in the following manner:

• first, 98% to the common unitholders, pro rata, and 2% to the general partner of PVR, until PVR distributes for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

• second, 98% to the common unitholders, pro rata, and 2% to the general partner of PVR, until PVR distributes for each outstanding common unit an amount equal to any arrearages in the payment of the minimum quarterly distribution on the common units for any prior quarters; and

• thereafter, in the manner described in “—Incentive distribution rights” below.

The minimum quarterly distribution is $0.25.

Incentive distribution rights.    The general partner of PVR is also entitled to distributions payable with respect to incentive distribution rights. Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved.

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If for any quarter:

• PVR has distributed available cash from operating surplus to the common unitholders in an amount equal to the minimum quarterly distribution; and

• PVR has distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, PVR will distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner of PVR in the following manner:

• first, 98% to all unitholders, pro rata, and 2% to the general partner of PVR, until each unitholder has received a total of $0.275 per unit for that quarter;

• second, 85% to all unitholders, and 15% to the general partner of PVR, until each unitholder has received a total of $0.325 per unit for that quarter;

• third, 75% to all unitholders, and 25% to the general partner of PVR, until each unitholder has received a total of $0.375 per unit for that quarter; and

• thereafter, 50% to all unitholders and 50% to the general partner of PVR.

In 2008, PVG received total distributions, including incentive distributions, of $57.5 million from PVR, and we received total distributions of $0.2 million from PVR. In February 2009 and May 2009, PVG received total distributions, including incentive distributions, of $15.7 million and $15.7 million from PVR with respect to the fourth quarter of 2008 and the first quarter of 2009, and we received total distributions of $0.1 million and $0.1 million from PVR.

Shared management and administrative services.    In 2008, we provided administrative services to PVR and PVG and shared management and administrative personnel with PVR and PVG. These personnel operated our business and PVR’s and PVG’s businesses. As a result, certain of our NEOs as well as other Company personnel allocated the time they spent on our behalf and on behalf of PVR and PVG. Based on those allocations, PVR and PVG reimbursed us for a proportionate share of compensation and benefit expenses of employees and officers as well as other administrative and overhead expenses incurred by PVR and PVG in connection with services rendered to PVR and PVG. In the three months ended March 31, 2009 and the year ended December 31, 2008, aggregate reimbursements by PVG totaled approximately $1.7 million and $5.5 million, which included aggregate reimbursements by PVR of approximately $1.5 million and $5.1 million.

Units purchase agreement.    In connection with PVR’s acquisition of Lone Star, Penn Virginia Resource LP Corp., or LP Corp, and Kanawha Rail Corp., or KRC, each a wholly owned subsidiary of us, entered into a Units Purchase Agreement with PVR. Pursuant to the Units Purchase Agreement, LP Corp and KRC sold an aggregate of 2,009,995 common units of PVG to PVR for an aggregate purchase price of $61.8 million. PVR delivered such PVG common units to Lone Star in payment of a portion of the purchase price of the Lone Star acquisition.

Oil and gas marketing agreement.    Penn Virginia Oil & Gas, L.P., or PVOG LP, our wholly owned subsidiary, and Connect Energy Services, LLC, or Connect Energy, PVR’s wholly owned subsidiary, are parties to a Master Services Agreement effective September 1, 2006. Pursuant to the Master Services Agreement, PVOG LP and Connect have agreed that Connect will market all of PVOG LP’s oil and gas production in Arkansas, Louisiana, Oklahoma and Texas for a fee equal to 1% of the

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net sales price (subject to specified limitations) received by PVOG LP for such production. The Master Services Agreement has a primary term of five years and automatically renews for additional one year terms until terminated by either party. In the three months ended March 31, 2009 and the year ended December 31, 2008, PVOG LP paid Connect Energy $0.4 million and $3.0 million in fees pursuant to the Master Services Agreement.

Gas gathering and processing agreement.    PVOG LP and PVR East Texas Gas Processing LLC, or PVR East Texas, PVR’s wholly owned subsidiary, are parties to a Gas Gathering and Processing Agreement effective May 1, 2007. Pursuant to the Gas Gathering and Processing Agreement, PVOG LP and PVR East Texas have agreed that PVR East Texas will gather and process all of PVOG LP’s current and future gas production in certain areas of the Bethany Field in East Texas and redeliver the natural gas liquids to PVOG LP for a $0.30/MMBtu service fee (with an annual CPI adjustment). The Gas Gathering and Processing Agreement has a primary term of ending August 31, 2021 and automatically renews for additional one year terms until terminated by either party. PVR East Texas began gathering and processing PVOG LP’s gas in June 2008. In the three months ended March 31, 2009 and the year ended December 31, 2008, PVOG LP paid PVR East Texas $0.7 million and $2.0 million in fees pursuant to the Gas Gathering and Processing Agreement.

Gas sales arrangement.    From time to time, PVOG LP sells gas or NGLs to Connect Energy at PVR’s Crossroads Plant, and Connect Energy resells such gas or NGLs to third parties. The sales price received by PVOG LP from Connect Energy for such gas or NGLs equals the sales price received by Connect Energy for such gas or NGLs from the third parties. In the three months ended March 31, 2009 and the year ended December 31, 2008, PVOG LP received $21.2 million and $127.9 million from Connect Energy in connection with such sales.

Omnibus agreement.    We, the general partner of PVR, PVR and Penn Virginia Operating Co., LLC, a wholly owned subsidiary of PVR, are parties to an Omnibus Agreement that governs potential competition among us. The Omnibus Agreement was entered into in connection with PVR’s initial public offering in October 2001. Upon completion of PVG’s initial public offering in December 2006, PVG became subject to the Omnibus Agreement as an affiliate of us. For purposes of the Omnibus Agreement, any restrictions that apply to us also apply to PVG.

Under the Omnibus Agreement, we and our affiliates are not permitted to engage in the businesses of: (i) owning, mining, processing, marketing or transporting coal, (ii) owning, acquiring or leasing coal reserves or (iii) growing, harvesting or selling timber, unless we or they first offer PVR the opportunity to acquire these businesses or assets and the board of directors of the general partner of PVR, with the concurrence of its Conflicts Committee, elects to cause PVR not to pursue such opportunity or acquisition. In addition, we and our affiliates will be able to purchase any business which includes the purchase of coal reserves, timber or infrastructure relating to the production or transportation of coal if the majority value of such business is not derived from owning, mining, processing, marketing or transporting coal or growing, harvesting or selling timber. If we or our affiliates make any such acquisition, we or they must offer PVR the opportunity to purchase the coal reserves, timber or related infrastructure following the acquisition and the Conflicts Committee of PVR’s general partner will determine whether PVR should pursue the opportunity. The restriction will terminate upon a change of control of us or the general partner of PVR.

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Management

Executive officers and directors of the company

The following table sets forth certain information with respect to our executive officers and members of our board of directors.

Name	Age	Position
Edward B. Cloues, II	61	Director
A. James Dearlove	61	President and Chief Executive Officer and Director
Robert Garrett	72	Chairman of the Board of Directors
Keith D. Horton	55	Executive Vice President and Director
Ronald K. Page	58	Vice President
Marsha R. Perelman	59	Director
Frank A. Pici	53	Executive Vice President and Chief Financial Officer
William H. Shea, Jr.	54	Director
Nancy M. Snyder	56	Executive Vice President and Chief Administrative Officer, General Counsel and Corporate Secretary
Philippe van Marcke de Lummen	65	Director
H. Baird Whitehead	58	Executive Vice President and Chief Operating Officer
Gary K. Wright	64	Director

Edward B. Cloues, II, has served as a director since December 2001. Since January 1998, Mr. Cloues has served as Chairman of the Board and Chief Executive Officer of K-Tron International, Inc., a provider of material handling equipment and systems. From October 1979 to January 1998, Mr. Cloues was a partner of Morgan, Lewis & Bockius LLP, a global law firm. Mr. Cloues also serves as a director of Penn Virginia Resource GP, LLC, the general partner of PVR, and the non-executive Chairman of the Board of AMREP Corporation.

A. James Dearlove has served as our President and Chief Executive Officer since May 1996 and as a director since February 1996, as our President and Chief Operating Officer from 1994 to May 1996, as our Senior Vice President from 1992 to 1994 and as our Vice President from 1986 to 1992. Mr. Dearlove has also served as Chairman of the Board, President and Chief Executive Officer of PVG GP, LLC, the general partner of PVG, since September 2006 and as Chairman of the Board and Chief Executive Officer of Penn Virginia Resource GP, LLC since July 2001.

Robert Garrett has served as our non-executive Chairman of the Board since March 2000 and as a director since May 1997. From 1986 to present, Mr. Garrett has been President of Robert Garrett & Sons, Inc., a private investing and financial advisory company. Mr. Garrett served as Founder and Managing Director of AdMedia Partners, Inc., or AdMedia, an investment banking firm serving media, advertising and marketing services businesses, from 2005 to 2007. From 1990 to 2005, Mr. Garrett was President of AdMedia. Mr. Garrett also serves as a director of PVG GP, LLC.

Keith D. Horton has served as our Executive Vice President and as a director since December 2000, as Co-President and Chief Operating Officer—Coal of Penn Virginia Resource GP, LLC since June 2006, as President and Chief Operating Officer of Penn Virginia Resource GP, LLC from July 2001 to June 2006, as President of Penn Virginia Operating Co., LLC since September 2001, as our Vice President—Eastern Operations from February 1999 to December 2000, as our Vice President from February 1996 to February 1999, as President of Penn Virginia Coal Company from February 1996

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to October 2001, as Vice President of Penn Virginia Coal Company from March 1994 to February 1996, as Vice President of Penn Virginia Resources Corporation from January 1990 to December 1998 and as Manager, Coal Operations of Penn Virginia Resources Corporation from July 1982 to December 1989.

Ronald K. Page has served as our Vice President since May 2005 and as our Vice President, Corporate Development from July 2003 to May 2005. Mr. Page has also served as Co-President and Chief Operating Officer—Midstream of Penn Virginia Resource GP, LLC since May 2006 and as Vice President, Corporate Development of Penn Virginia Resource GP, LLC from July 2003 to May 2006. Mr. Page has also served as President of PVR Midstream LLC since January 2005. From January 1998 to May 2003, Mr. Page served in various positions with El Paso Field Services Company, including Vice President of Commercial Operations—Texas Pipelines and Processing from 2001 to 2003, Vice President of Business Development from 2000 to 2001 and Director of Business Development from 1999 to 2000.

Marsha R. Perelman has served as a director since October 1998. In 1993, Ms. Perelman founded, and since then has been the Chief Executive Officer of, Woodforde Management, Inc., a holding company. In 1983, she co-founded, and from 1983 to 1990 served as the President of, Clearfield Ohio Holdings, Inc., a gas gathering and distribution company. In 1983, she also co-founded, and from 1983 to 1990 served as Vice President of, Clearfield Energy, Inc., a crude oil gathering and distribution company. Ms. Perelman also serves as a director of Penn Virginia Resource GP, LLC.

Frank A. Pici has served as our Executive Vice President and Chief Financial Officer since September 2001. Mr. Pici has also served as Vice President and Chief Financial Officer and as a director of PVG GP, LLC since September 2006 and as Vice President and Chief Financial Officer and as a director of Penn Virginia Resource GP, LLC since September 2001 and October 2002. From 1996 to 2001, Mr. Pici served as Vice President—Finance and Chief Financial Officer of Mariner Energy, Inc., or Mariner, a Houston, Texas-based oil and gas exploration and production company, where he managed all financial aspects of Mariner, including accounting, tax, finance, banking, investor relations, planning and budgeting and information technology. From 1994 to 1996, Mr. Pici served as Corporate Controller of Cabot Oil & Gas Corporation, or Cabot, an oil and gas exploration and production company.

William H. Shea, Jr., has served as a director since July 2007. Mr. Shea served as the Chairman of Buckeye GP LLC, the general partner of Buckeye Partners, L.P., a refined petroleum products pipeline company from May 2004 to July 2007, as President and Chief Executive Officer of Buckeye GP LLC from September 2000 to July 2007 and as President and Chief Operating Officer of Buckeye GP LLC from July 1998 to September 2000. From August 2006 to July 2007, Mr. Shea served as Chairman of MainLine Management LLC, the general partner of Buckeye GP Holdings, L.P., and as President and Chief Executive Officer of MainLine Management LLC from May 2004 to July 2007. Mr. Shea also serves as a director of Kayne Anderson Energy Total Return Fund, Inc. and Kayne Anderson MLP Investment Company.

Nancy M. Snyder has served as our Executive Vice President since May 2006, as our Chief Administrative Officer since May 2008, as our Senior Vice President from February 2003 to May 2006, as our Vice President from December 2000 to February 2003 and as our General Counsel and Corporate Secretary since 1997. Ms. Snyder has also served as Vice President and General Counsel and as a director of PVG GP, LLC since September 2006 and as Chief Administrative Officer since 2008 and as Vice President and General Counsel and as a director of Penn Virginia Resource GP, LLC since July 2001 and as Chief Administrative Officer since May 2008.

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Philippe van Marcke de Lummen has served as a director since January 2006. Mr. van Marcke de Lummen has served as President of Universitas, Ltd., a manager of funds for the benefit of Belgian universities since 2007 and as its Secretary since 1995. Since 2004, Mr. van Marcke de Lummen has served as a private consultant. From 2005 to 2008, he served as an advisor to Cheniere Energy, Inc., a liquefied natural gas terminal business. From 2002 to 2004, he served as Chairman of Tractebel LNG Trading S.A., a global energy and services business. From 2001 to 2002, Mr. van Marcke de Lummen was Chief Executive Officer of Tractebel LNG Ltd. (London). From 1999 to 2001, he served as Executive Vice President, President of Strategy Committee and Head of Mergers and Acquisitions of Tractebel North America, Inc. Mr. van Marcke de Lummen is the founder of Tractebel Energy Marketing, Inc. and served as its Chief Executive Officer from 1996 to 1999. From 1990 to 1996, Mr. van Marcke de Lummen served as President of American Tractebel Corporation. Mr. van Marcke de Lummen currently serves as a director of Universitas, Ltd. and EXMAR N.V.

H. Baird Whitehead has served as our Executive Vice President since January 2001, as our Chief Operating Officer since February 2009 and as President of Penn Virginia Oil & Gas Corporation since January 2001. Prior to joining the Company, Mr. Whitehead served in various positions with Cabot. From 1998 to 2001, Mr. Whitehead served as Senior Vice President during which time he oversaw Cabot’s drilling, production and exploration activity in the Appalachian, Rocky Mountain, Mid-Continent and Texas and Louisiana Gulf Coast areas. From 1992 to 1998, Mr. Whitehead served as Vice President and Regional Manager of Cabot’s Appalachian business. From 1989 to 1992, Mr. Whitehead served as Vice President and Regional Manager of Cabot’s Anadarko business unit.

Gary K. Wright has served as a director since January 2003. From 2004 to present, Mr. Wright has been a consultant. Mr. Wright was President of LNB Energy Advisors, a provider of bank credit facilities and strategic advice to small to mid-sized oil and gas producers, from 2003 to 2004. Mr. Wright was an independent consultant to the energy industry from 2001 to 2003. From 1998 to 2001, Mr. Wright was North American Credit Deputy for the Global Oil and Gas Group of Chase Manhattan Bank. Mr. Wright was Managing Director and Senior Client Manager in the Southwest for the Global Oil and Gas Group of Chase Manhattan Bank from 1992 to 1998. Mr. Wright was Manager of the Chemical Bank Worldwide Energy Group from 1990 to 1992 and Manager of the Energy Group of Texas Commerce Bank from 1982 to 1987.

Policies regarding transactions with related persons

Under our Corporate Governance Principles, all directors must recuse themselves from any decision affecting their personal, business or professional interests. In addition, as a general matter, our practice is that all transactions with related persons are approved by disinterested directors. For example, with respect to any proposed transaction between us or any of our subsidiaries and PVG or PVR or any of their subsidiaries, any director of ours who serves as a director or executive officer of PVG’s general partner or PVR’s general partner would not vote on such proposed transaction. Our General Counsel advises our board of directors as to which transactions involve related persons and which directors are prohibited from voting on a particular transaction. All of the related transactions described in “Transactions with related persons” which were entered into since January 1, 2008 were approved in accordance with the foregoing policies and procedures.

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Description of other indebtedness

Our Revolver

As of March 31, 2009, we had $390.0 million outstanding under our Revolver, which is senior to the Convertible Notes. Our Revolver is governed by a borrowing base calculation and is redetermined semi-annually. In March 2009, our bank group completed the semi-annual re-determination. As a result, the borrowing base was revised to $450.0 million, which is approximately 6% less than its previous level of $479.0 million. In connection with this offering, we have entered into an amendment to our Revolver to permit the issuance of the notes.

On May 22, 2009, we completed the sale of 3,500,000 shares of our common stock in a registered public offering. The net proceeds of the sale were $64.9 million and were used to repay a portion of the outstanding borrowings under our Revolver. Assuming we had completed the issuance and sale of shares of our common stock at March 31, 2009 and on an as adjusted basis for the application of the net proceeds from the sale of shares of our common stock, we would have had $325.1 million outstanding under our Revolver (excluding $0.3 million of letters of credit) and would have been able to incur an additional $124.6 million under our Revolver. Assuming we had completed this offering and the May 2009 issuance and sale of shares of our common stock at March 31, 2009 and on an as further adjusted basis for the application of the estimated net proceeds from the sale of the notes, we would have had $             million outstanding under our Revolver (excluding $0.3 million of letters of credit) and would have been able to incur an additional $             million under our Revolver.

At the current $450.0 million limit on our Revolver, and given our outstanding balance of $390.0 million at March 31, 2009, net of $0.3 million of letters of credit outstanding, we could borrow up to $59.7 million at March 31, 2009. As a result of the issuance of the notes in this offering, the borrowing base under our Revolver will be automatically reduced to $382.0 million, which is approximately 11% less than the current level of $450.0 million. Our Revolver, which matures in December 2010, is secured by a portion of our proved oil and gas reserves. Our 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. In the three months ended March 31, 2009 and in the year ended December 31, 2008, we incurred commitment fees of $0.1 million and $0.8 million on the unused portion of our Revolver. The commitments, which can be redetermined relative to our borrowing base, cannot be withdrawn by the bank. We capitalized $0.4 million and $2.0 million of interest cost incurred in the three months ended March 31, 2009 and in the year ended December 31, 2008. We have the option to elect interest at (i) LIBOR plus a margin ranging from 2.00% to 3.00%, 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 2.125%. The weighted average interest rate on borrowings outstanding under our Revolver at March 31, 2009 and at December 31, 2008 was approximately 3.89% and 2.57% (after giving effect to the Interest Rate Swaps). We do not have a public credit rating for our Revolver.

The financial covenants under our Revolver require us not to exceed specified ratios. We are required to maintain a Debt-to-EBITDAX ratio of no more than 3.5-to-1.0, and at March 31, 2009 such ratio was 1.7-to-1.0, as compared to 1.5-to-1.0 at December 31, 2008. We are also required to maintain an EBITDAX-to-interest expense ratio of no less than 2.5-to-1.0, and at March 31, 2009 such ratio was 16.2-to-1.0, as compared to 21.8-to-1.0 at December 31, 2008. EBITDAX, which is a non-GAAP measure, is generally defined in our Revolver as our net income before the effects of interest expense, interest income, income tax expense, depreciation, depletion and

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amortization, or DD&A, expense, impairments, other similar non-cash charges, exploration expense, non-cash compensation expense and non-cash hedging activity. For covenant calculation purposes, EBITDAX is further adjusted for distributions received through our ownership in PVG and for dividends paid to shareholders. In addition, the financial covenants impose dividend limitation restrictions. Our 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 March 31, 2009 and December 31, 2008, we were in compliance with all of our covenants under our Revolver. We intend to apply the net proceeds of this offering to repay a portion of the outstanding borrowings under our Revolver.

In the event that we would be in default of our covenants, we could appeal to the banks for a waiver of the covenant default. Should the banks deny our appeal to waive the covenant default, the outstanding borrowings under our Revolver would become payable upon demand and would be reclassified to the current liabilities section of our consolidated balance sheet. Our Revolver contains cross-default provisions for default of indebtedness of more than $5.0 million. Our Revolver does not contain a subjective acceleration clause.

Our Convertible Notes, Note Hedges and Warrants

As of March 31, 2009, we had $230.0 million (excluding the discount of $28.5 million) of Convertible Notes outstanding. The Convertible Notes bear interest at a coupon rate of 4.50% per year payable semiannually in arrears on May 15 and November 15 of each year. We do not have a public credit rating for the Convertible Notes.

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

The holders of the Convertible Notes who convert their Convertible Notes in connection with a make-whole fundamental change, as defined in the indenture governing the Convertible Notes, may be entitled to an increase in the conversion rate as specified in the indenture governing the

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

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

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

Our Revolver Interest Rate Swaps

We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under our Revolver until December 2010. The notional amounts of the Interest Rate Swaps total $50.0 million, or approximately 13% of our total long-term debt outstanding under our Revolver at March 31, 2009. We will pay a weighted average fixed rate of 5.34% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the Interest Rate Swaps were recorded as interest expense. During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value and losses for the Interest Rate Swaps will be recognized as a component of derivatives in the income statement. After considering the applicable margins of 2.75% and 1.25% in effect as of March 31, 2009 and December 31, 2008, the total interest rate on the $50.0 million portion of Revolver borrowings covered by the Interest Rate Swaps was 8.09% at March 31, 2009 and 6.6% at December 31, 2008.

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PVR debt

The following is a discussion of PVR’s indebtedness. Indebtedness of PVR is not recourse to the Restricted Group and is structurally senior to the notes.

PVR Revolver

In March 2009, PVR increased the size of the PVR Revolver from $700.0 million to $800.0 million, which resulted in $9.3 million of debt issuance costs. The PVR Revolver is secured with substantially all of PVR’s assets. As of March 31, 2009, net of outstanding borrowings of $595.1 million and letters of credit of $1.6 million, PVR had remaining borrowing capacity of $203.3 million on the 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 the three months ended March 31, 2009 and the year ended December 31, 2008, PVR incurred commitment fees of $0.1 million and $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 1.25% 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 1.75% to 2.75% if PVR selects the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the PVR Revolver at March 31, 2009 and December 31, 2008 was approximately 3.75% and 4.39% (after giving effect to the PVR Interest Rate Swaps). 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. PVR is required to maintain a debt-to-consolidated EBITDA ratio of less than 5.25-to-1.0, and at March 31, 2009 such ratio was 3.37-to-1.0, as compared to 4.05-to-1.0 at December 31, 2008. PVR is also required to maintain a consolidated EBITDA-to-interest expense ratio of greater than 2.5-to-1.0, and at March 31, 2009, such ratio was 6.31-to-1.0, as compared to 4.74-to-1.0 at December 31, 2008. EBITDA, which is a non-GAAP measure, is generally defined in the PVR Revolver as PVR’s net income before the effects of interest expense, interest income, DD&A expense, impairments and other similar charges and non-cash hedging activity. 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 its subsidiaries. As of March 31, 2009 and December 31, 2008, PVR was in compliance with all of its covenants under the PVR Revolver.

In the event that PVR would be in default of its covenants, PVR could appeal to the banks for a waiver of the covenant default. Should the banks deny PVR’s appeal to waive the covenant default, the outstanding borrowings under the PVR Revolver would become payable upon demand and would be reclassified to the current liabilities section of our consolidated balance sheet. The PVR Revolver contains cross-default provisions for default of indebtedness of more than $7.5 million. The PVR Revolver does not contain a subjective acceleration clause. 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.

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PVR senior unsecured 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%.

PVR Revolver 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. During the first quarter of 2009, PVR discontinued hedge accounting for all of the PVR Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the PVR Interest Rate Swaps are recognized in earnings currently. Until March 2010, the notional amounts of the PVR Interest Rate Swaps total $310.0 million, or approximately 52% of PVR’s total long-term debt outstanding as of March 31, 2009, with PVR paying a weighted average fixed rate of 3.54% 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 $250.0 million with PVR paying a weighted average fixed rate of 3.37% 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 Interest Rate Swaps total $100.0 million, with PVR paying a weighted average fixed rate of 2.09% 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 seven financial institution counterparties, with no counterparty having more than 24% of the open positions. After considering the applicable margin of 2.00% in effect as of March 31, 2009, the total interest rate on the $310.0 million portion of PVR Revolver borrowings covered by the PVR Interest Rate Swaps was 5.54% at March 31, 2009. After considering the applicable margin of 1.75% in effect as of December 31, 2008, the total interest rate on the $285.0 million portion of PVR Revolver borrowings covered by the PVR Interest Rate Swaps was 5.42% at December 31, 2008.

We and PVR monitor changes in our and its counterparties and are not aware of any specific concerns regarding our or PVR’s counterparties’ ability to make payments under any of the Interest Rate Swaps or PVR Interest Rate Swaps.

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Description of notes

We will issue the Notes under an indenture, as supplemented by a supplemental indenture (collectively the “Indenture”), among us, the Subsidiary Guarantors and Wells Fargo Bank, National Association, as trustee (the “Trustee”). The terms of the Notes include those expressly set forth in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”). The Indenture is unlimited in aggregate principal amount, although the issuance of Notes in this offering will be limited to $250.0 million. We may issue an unlimited principal amount of additional notes having identical terms and conditions as the Notes (the “Additional Notes”). We will only be permitted to issue such Additional Notes in compliance with the covenant described under the subheading “—Certain covenants—Limitation on Indebtedness and Preferred Stock.” Any Additional Notes will be part of the same issue as the Notes that we are currently offering and will vote on all matters with the holders of the Notes. Unless the context otherwise requires, for all purposes of the Indenture and this “Description of notes,” references to the Notes include any Additional Notes actually issued.

This description of notes is intended to be a useful overview of the material provisions of the Notes and the Indenture. Since this description of notes is only a summary, you should refer to the Indenture for a complete description of the obligations of the Company and your rights.

You will find the definitions of capitalized terms used in this description of notes under the heading “Certain definitions.” For purposes of this description, references to “the Company,” “we,” “our” and “us” refer only to Penn Virginia Corporation and not to any of its subsidiaries.

General

The Notes.    The Notes:

• are general unsecured, senior obligations of the Company;

• mature on                     , 2016;

• will be issued in denominations of $2,000 and integral multiples of $1,000 in excess of $2,000;

• will be represented by one or more registered Notes in global form, but in certain circumstances may be represented by Notes in definitive form, see “Book-entry, delivery and form”;

• rank senior in right of payment to all existing and future Subordinated Obligations of the Company, including our Convertible Notes;

• rank equally in right of payment to any future senior Indebtedness of the Company, without giving effect to collateral arrangements;

• will be initially unconditionally guaranteed on a senior basis by Penn Virginia Holding Corp., Penn Virginia Oil & 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., representing each Restricted Subsidiary of the Company that currently guarantees the Senior Secured Credit Agreement, see “—Subsidiary guarantees”;

• effectively rank junior to any existing or future secured Indebtedness of the Company, including amounts that may be borrowed under our Senior Secured Credit Agreement, to the extent of the value of the collateral securing such Indebtedness; and

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• rank structurally junior to the indebtedness and other obligations of our non-guarantor subsidiaries, including each of our Unrestricted Subsidiaries.

Interest.    Interest on the Notes will compound semi-annually and will:

• accrue at the rate of     % per annum;

• accrue from the Issue Date or, if interest has already been paid, from the most recent interest payment date;

• be payable in cash semi-annually in arrears on                      and                     , commencing on                     , 2009;

• be payable to the holders of record on the                      and                      immediately preceding the related interest payment dates; and

• be computed on the basis of a 360-day year comprised of twelve 30-day months.

If an interest payment date falls on a day that is not a Business Day, the interest payment to be made on such interest payment date will be made on the next succeeding Business Day with the same force and effect as if made on such interest payment date, and no additional interest will accrue as a result of such delayed payment. The Company will pay interest on overdue principal of the Notes at the above rate, and overdue installments of interest at such rate, to the extent lawful.

Payments on the Notes; paying agent and registrar

We will pay principal of, premium, if any, and interest on the Notes at the office or agency designated by the Company in the City and State of New York, except that we may, at our option, pay interest on the Notes by check mailed to holders of the Notes at their registered address as it appears in the registrar’s books. We have initially designated the corporate trust office of the Trustee in New York, New York to act as our paying agent and registrar. We may, however, change the paying agent or registrar without prior notice to the holders of the Notes, and the Company or any of its Restricted Subsidiaries may act as paying agent or registrar.

We will pay principal of, premium, if any, and interest on, Notes in global form registered in the name of or held by The Depository Trust Company or its nominee in immediately available funds to The Depository Trust Company or its nominee, as the case may be, as the registered holder of such global Note.

Transfer and exchange

A holder may transfer or exchange Notes in accordance with the Indenture. The registrar and the Trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of Notes. No service charge will be imposed by the Company, the Trustee or the registrar for any registration of transfer or exchange of Notes, but the Company may require a holder to pay a sum sufficient to cover any transfer tax or other governmental taxes and fees required by law or permitted by the Indenture. The Company is not required to transfer or exchange any Note selected for redemption. Also, the Company is not required to transfer or exchange any Note for a period of 15 days before a selection of Notes to be redeemed.

The registered holder of a Note will be treated as the owner of it for all purposes.

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Optional redemption

On and after                     , 2013, we may redeem all or, from time to time, a part of the Notes upon not less than 30 nor more than 60 days’ notice, at the following redemption prices (expressed as a percentage of principal amount of the Notes) plus accrued and unpaid interest on the Notes, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the twelve-month period beginning on                  of the years indicated below:

Year	Percentage
2013	%
2014	%
2015 and thereafter	100.000%

Prior to                     , 2012 we may, at our option, on any one or more occasions redeem up to 35% of the aggregate principal amount of the Notes (including Additional Notes) issued under the Indenture with the Net Cash Proceeds of one or more Equity Offerings at a redemption price of % of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date); provided that

(1) at least 65% of the original principal amount of the Notes issued on the Issue Date remains outstanding after each such redemption; and

(2) the redemption occurs within 90 days after the closing of the related Equity Offering.

In addition, the Notes may be redeemed, in whole or in part, at any time prior to                     , 2013 at the option of the Company upon not less than 30 nor more than 60 days’ prior notice mailed by first-class mail to each holder of Notes at its registered address, at a redemption price equal to 100% of the principal amount of the Notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest to, the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date). “Applicable Premium” means, with respect to any Note on any applicable redemption date, the greater of:

(1) 1.0% of the principal amount of such Note; and

(2) the excess, if any, of:

(a) the present value at such redemption date of (i) the redemption price of such Note at                     , 2013 (such redemption price being set forth in the table appearing above under the caption “Optional redemption”) plus (ii) all required interest payments (excluding accrued and unpaid interest to such redemption date) due on such Note through                     , 2013 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

(b) the principal amount of such Note.

“Treasury Rate” means, as of any redemption date, the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) which has become publicly available at least two Business Days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source or similar market data)) most nearly

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equal to the period from the redemption date to                     , 2013; provided, however, that if the period from the redemption date to                     , 2013 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to                     , 2013 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

Selection and notice

If the Company is redeeming less than all of the outstanding Notes, the Trustee will select the Notes for redemption in compliance with the requirements of the principal national securities exchange, if any, on which the Notes are listed or, if the Notes are not listed, then on a pro rata basis, by lot or by such other method as the Trustee in its sole discretion will deem to be fair and appropriate, although no Note of $2,000 in original principal amount or less will be redeemed in part. If any Note is to be redeemed in part only, the notice of redemption relating to such Note will state the portion of the principal amount thereof to be redeemed. A new Note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the partially redeemed Note. On and after the redemption date, interest will cease to accrue on Notes or the portion of them called for redemption unless we default in the payment thereof.

Mandatory redemption; Offers to purchase; Open market purchases

We are not required to make mandatory redemption payments or sinking fund payments with respect to the Notes. However, under certain circumstances, we may be required to offer to purchase Notes as described under the captions “—Change of control” and “—Certain covenants —Limitation on sales of assets and Subsidiary stock.”

We may acquire Notes by means other than a redemption, whether by tender offer, open market purchases, negotiated transactions or otherwise, in accordance with applicable securities laws, so long as such acquisition does not otherwise violate the terms of the Indenture. However, other existing or future agreements of the Company may limit the ability of the Company or its Subsidiaries to purchase Notes prior to maturity.

Ranking

The Notes will be general unsecured obligations of the Company that rank senior in right of payment to all existing and future Indebtedness that is expressly subordinated in right of payment to the Notes. The Notes will rank equally in right of payment with all existing and future liabilities of the Company that are not so subordinated and will be effectively subordinated to all of our secured Indebtedness, including Indebtedness Incurred under our Senior Secured Credit Facility, to the extent of the value of the collateral securing such Indebtedness, and liabilities of any of our Subsidiaries that do not guarantee the Notes (including each of our Unrestricted Subsidiaries). In the event of bankruptcy, liquidation, reorganization or other winding up of the Company or its Subsidiary Guarantors or upon a default in payment with respect to, or the acceleration of, any Indebtedness under the Senior Secured Credit Agreement or other secured Indebtedness, the assets of the Company and its Subsidiary Guarantors that secure secured Indebtedness will be available to pay obligations on the Notes and the Subsidiary

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Guarantees only after all Indebtedness under the Senior Secured Credit Agreement and other secured Indebtedness has been repaid in full from such assets. In addition, in the event of bankruptcy, liquidation, reorganization or other winding up of an Unrestricted Subsidiary, the assets of such Unrestricted Subsidiary will be available to pay obligations on the Notes only after all obligations of such Unrestricted Subsidiary have been repaid in full from such assets. In addition, in the event of bankruptcy, liquidation, reorganization or other winding up of an Unrestricted Subsidiary, the assets of such Unrestricted Subsidiary will be available to pay obligations on the Notes only after all obligations of such Unrestricted Subsidiary have been repaid in full from such assets. We advise you that there may not be sufficient assets remaining to pay amounts due on any or all the Notes and the Subsidiary Guarantees then outstanding.

As of March 31, 2009, on an as adjusted basis after giving effect to our May 2009 equity offering, this offering and the application of net proceeds from this offering as more fully described in “Use of proceeds”:

• we and our Subsidiary Guarantors would have had $             million of total Indebtedness; and

• of the $             million of total Indebtedness, $             million would have constituted secured Indebtedness under our Senior Secured Credit Agreement and we would have additional availability of $             million under our Senior Secured Credit Agreement as to which the Notes would have been effectively subordinated to the extent of the assets secured thereby.

As of March 31, 2009, the Company’s Subsidiaries (other than the Subsidiary Guarantors) had consolidated total liabilities of $700.9 million, consolidated total assets of $1,243.0 million and consolidated total revenues of $881.7 million.

Subsidiary guarantees

The Subsidiary Guarantors will, jointly and severally, fully and unconditionally guarantee on a senior unsecured basis our obligations under the Notes and all obligations under the Indenture. The obligations of Subsidiary Guarantors under the Subsidiary Guarantees will rank equally in right of payment with other Indebtedness of such Subsidiary Guarantor, except to the extent such other Indebtedness is expressly subordinate to the obligations arising under the Subsidiary Guarantee.

As of March 31, 2009, on an as adjusted basis and after giving effect to this offering and the application of net proceeds from this offering, as more fully described under “Use of proceeds,” the Subsidiary Guarantors would have had $             million of Indebtedness, consisting of secured guarantees of $             million under the revolving credit facility and unsecured guarantees of $250.0 million under the notes.

Although the Indenture will limit the amount of Indebtedness that Restricted Subsidiaries may Incur, such Indebtedness may be substantial and such limitation is subject to a number of significant qualifications. Moreover, the Indenture does not impose any limitation on the Incurrence by such Subsidiaries of liabilities that are not considered Indebtedness under the Indenture. See “—Certain covenants—Limitation on Indebtedness and Preferred Stock.”

The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance or fraudulent transfer under applicable law, although no assurance can be given that a court would give the holder the benefit of such provision. See “Risk factors—Risks relating to the offering—

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Federal and state laws allow courts, under specific circumstances, to void guarantees and to require you to return payments received from guarantors.” If a Subsidiary Guarantee were rendered voidable, it could be subordinated by a court to all other indebtedness (including guarantees and other contingent liabilities) of the applicable Subsidiary Guarantor, and, depending on the amount of such indebtedness, a Subsidiary Guarantor’s liability on its Subsidiary Guarantee could be reduced to zero. If the obligations of a Subsidiary Guarantor under its Subsidiary Guarantee were avoided, holders of Notes would have to look to the assets of any remaining Subsidiary Guarantors for payment. There can be no assurance in that event that such assets would suffice to pay the outstanding principal and interest on the Notes.

In the event a Subsidiary Guarantor is sold or disposed of (whether by merger, consolidation, the sale of its Capital Stock or the sale of all or substantially all of its assets (other than by lease)) and whether or not the Subsidiary Guarantor is the surviving corporation in such transaction to a Person which is not the Company or a Restricted Subsidiary of the Company, such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee if the sale or other disposition does not violate the covenants described under “Certain covenants—Limitation on sales of assets and Subsidiary stock.”

In addition, a Subsidiary Guarantor will be released from its obligations under the Indenture and, its Subsidiary Guarantee, upon the release or discharge of the Guarantee that resulted in the creation of such Subsidiary Guarantee pursuant to the covenant described under “—Future subsidiary guarantors,” except a release or discharge by or as a result of payment under such Guarantee; if the Company designates such Subsidiary as an Unrestricted Subsidiary and such designation complies with the other applicable provisions of the Indenture or in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the Notes as provided below under the captions “Defeasance” and “Satisfaction and discharge.”

PVG, PVR, each of their respective Subsidiaries and certain other Subsidiaries of the Company are Unrestricted Subsidiaries. In addition, under certain circumstances, the Company may designate additional Subsidiaries as Unrestricted Subsidiaries. None of the Unrestricted Subsidiaries will be subject to the restrictive covenants in the Indenture and none will guarantee the Notes.

Change of control

If a Change of Control occurs, unless the Company has previously or concurrently exercised its right to redeem all of the Notes as described under “Optional redemption,” each holder will have the right to require the Company to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess of $2,000) of such holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

Within 30 days following any Change of Control, unless we have previously or concurrently exercised our right to redeem all of the Notes as described under “Optional redemption,” we will mail a notice (the “Change of Control Offer”) to each holder, with a copy to the Trustee, stating:

(1) that a Change of Control has occurred and that such holder has the right to require us to purchase such holder’s Notes at a purchase price in cash equal to 101% of the principal amount of such Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on a record date to receive interest on the relevant interest payment date) (the “Change of Control Payment”);

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(2) the repurchase date (which shall be no earlier than 30 days nor later than 60 days from the date such notice is mailed) (the “Change of Control Payment Date”);

(3) that any Note not properly tendered will remain outstanding and continue to accrue interest;

(4) that unless we default in the payment of the Change of Control Payment, all Notes accepted for payment pursuant to the Change of Control Offer will cease to accrue interest on the Change of Control Payment Date;

(5) that holders electing to have any Notes purchased pursuant to a Change of Control Offer will be required to surrender such Notes, with the form entitled “Option of Holder to Elect Purchase” on the reverse of such Notes completed, to the paying agent specified in the notice at the address specified in the notice prior to the close of business on the third Business Day preceding the Change of Control Payment Date;

(6) that holders will be entitled to withdraw their tendered Notes and their election to require us to purchase such Notes, provided that the paying agent receives, not later than the close of business on the 30th day following the date of the Change of Control notice, a telegram, telex, facsimile transmission or letter setting forth the name of the holder of the Notes, the principal amount of Notes tendered for purchase, and a statement that such holder is withdrawing its tendered Notes and its election to have such Notes purchased;

(7) that if we are redeeming less than all of the Notes, the holders of the remaining Notes will be issued new Notes and such new Notes will be equal in principal amount to the unpurchased portion of the Notes surrendered. The unpurchased portion of the Notes must be equal to a minimum principal amount of $2,000 and an integral multiple of $1,000 in excess of $2,000; and

(8) the procedures determined by us, consistent with the Indenture, that a holder must follow in order to have its Notes repurchased.

On the Change of Control Payment Date, the Company will, to the extent lawful:

(1) accept for payment all Notes or portions of Notes (in a minimum principal amount of $2,000 and integral multiples of $1,000 in excess of $2,000) properly tendered pursuant to the Change of Control Offer;

(2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all Notes or portions of Notes properly tendered and not properly withdrawn; and

(3) deliver or cause to be delivered to the Trustee the Notes so accepted together with an Officers’ Certificate stating the aggregate principal amount of Notes or portions of Notes being purchased by the Company.

The paying agent will promptly mail to each holder of Notes properly tendered and not properly withdrawn the Change of Control Payment for such Notes, and the Trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new Note equal in principal amount to any unpurchased portion of the Notes surrendered, if any; provided that each such new Note will be in a minimum principal amount of $2,000 or an integral multiple of $1,000 in excess of $2,000.

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If the Change of Control Payment Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest, will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no further interest will be payable to holders who tender pursuant to the Change of Control Offer.

The Change of Control provisions described above will be applicable whether or not any other provisions of the Indenture are applicable. Except as described above with respect to a Change of Control, the Indenture does not contain provisions that permit the holders to require that the Company repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

We will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by us and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer.

A Change of Control Offer may be made in advance of a Change of Control, and conditioned upon the occurrence of a Change of Control, if a definitive agreement is in place for the Change of Control at the time of making the Change of Control Offer.

We will comply, to the extent applicable, with the requirements of Rule 14e-1 of the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with provisions of the Indenture, or compliance with the Change of Control provisions of the Indenture would constitute a violation of any such laws or regulations, we will comply with the applicable securities laws and regulations and will not be deemed to have breached our obligations described in the Indenture by virtue of our compliance with such securities laws or regulations.

Our ability to repurchase Notes pursuant to a Change of Control Offer may be limited by a number of factors. The occurrence of certain of the events that constitute a Change of Control would constitute a default under the Senior Secured Credit Agreement. In addition, certain events that may constitute a change of control under the Senior Secured Credit Agreement and cause a default under that agreement will not constitute a Change of Control under the Indenture. Future Indebtedness of the Company and its Subsidiaries may also contain prohibitions of certain events that would constitute a Change of Control or require such Indebtedness to be repurchased upon a Change of Control. Moreover, the exercise by the holders of their right to require the Company to repurchase the Notes could cause a default under such Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Company. Finally, the Company’s ability to pay cash to the holders upon a repurchase may be limited by the Company’s then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases.

Even if sufficient funds were otherwise available, the terms of the Senior Secured Credit Agreement will, and other an/or future Indebtedness may, prohibit the Company’s prepayment or repurchase of Notes before their scheduled maturity. Consequently, if the Company is not able to prepay the Indebtedness under the Senior Secured Credit Agreement and any such other Indebtedness containing similar restrictions or obtain requisite consents, the Company will be

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unable to fulfill its repurchase obligations if holders of Notes exercise their repurchase rights following a Change of Control, resulting in a default under the Indenture. A default under the Indenture may result in a cross-default under the Senior Secured Credit Agreement.

If holders of not less than 90% in aggregate principal amount of the outstanding Notes validly tender and do not withdraw such Notes in a Change of Control Offer and the Company, or any third party making a Change of Control Offer in lieu of the Company as described above, purchases all of the Notes validly tendered and not withdrawn by such holders, the Company will have the right, upon not less than 30 nor more than 60 days’ prior notice, given not more than 30 days following such purchase pursuant to the Change of Control Offer described above, to redeem all Notes that remain outstanding following such purchase at a redemption price in cash equal to the applicable Change of Control Payment plus, to the extent not included in the Change of Control Payment, accrued and unpaid interest, if any, to the date of redemption.

The Change of Control provisions described above may deter certain mergers, tender offers and other takeover attempts involving the Company. The Change of Control purchase feature is a result of negotiations between the underwriters and us. As of the Issue Date, we have no present intention to engage in a transaction involving a Change of Control, although it is possible that we could decide to do so in the future. Subject to the limitations discussed below, we could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the Indenture, but that could increase the amount of indebtedness outstanding at such time or otherwise affect our capital structure or credit ratings. Restrictions on our ability to incur additional Indebtedness are contained in the covenants described under “Certain covenants—Limitation on Indebtedness and Preferred Stock” and “Certain covenants—Limitation on Liens.” Such restrictions in the Indenture can be waived only with the consent of the holders of a majority in principal amount of the Notes then outstanding. Except for the limitations contained in such covenants, however, the Indenture will not contain any covenants or provisions that may afford holders of the Notes protection in the event of a highly leveraged transaction.

The definition of “Change of Control” includes a disposition of all or substantially all of the property and assets of the Company and its Restricted Subsidiaries taken as a whole to any Person. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve a disposition of “all or substantially all” of the property or assets of a Person. As a result, it may be unclear as to whether a Change of Control has occurred and whether a holder of Notes may require the Company to make an offer to repurchase the Notes as described above. In a recent decision, the Chancery Court of Delaware raised the possibility that a Change of Control occurring as a result of a failure to have Continuing Directors comprising a majority of the Board of Directors may be unenforceable on public policy grounds.

The provisions under the Indenture relative to our obligation to make an offer to repurchase the Notes as a result of a Change of Control may be waived or modified or terminated with the written consent of the holders of a majority in principal amount of the Notes then outstanding (including consents obtained in connection with a tender offer or exchange offer for the Notes) prior to the occurrence of such Change of Control.

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Certain covenants

Limitation on Indebtedness and Preferred Stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, Incur any Indebtedness (including Acquired Indebtedness) and the Company will not permit any of its Restricted Subsidiaries to issue Preferred Stock; provided, however, that the Company may Incur Indebtedness and any of the Subsidiary Guarantors may Incur Indebtedness and issue Preferred Stock if on the date thereof:

(1) the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries is at least 2.25 to 1.00, determined on a pro forma basis (including a pro forma application of proceeds); and

(2) no Default will have occurred or be continuing or would occur as a consequence of Incurring the Indebtedness or transactions relating to such Incurrence.

The first paragraph of this covenant will not prohibit the Incurrence of the following Indebtedness:

(1) Indebtedness of the Company Incurred pursuant to one or more Credit Facilities in an aggregate amount not to exceed the greater of (a) $500.0 million or (b) an amount equal to the sum of $225.0 million and 30.0% of the Company’s Adjusted Consolidated Net Tangible Assets determined as of the date of the Incurrence of such Indebtedness after giving effect to the application of the proceeds therefrom, in each case outstanding at any one time;

(2) Guarantees by the Company or Subsidiary Guarantors of Indebtedness of the Company or a Subsidiary Guarantor, as the case may be, Incurred in accordance with the provisions of the Indenture; provided that in the event such Indebtedness that is being Guaranteed is a Subordinated Obligation or a Guarantor Subordinated Obligation, then the related Guarantee shall be subordinated in right of payment to the Notes or the Subsidiary Guarantee to at least the same extent as the Indebtedness being Guaranteed, as the case may be;

(3) Indebtedness of the Company owing to and held by any Restricted Subsidiary or Indebtedness of a Restricted Subsidiary owing to and held by the Company or any Restricted Subsidiary; provided, however, that (i) any subsequent issuance or transfer of Capital Stock or any other event which results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary of the Company and (ii) any sale or other transfer of any such Indebtedness to a Person other than the Company or a Restricted Subsidiary of the Company shall be deemed, in each case, to constitute an Incurrence of such Indebtedness by the Company or such Subsidiary, as the case may be;

(4) Indebtedness represented by (a) the Notes issued on the Issue Date and all Subsidiary Guarantees, (b) any Indebtedness (other than the Indebtedness described in clauses (1), (2) and 4(a)) outstanding on the Issue Date and (c) any Refinancing Indebtedness Incurred in respect of any Indebtedness described in this clause (4) or clause (5) or Incurred pursuant to the first paragraph of this covenant;

(5) Indebtedness of a Person that becomes a Restricted Subsidiary or is acquired by the Company or a Restricted Subsidiary or merged into the Company or a Restricted Subsidiary in accordance with the Indenture and outstanding on the date on which such Person became a

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Restricted Subsidiary or was acquired by or was merged into the Company or such Restricted Subsidiary (other than Indebtedness Incurred (a) to provide all or any portion of the funds utilized to consummate the transaction or series of related transactions pursuant to which such Person became a Restricted Subsidiary or was otherwise acquired by or was merged into the Company or a Restricted Subsidiary or (b) otherwise in connection with, or in contemplation of, such acquisition); provided, however, that at the time such Person becomes a Restricted Subsidiary or is acquired by or was merged into the Company or a Restricted Subsidiary, the Company would have been able to Incur $1.00 of additional Indebtedness pursuant to the first paragraph of this covenant after giving effect to the Incurrence of such Indebtedness pursuant to this clause (5);

(6) the Incurrence by the Company or any Restricted Subsidiary of Indebtedness represented by Capitalized Lease Obligations, mortgage financings or purchase money obligations, in each case Incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvements or carrying costs of property used in the business of the Company or such Restricted Subsidiary, and Refinancing Indebtedness Incurred to Refinance any Indebtedness Incurred pursuant to this clause (6) in an aggregate outstanding principal amount which, when taken together with the principal amount of all other Indebtedness Incurred pursuant to this clause (6) and then outstanding, will not exceed $20.0 million at any time outstanding;

(7) Permitted Acquisition Indebtedness;

(8) Indebtedness Incurred in respect of (a) self-insurance obligations, bid, appeal, reimbursement, performance, surety and similar bonds and completion guarantees provided by the Company or a Restricted Subsidiary in the ordinary course of business and any Guarantees or letters of credit functioning as or supporting any of the foregoing bonds or obligations and (b) obligations represented by letters of credit for the account of the Company or a Restricted Subsidiary in order to provide security for workers’ compensation claims (in the case of clauses (a) and (b) other than for an obligation for money borrowed);

(9) the Incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness arising from Guarantees of Indebtedness of joint ventures at any time outstanding not to exceed the greater of $10.0 million or 1.0% of the Company’s Adjusted Consolidated Net Tangible Assets determined as of the date of the Incurrence of such Indebtedness after giving pro forma effect to such Incurrence and the application of proceeds therefrom;

(10) Capital Stock (other than Disqualified Stock) of the Company or of any of the Subsidiary Guarantors; and

(11) in addition to the items referred to in clauses (1) through (10) above, Indebtedness of the Company and its Subsidiary Guarantors in an aggregate outstanding principal amount which, when taken together with the principal amount of all other Indebtedness Incurred pursuant to this clause (11) and then outstanding, will not at any time exceed the greater of $35.0 million or 2.5% of the Company’s Adjusted Consolidated Net Tangible Assets, determined as of the date of Incurrence of such Indebtedness after giving effect to such Incurrence and the application of the proceeds therefrom.

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For purposes of determining compliance with, and the outstanding principal amount of any particular Indebtedness Incurred pursuant to and in compliance with, this covenant:

(1) in the event an item of that Indebtedness meets the criteria of more than one of the types of Indebtedness described in the first and second paragraphs of this covenant, the Company, in its sole discretion, will classify such item of Indebtedness on the date of Incurrence and, subject to clause (2) below may later classify, reclassify or redivide all or a portion of such item of Indebtedness, in any manner that complies with this covenant;

(2) all Indebtedness outstanding on the date of the Indenture under the Senior Secured Credit Agreement shall be deemed Incurred on the Issue Date under clause (1) of the second paragraph of this covenant;

(3) Guarantees of, or obligations in respect of letters of credit supporting, Indebtedness which is otherwise included in the determination of a particular amount of Indebtedness shall not be included;

(4) if obligations in respect of letters of credit are Incurred pursuant to a Credit Facility and are being treated as Incurred pursuant to clause (1) of the second paragraph above and the letters of credit relate to other Indebtedness, then such other Indebtedness shall not be included;

(5) the principal amount of any Disqualified Stock of the Company or a Restricted Subsidiary, or Preferred Stock of a Restricted Subsidiary that is not a Subsidiary Guarantor, will be equal to the greater of the maximum mandatory redemption or repurchase price (not including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;

(6) Indebtedness permitted by this covenant need not be permitted solely by reference to one provision permitting such Indebtedness but may be permitted in part by one such provision and in part by one or more other provisions of this covenant permitting such Indebtedness; and

(7) the amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP.

Accrual of interest, accrual of dividends, the amortization of debt discount or the accretion of accreted value, the payment of interest in the form of additional Indebtedness, the payment of dividends in the form of additional shares of Preferred Stock or Disqualified Stock and unrealized losses or charges in respect of Hedging Obligations (including those resulting from the application of Statement of Financial Accounting Standard No. 133) will not be deemed to be an Incurrence of Indebtedness for purposes of this covenant. The amount of any Indebtedness outstanding as of any date shall be (i) the accreted value thereof in the case of any Indebtedness issued with original issue discount and (ii) the principal amount or liquidation preference thereof, together with any interest thereon that is more than 30 days past due, in the case of any other Indebtedness.

If at any time an Unrestricted Subsidiary becomes a Restricted Subsidiary, any Indebtedness of such Subsidiary shall be deemed to be Incurred by a Restricted Subsidiary as of such date (and, if such Indebtedness is not permitted to be Incurred as of such date under this “Limitation on Indebtedness and Preferred Stock” covenant, the Company shall be in Default of this covenant).

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For purposes of determining compliance with any U.S. dollar-denominated restriction on the Incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was Incurred, in the case of term Indebtedness, or first committed, in the case of revolving credit Indebtedness; provided that if such Indebtedness is Incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Company may Incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in the exchange rate of currencies. The principal amount of any Indebtedness Incurred to refinance other Indebtedness, if Incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such Refinancing Indebtedness is denominated that is in effect on the date of such refinancing.

The Indenture will not treat (1) unsecured Indebtedness as subordinated or junior to secured Indebtedness merely because it is unsecured or (2) senior Indebtedness as subordinated or junior to any other senior Indebtedness merely because it has a junior priority with respect to the same collateral.

Limitation on Restricted Payments

The Company will not, and will not permit any of its Restricted Subsidiaries, directly or indirectly, to:

(1) declare or pay any dividend or make any payment or distribution on or in respect of the Company’s Capital Stock (including any payment or distribution in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) except:

(a) dividends or distributions by the Company payable solely in Capital Stock of the Company (other than Disqualified Stock) or in options, warrants or other rights to purchase such Capital Stock of the Company; and

(b) dividends or distributions payable to the Company or a Restricted Subsidiary and if such Restricted Subsidiary is not a Wholly-Owned Subsidiary, to minority stockholders (or owners of an equivalent interest in the case of a Subsidiary that is an entity other than a corporation) so long as the Company or a Restricted Subsidiary receives at least its pro rata share of such dividend or distribution;

(2) purchase, redeem, defease, retire or otherwise acquire for value any Capital Stock of the Company or any direct or indirect parent of the Company held by Persons other than the Company or a Restricted Subsidiary (other than in exchange for Capital Stock of the Company (other than Disqualified Stock));

(3) purchase, repurchase, redeem, defease or otherwise acquire or retire for value, prior to scheduled maturity, scheduled repayment or scheduled sinking fund payment, any Subordinated Obligations or Guarantor Subordinated Obligations (other than (x) Indebtedness permitted under clause (3) of the second paragraph of the covenant

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“—Limitation on Indebtedness and Preferred Stock” or (y) the purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations or Guarantor Subordinated Obligations purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of purchase, repurchase, redemption, defeasance or other acquisition or retirement); or

(4) make any Restricted Investment in any Person;

(any such dividend, distribution, purchase, redemption, repurchase, defeasance, other acquisition, retirement or Restricted Investment referred to in clauses (1) through (4) shall be referred to herein as a “Restricted Payment”), if at the time the Company or such Restricted Subsidiary makes such Restricted Payment:

(a) a Default shall have occurred and be continuing (or would result therefrom);

(b) the Company is not able to Incur an additional $1.00 of Indebtedness pursuant to the covenant described under the first paragraph under “—Limitation on Indebtedness and Preferred Stock” after giving effect, on a pro forma basis, to such Restricted Payment; or

(c) the aggregate amount of such Restricted Payment and all other Restricted Payments declared or made subsequent to the Issue Date would exceed the sum of:

(i) 50% of Consolidated Net Income for the period (treated as one accounting period) from July 1, 2009 to the end of the most recent fiscal quarter ending prior to the date of such Restricted Payment for which internal financial statements are in existence (or, in case such Consolidated Net Income is a deficit, minus 100% of such deficit);

(ii) 100% of the aggregate Net Cash Proceeds and the fair market value (as determined by the Company’s Board of Directors in good faith) of property or securities other than cash (including Capital Stock of Persons engaged primarily in the Oil and Gas Business or assets used in the Oil and Gas Business), in each case received by the Company from the issue or sale of its Capital Stock (other than Disqualified Stock) or other capital contributions subsequent to the Issue Date (other than Net Cash Proceeds received from an issuance or sale of such Capital Stock to (x) management, employees, directors or any direct or indirect parent of the Company, to the extent such Net Cash Proceeds have been used to make a Restricted Payment pursuant to clause (5)(a) of the next succeeding paragraph, (y) a Subsidiary of the Company or (z) an employee stock ownership plan, option plan or similar trust (to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination));

(iii) the amount by which Indebtedness of the Company or its Restricted Subsidiaries is reduced on the Company’s balance sheet upon the conversion or exchange (other than by a Wholly-Owned Subsidiary of the Company) subsequent to the Issue Date of any Indebtedness of the Company or its Restricted Subsidiaries convertible or exchangeable for Capital Stock (other than Disqualified Stock) of the Company (less the amount of any cash, or the fair market value of any other property (other than such Capital Stock), distributed by the Company upon such conversion or exchange), together with the net proceeds, if any, received by the Company or any of its Restricted Subsidiaries upon such conversion or exchange; and

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(iv) the amount equal to the aggregate net reduction in Restricted Investments made by the Company or any of its Restricted Subsidiaries in any Person after the Issue Date resulting from:

(A) repurchases, repayments or redemptions of such Restricted Investments by such Person, proceeds realized upon the sale of such Restricted Investment (other than to a Subsidiary of the Company), repayments of loans or advances or other transfers of assets (including by way of dividend or distribution) by such Person to the Company or any Restricted Subsidiary;

(B) the redesignation of Unrestricted Subsidiaries as Restricted Subsidiaries (valued in each case as provided in the definition of “Investment”) not to exceed, in the case of any Unrestricted Subsidiary, the amount of Investments previously made by the Company or any Restricted Subsidiary in such Unrestricted Subsidiary, which amount in each case under this clause (iv) was included in the calculation of the amount of Restricted Payments; provided, however, that no amount will be included under this clause (iv) to the extent it is already included in Consolidated Net Income; and

(C) the sale by the Company or any Restricted Subsidiary (other than to the Company or a Restricted Subsidiary) of all or a portion of the Capital Stock of an Unrestricted Subsidiary or a distribution from an Unrestricted Subsidiary or a dividend from an Unrestricted Subsidiary (whether any such distribution or dividend is made with proceeds from the issuance by such Unrestricted Subsidiary of its Capital Stock or otherwise).

The provisions of the preceding paragraph will not prohibit:

(1) any Restricted Payment made by exchange for, or out of the proceeds of the substantially concurrent sale of, Capital Stock of the Company (other than Disqualified Stock and other than Capital Stock issued or sold to a Subsidiary or an employee stock ownership plan or similar trust to the extent such sale to an employee stock ownership plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination) or a substantially concurrent cash capital contribution received by the Company from its shareholders; provided, however, that (a) such Restricted Payment will be excluded from subsequent calculations of the amount of Restricted Payments and (b) the Net Cash Proceeds from such sale of Capital Stock or capital contribution will be excluded from clause (c)(ii) of the preceding paragraph;

(2) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations of the Company or Guarantor Subordinated Obligations of any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, Subordinated Obligations of the Company or any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Guarantor Subordinated Obligations made by exchange for or out of the proceeds of the substantially concurrent sale of Guarantor Subordinated Obligations that, in each case, is permitted to be Incurred pursuant to the covenant described under “—Limitation on Indebtedness and Preferred Stock”; provided, however, that such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded from subsequent calculations of the amount of Restricted Payments;

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(3) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Disqualified Stock of the Company or a Restricted Subsidiary made by exchange for or out of the proceeds of the substantially concurrent sale of Disqualified Stock of the Company or such Restricted Subsidiary, as the case may be, that, in each case, is permitted to be Incurred pursuant to the covenant described under “—Limitation on Indebtedness and Preferred Stock”; provided, however, that such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded from subsequent calculations of the amount of Restricted Payments;

(4) dividends paid or distributions made within 60 days after the date of declaration if at such date of declaration such dividend or distribution would have complied with this covenant; provided, however, that such dividends and distributions will be included in subsequent calculations of the amount of Restricted Payments; and provided further, however, that for purposes of clarification, this clause (4) shall not include cash payments in lieu of the issuance of fractional shares included in clause (9) below;

(5) so long as no Default has occurred and is continuing, (a) the purchase of Capital Stock or options, warrants, equity appreciation rights or other rights to purchase or acquire Capital Stock of the Company held by any existing or former employees, management or directors of the Company or any Restricted Subsidiary of the Company or their assigns, estates or heirs, in each case in connection with the repurchase provisions under employee stock option or stock purchase agreements or other agreements to compensate management, employees or directors; provided that such redemptions or repurchases pursuant to this subclause (a) during any calendar year will not exceed $2.0 million in the aggregate (with unused amounts in any calendar year being carried over to succeeding calendar years); provided further, that such amount in any calendar year may be increased by an amount not to exceed (A) the cash proceeds received by the Company from the sale of Capital Stock of the Company to members of management or directors of the Company and its Restricted Subsidiaries that occurs after the Issue Date (to the extent the cash proceeds from the sale of such Capital Stock have not otherwise been applied to the payment of Restricted Payments by virtue of the clause (c) of the preceding paragraph), plus (B) the cash proceeds of key man life insurance policies received by the Company and its Restricted Subsidiaries after the Issue Date, less (C) the amount of any Restricted Payments made pursuant to clauses (A) and (B) of this clause (5)(a); provided further, however, that the amount of any such repurchase or redemption under this subclause (a) will be excluded in subsequent calculations of the amount of Restricted Payments and the proceeds received from any such sale will be excluded from clause (c)(ii) of the preceding paragraph; and (b) the cancellation of loans or advances to employees or directors of the Company or any Subsidiary of the Company the proceeds of which are used to purchase Capital Stock of the Company, in an aggregate amount not in excess of $2.0 million at any one time outstanding; provided, however, that the amount of such cancelled loans and advances will be included in subsequent calculations of the amount of Restricted Payments;

(6) repurchases, redemptions or other acquisitions or retirements for value of Capital Stock deemed to occur upon the exercise of stock options, warrants, rights to acquire Capital Stock or other convertible securities if such Capital Stock represents a portion of the exercise or exchange price thereof, and any repurchases, redemptions or other acquisitions or retirements for value of Capital Stock made in lieu of withholding taxes in connection with any exercise or exchange of warrants, options or rights to acquire Capital Stock; provided,

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however, that such repurchases will be excluded from subsequent calculations of the amount of Restricted Payments;

(7) the purchase, repurchase, redemption, defeasance or other acquisition or retirement for value of any Subordinated Obligation (i) at a purchase price not greater than 101% of the principal amount of such Subordinated Obligation in the event of a Change of Control in accordance with provisions similar to the covenant described under “Change of control” or (ii) at a purchase price not greater than 100% of the principal amount thereof in accordance with provisions similar to the covenant described under “—Limitation on sales of assets and Subsidiary stock”; provided that, prior to or simultaneously with such purchase, repurchase, redemption, defeasance or other acquisition or retirement, the Company has made the Change of Control Offer or Asset Disposition Offer, as applicable, as provided in such covenant with respect to the Notes and has completed the repurchase or redemption of all Notes validly tendered for payment in connection with such Change of Control Offer or Asset Disposition Offer; provided, however, that such repurchases will be included in subsequent calculations of the amount of Restricted Payments;

(8) payments or distributions to dissenting stockholders pursuant to applicable law or in connection with the settlement or other satisfaction of legal claims made pursuant to or in connection with a consolidation, merger or transfer of assets; provided, however, that any payment pursuant to this clause (8) shall be included in the calculation of the amount of Restricted Payments;

(9) cash payments in lieu of the issuance of fractional shares; provided, however, that any payment pursuant to this clause (9) shall be excluded in the calculation of the amount of Restricted Payments;

(10) so long as no Default or Event of Default has occurred and is continuing, the payment of dividends on the Company’s Common Stock of an amount per annum not to exceed $0.25 per share (but in no event in excess of $15.0 million in the aggregate during any calendar year pursuant to this clause (10)); provided, however, that the amount of such Restricted Payments will be included in subsequent calculations of Restricted Payments;

(11) the declaration and payment of scheduled or accrued dividends to holders of any class of or series of Disqualified Stock of the Company or any of its Restricted Subsidiaries issued on or after the Issue Date in accordance with the covenant captioned “—Limitation on Indebtedness and Preferred Stock”, to the extent such dividends are included in Consolidated Interest Expense; provided, however, that any payment pursuant to this clause (11) shall be excluded in the calculation of the amount of Restricted Payments; and

(12) Restricted Payments in an amount not to exceed $20.0 million at any one time outstanding; provided, however, that the amount of such Restricted Payments will be included in subsequent calculations of the amount of Restricted Payments.

The amount of all Restricted Payments (other than cash) shall be the fair market value on the date of such Restricted Payment of the asset(s) or securities proposed to be paid, transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to such Restricted Payment. The fair market value of any cash Restricted Payment shall be its face amount and the fair market value of any non-cash Restricted Payment shall be determined conclusively by the Board of Directors of the Company acting in good faith whose resolution with respect thereto shall be delivered to the Trustee.

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In the event that a Restricted Payment meets the criteria of more than one of the exceptions described in (1) through (12) above or is entitled to be made pursuant to the first paragraph above, the Company shall, in its sole discretion, classify such Restricted Payment.

As of the Issue Date, only Penn Virginia Holding Corp., Penn Virginia Oil & 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. will be Restricted Subsidiaries. PVG, PVR, their respective Subsidiaries and certain other Subsidiaries of the Company will be Unrestricted Subsidiaries as of the Issue Date. We will not permit any Unrestricted Subsidiary to become a Restricted Subsidiary except pursuant to the last sentence of the definition of “Unrestricted Subsidiary.” For purpose of designating any Restricted Subsidiary as an Unrestricted Subsidiary, all outstanding Investments by the Company and its Restricted Subsidiaries (except to the extent repaid) in the Subsidiary so designated will be deemed to be Restricted Payments in an amount determined as set forth in the last sentence of the definition of “Investment.” Such designation will be permitted only if a Restricted Payment in such amount would be permitted at such time, whether pursuant to the first paragraph of this covenant or under clause (12) of the second paragraph of this covenant, or pursuant to the definition of “Permitted Investments,” and if such Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. Unrestricted Subsidiaries will not be subject to any of the restrictive covenants set forth in the Indenture.

Limitation on Liens

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, Incur or suffer to exist any Lien (the “Initial Lien”) other than Permitted Liens upon any of its property or assets (including Capital Stock of Restricted Subsidiaries), including any income or profits therefrom, whether owned on the date of the Indenture or acquired after that date, which Lien is securing any Indebtedness, unless contemporaneously with the Incurrence of such Liens effective provision is made to secure the Indebtedness due under the Notes or, in respect of Liens on any Restricted Subsidiary’s property or assets, any Subsidiary Guarantee of such Restricted Subsidiary, equally and ratably with (or senior in priority to in the case of Liens with respect to Subordinated Obligations or Guarantor Subordinated Obligations, as the case may be) the Indebtedness secured by such Lien for so long as such Indebtedness is so secured.

Any Lien created for the benefit of the holders of the Notes pursuant to the preceding paragraph shall provide by its terms that such Lien shall be automatically and unconditionally released and discharged upon the release and discharge of the Initial Lien.

Limitation on restrictions on distributions from Restricted Subsidiaries

The Company will not, and will not permit any Restricted Subsidiary to, create or otherwise cause or permit to exist or become effective any consensual encumbrance or consensual restriction on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock or pay any Indebtedness or other obligations owed to the Company or any Restricted Subsidiary (it being understood that the priority of any Preferred Stock in receiving dividends or liquidating distributions prior to dividends or liquidating distributions being paid on Common Stock shall not be deemed a restriction on the ability to make distributions on Capital Stock);

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(2) make any loans or advances to the Company or any Restricted Subsidiary (it being understood that the subordination of loans or advances made to the Company or any Restricted Subsidiary to other Indebtedness Incurred by the Company or any Restricted Subsidiary shall not be deemed a restriction on the ability to make loans or advances); or

(3) sell, lease or transfer any of its property or assets to the Company or any Restricted Subsidiary.

The preceding provisions will not prohibit:

(i) any encumbrance or restriction pursuant to or by reason of an agreement in effect at or entered into on the Issue Date, including, without limitation, the Indenture in effect on such date;

(ii) any encumbrance or restriction with respect to a Person pursuant to or by reason of an agreement relating to any Capital Stock or Indebtedness Incurred by a Person on or before the date on which such Person was acquired by the Company or another Restricted Subsidiary (other than Capital Stock or Indebtedness Incurred as consideration in, or to provide all or any portion of the funds utilized to consummate, the transaction or series of related transactions pursuant to which such Person was acquired by the Company or a Restricted Subsidiary or in contemplation of the transaction) and outstanding on such date; provided that any such encumbrance or restriction shall not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property so acquired;

(iii) encumbrances and restrictions contained in contracts entered into in the ordinary course of business, not relating to any Indebtedness, and that do not, individually or in the aggregate, detract from the value of, or from the ability of the Company and the Restricted Subsidiaries to realize the value of, property or assets of the Company or any Restricted Subsidiary in any manner material to the Company or any Restricted Subsidiary;

(iv) any encumbrance or restriction with respect to a Unrestricted Subsidiary pursuant to or by reason of an agreement that the Unrestricted Subsidiary is a party to entered into before the date on which such Unrestricted Subsidiary became a Restricted Subsidiary; provided that such agreement was not entered into in anticipation of the Unrestricted Subsidiary becoming a Restricted Subsidiary and any such encumbrance or restriction shall not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property so acquired;

(v) with respect to any Foreign Subsidiary, any encumbrance or restriction contained in the terms of any Indebtedness or any agreement pursuant to which such Indebtedness was Incurred if either (1) the encumbrance or restriction applies only in the event of a payment default or a default with respect to a financial covenant in such Indebtedness or agreement or (2) the Company determines that any such encumbrance or restriction will not materially affect the Company’s ability to make principal or interest payments on the Notes, as determined in good faith by the Board of Directors of the Company, whose determination shall be conclusive;

(vi) any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement effecting a refunding, replacement or refinancing of Indebtedness Incurred pursuant to an agreement referred to in clauses (i) through (v) or clause (xii) of this paragraph or this clause (vi) or contained in any amendment, restatement, modification,

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renewal, supplemental, refunding, replacement or refinancing of an agreement referred to in clauses (i) through (v) or clause (xii) of this paragraph or this clause (vi); provided that the encumbrances and restrictions with respect to such Restricted Subsidiary contained in any such agreement taken as a whole are no less favorable in any material respect to the holders of the Notes than the encumbrances and restrictions contained in the agreements governing the Indebtedness being refunded, replaced or refinanced;

(vii) in the case of clause (3) of the first paragraph of this covenant, any encumbrance or restriction:

(a) that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease (including leases governing leasehold interests or farm-in agreements or farm-out agreements relating to leasehold interests in Oil and Gas Properties), license or similar contract, or the assignment or transfer of any such lease (including leases governing leasehold interests or farm-in agreements or farm-out agreements relating to leasehold interests in Oil and Gas Properties), license (including, without limitation, licenses of intellectual property) or other contract;

(b) contained in mortgages, pledges or other security agreements permitted under the Indenture securing Indebtedness of the Company or a Restricted Subsidiary to the extent such encumbrances or restrictions restrict the transfer of the property subject to such mortgages, pledges or other security agreements;

(c) contained Hedging Obligations permitted from time to time under the Indenture;

(d) pursuant to customary provisions restricting dispositions of real property interests set forth in any reciprocal easement agreements of the Company or any Restricted Subsidiary;

(e) restrictions on cash or other deposits imposed by customers under contracts entered into in the ordinary course of business; or

(f) provisions with respect to the disposition or distribution of assets or property in operating agreements, joint venture agreements, development agreements, area of mutual interest agreements and other agreements that are customary in the Oil and Gas Business and entered into in the ordinary course of business.

(viii) (a) purchase money obligations for property acquired in the ordinary course of business and (b) Capitalized Lease Obligations permitted under the Indenture, in each case, that impose encumbrances or restrictions of the nature described in clause (3) of the first paragraph of this covenant on the property so acquired;

(ix) any encumbrance or restriction with respect to a Restricted Subsidiary (or any of its property or assets) imposed pursuant to an agreement entered into for the direct or indirect sale or disposition of all or a portion of the Capital Stock or assets of such Restricted Subsidiary (or the property or assets that are subject to such restriction) pending the closing of such sale or disposition;

(x) any customary encumbrances or restrictions imposed pursuant to any agreement of the type described in the definition of “Permitted Business Investment”;

(xi) encumbrances or restrictions arising or existing by reason of applicable law or any applicable rule, regulation or order;

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(xii) other Indebtedness of the Company or any of its Restricted Subsidiaries permitted to be Incurred pursuant to an agreement entered into subsequent to the Issue Date in accordance with the covenant described under the caption “—Limitation on Indebtedness and Preferred Stock”; provided that the provisions relating to such encumbrance or restriction contained in such Indebtedness are not materially less favorable to the Company taken as a whole, as determined by the Board of Directors of the Company in good faith, than the provisions contained in the Senior Secured Credit Agreement and in the Indenture as in effect on the Issue Date;

(xiii) the issuance of Preferred Stock by a Restricted Subsidiary or the payment of dividends thereon in accordance with the terms thereof; provided that issuance of such Preferred Stock is permitted pursuant to the covenant described under the caption “—Limitation on Indebtedness and Preferred Stock” and the terms of such Preferred Stock do not expressly restrict the ability of a Restricted Subsidiary to pay dividends or make any other distributions on its Capital Stock (other than requirements to pay dividends or liquidation preferences on such Preferred Stock prior to paying any dividends or making any other distributions on such other Capital Stock);

(xiv) supermajority voting requirements existing under corporate charters, bylaws, stockholders agreements and similar documents and agreements;

(xv) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business; and

(xvi) the Senior Secured Credit Agreement as in effect as of the Issue Date, and any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings thereof; provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are no more restrictive with respect to such dividend and other payment restrictions than those contained in the Senior Secured Credit Agreement as in effect on the Issue Date.

Limitation on sales of assets and Subsidiary stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any Asset Disposition unless:

(1) the Company or such Restricted Subsidiary, as the case may be, receives consideration at the time of such Asset Disposition at least equal to the fair market value (such fair market value to be determined on the date of contractually agreeing to such Asset Disposition), as determined in good faith by the Board of Directors (including as to the value of all non-cash consideration), of the shares and assets subject to such Asset Disposition;

(2) (a) at least 75% of the consideration received by the Company or such Restricted Subsidiary, as the case may be, from such Asset Disposition is in the form of cash or Cash Equivalents or Additional Assets, or any combination thereof or (b) the fair market value of all forms of consideration other than those in clause (a) since the Issue Date which does not exceed in the aggregate 10% of the Company’s Adjusted Consolidated Net Tangible Assets of the Company measured at the time the determination is made; and

(3) except as provided in the next paragraph, an amount equal to 100% of the Net Available Cash from such Asset Disposition is applied, within one year from the later of the date of

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such Asset Disposition or the receipt of such Net Available Cash, by the Company or such Restricted Subsidiary, as the case may be:

(a) to the extent the Company or any Restricted Subsidiary, as the case may be, elects (or is required by the terms of any Indebtedness), to prepay, repay, redeem or purchase Indebtedness of the Company under the Senior Secured Credit Agreement, any other Indebtedness of the Company or a Subsidiary Guarantor that is secured by a Lien permitted to be Incurred under the Indenture or Indebtedness (other than Disqualified Stock) of any Wholly-Owned Subsidiary that is not a Subsidiary Guarantor; provided, however, that, in connection with any prepayment, repayment, redemption or purchase of Indebtedness pursuant to this clause (a), the Company or such Restricted Subsidiary will retire such Indebtedness and will cause the related commitment (if any) to be permanently reduced in an amount equal to the principal amount so prepaid, repaid, redeemed or purchased; or

(b) to invest in Additional Assets;

provided that pending the final application of any such Net Available Cash in accordance with this covenant, the Company and its Restricted Subsidiaries may temporarily reduce Indebtedness or otherwise invest such Net Available Cash in any manner not prohibited by the Indenture.

Any Net Available Cash from Asset Dispositions that is not applied or invested as provided in the preceding paragraph will be deemed to constitute “Excess Proceeds.” Not later than the day following the date that is one year from the later of the date of such Asset Disposition or the receipt of such Net Available Cash, if the aggregate amount of Excess Proceeds exceeds $20.0 million, the Company will be required to make an offer (“Asset Disposition Offer”) to all holders of Notes and, to the extent required by the terms of other Pari Passu Indebtedness, to all holders of other Pari Passu Indebtedness outstanding with similar provisions requiring the Company to make an offer to purchase such Pari Passu Indebtedness with the proceeds from any Asset Disposition (“Pari Passu Notes”) to purchase the maximum principal amount of Notes and any such Pari Passu Notes to which the Asset Disposition Offer applies that may be purchased out of the Excess Proceeds, at an offer price in cash in an amount equal to 100% of the principal amount (or, in the event such Pari Passu Indebtedness of the Company was issued with significant original issue discount, 100% of the accreted value thereof) of the Notes and Pari Passu Notes plus accrued and unpaid interest, if any (or in respect of such Pari Passu Indebtedness, such lesser price, if any, as may be provided for by the terms of such Indebtedness), to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), in accordance with the procedures set forth in the Indenture or the agreements governing the Pari Passu Notes, as applicable, in each case in minimum principal amount of $2,000 and integral multiples of $1,000 in excess of $2,000. If the aggregate principal amount of Notes surrendered by holders thereof and other Pari Passu Notes surrendered by holders or lenders, collectively, exceeds the amount of Excess Proceeds, the Trustee shall select the Notes to be purchased on a pro rata basis on the basis of the aggregate principal amount of tendered Notes and Pari Passu Notes. To the extent that the aggregate amount of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to an Asset Disposition Offer is less than the Excess Proceeds, the Company may use any remaining Excess Proceeds for general corporate purposes, subject to the other covenants contained in the Indenture. Upon completion of such Asset Disposition Offer, the amount of Excess Proceeds shall be reset at zero.

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The Asset Disposition Offer will remain open for a period of 20 Business Days following its commencement, except to the extent that a longer period is required by applicable law (the “Asset Disposition Offer Period”). No later than five Business Days after the termination of the Asset Disposition Offer Period (the “Asset Disposition Purchase Date”), the Company will purchase the principal amount of Notes and Pari Passu Notes required to be purchased pursuant to this covenant (the “Asset Disposition Offer Amount”) or, if less than the Asset Disposition Offer Amount has been so validly tendered, all Notes and Pari Passu Notes validly tendered in response to the Asset Disposition Offer.

If the Asset Disposition Purchase Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest, if any, will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no further interest will be payable to holders who tender Notes pursuant to the Asset Disposition Offer.

On or before the Asset Disposition Purchase Date, the Company will, to the extent lawful, accept for payment, on a pro rata basis to the extent necessary, the Asset Disposition Offer Amount of Notes and Pari Passu Notes or portions of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to the Asset Disposition Offer, or if less than the Asset Disposition Offer Amount has been validly tendered and not properly withdrawn, all Notes and Pari Passu Notes so validly tendered and not properly withdrawn, in each case in minimum principal amount of $2,000 and integral multiples of $1,000 in excess of $2,000. The Company will deliver to the Trustee an Officers’ Certificate stating that such Notes or portions thereof were accepted for payment by the Company in accordance with the terms of this covenant and, in addition, the Company will deliver all certificates and notes required, if any, by the agreements governing the Pari Passu Notes. The Company or the paying agent, as the case may be, will promptly (but in any case not later than five Business Days after the termination of the Asset Disposition Offer Period) mail or deliver to each tendering holder of Notes or holder or lender of Pari Passu Notes, as the case may be, an amount equal to the purchase price of the Notes or Pari Passu Notes so validly tendered and not properly withdrawn by such holder or lender, as the case may be, and accepted by the Company for purchase, and the Company will promptly issue a new Note, and the Trustee, upon delivery of an Officers’ Certificate from the Company, will authenticate and mail or deliver such new Note to such holder, in a principal amount equal to any unpurchased portion of the Note surrendered; provided that each such new Note will be in a minimum principal amount of $2,000 or an integral multiple of $1,000 in excess of $2,000. In addition, the Company will take any and all other actions required by the agreements governing the Pari Passu Notes. Any Note not so accepted will be promptly mailed or delivered by the Company to the holder thereof. The Company will publicly announce the results of the Asset Disposition Offer on the Asset Disposition Purchase Date.

The Company will comply, to the extent applicable, with the requirements of Rule 14e-1 of the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes pursuant to the Indenture. To the extent that the provisions of any securities laws or regulations conflict with provisions of this covenant, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Indenture by virtue of its compliance with such securities laws or regulations.

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For the purposes of clause (2) of the first paragraph of this covenant, the following will be deemed to be cash:

(1) the assumption by the transferee of Indebtedness (other than Subordinated Obligations or Disqualified Stock) of the Company or Indebtedness of a Restricted Subsidiary (other than Guarantor Subordinated Obligations or Disqualified Stock of any Restricted Subsidiary that is a Subsidiary Guarantor) and the release of the Company or such Restricted Subsidiary from all liability on such Indebtedness in connection with such Asset Disposition (or in lieu of such a release, the agreement of the acquirer or its parent company to indemnify and hold the Company or such Restricted Subsidiary harmless from and against any loss, liability or cost in respect of such assumed Indebtedness, in which case the Company will, without further action, be deemed to have applied such deemed cash to Indebtedness in accordance with clause (3)(a) of the first paragraph of this covenant; and

(2) securities, notes or other obligations received by the Company or any Restricted Subsidiary from the transferee that are converted by the Company or such Restricted Subsidiary into cash within 180 days after receipt thereof.

Notwithstanding the foregoing, the 75% limitation referred to in clause (2) of the first paragraph of this covenant shall be deemed satisfied with respect to any Asset Disposition in which the cash or Cash Equivalents portion of the consideration received therefrom, determined in accordance with the foregoing provision on an after-tax basis, is equal to or greater than what the after-tax proceeds would have been had such Asset Disposition complied with the aforementioned 75% limitation.

The requirement of clause (3)(b) of the first paragraph of this covenant above shall be deemed to be satisfied if an agreement (including a lease, whether a capital lease or an operating lease) committing to make the acquisitions or expenditures referred to therein is entered into by the Company or its Restricted Subsidiary within the specified time period and such Net Available Cash is subsequently applied in accordance with such agreement within six months following such agreement.

Limitation on Affiliate Transactions

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, enter into, make, amend or conduct any transaction (including making a payment to, the purchase, sale, lease or exchange of any property or the rendering of any service), contract, agreement or understanding with or for the benefit of any Affiliate of the Company (an “Affiliate Transaction”) unless such Affiliate Transaction complies with the Company’s corporate governance principles and, solely in the case of Affiliate Transactions with Persons other than PVG, PVR or their respective Subsidiaries:

(1) the terms of such Affiliate Transaction are no less favorable to the Company or such Restricted Subsidiary, as the case may be, than those that could be obtained in a comparable transaction at the time of such transaction in arm’s-length dealings with a Person who is not such an Affiliate;

(2) if such Affiliate Transaction involves an aggregate consideration in excess of $10.0 million, the terms of such transaction have been approved by a majority of the members of the Board of Directors of the Company and by a majority of the members of such Board having

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no personal stake in such transaction, if any (and such majority or majorities, as the case may be, determines that such Affiliate Transaction satisfies the criteria in clause (1) above); and

(3) if such Affiliate Transaction involves an aggregate consideration in excess of $25.0 million, the Board of Directors of the Company has received a written opinion from an independent investment banking, accounting or appraisal firm of nationally recognized standing that such Affiliate Transaction is fair, from a financial standpoint, to the Company or such Restricted Subsidiary or is not materially less favorable than those that could reasonably be expected to be obtained in a comparable transaction at such time on an arm’s-length basis from a Person that is not an Affiliate.

The preceding paragraph will not apply to:

(1) any Restricted Payment permitted to be made pursuant to the covenant described under “—Limitation on Restricted Payments” or any Permitted Investment;

(2) any issuance of Capital Stock (other than Disqualified Stock), or other payments, awards or grants in cash, Capital Stock (other than Disqualified Stock) or otherwise pursuant to, or the funding of, employment or severance agreements and other compensation arrangements, options to purchase Capital Stock (other than Disqualified Stock) of the Company, restricted stock plans, long-term incentive plans, stock appreciation rights plans, participation plans or similar employee benefits plans and/or indemnity provided on behalf of officers and employees approved by the Board of Directors of the Company;

(3) loans or advances to employees, officers or directors in the ordinary course of business of the Company or any of its Restricted Subsidiaries;

(4) advances to or reimbursements of employees for moving, entertainment and travel expenses, drawing accounts and similar expenditures in the ordinary course of business of the Company or any of its Restricted Subsidiaries;

(5) any transaction between the Company and a Restricted Subsidiary or between Restricted Subsidiaries and Guarantees issued by the Company or a Restricted Subsidiary for the benefit of the Company or a Restricted Subsidiary, as the case may be, in accordance with “—Limitation on Indebtedness and Preferred Stock”;

(6) any transaction with a joint venture or similar entity which would constitute an Affiliate Transaction solely because the Company or a Restricted Subsidiary owns, directly or indirectly, an Equity Interest in or otherwise controls such joint venture or similar entity;

(7) the issuance or sale of any Capital Stock (other than Disqualified Stock) of the Company or the receipt by the Company of any capital contribution from its shareholders;

(8) indemnities of officers, directors and employees of the Company or any of its Restricted Subsidiaries permitted by bylaw or statutory provisions and any employment agreement or other employee compensation plan or arrangement entered into in the ordinary course of business by the Company or any of its Restricted Subsidiaries;

(9) the payment of reasonable compensation and fees paid to, and indemnity provided on behalf of, officers or directors of the Company or any Restricted Subsidiary;

(10) the performance of obligations of the Company or any of its Restricted Subsidiaries under the terms of any agreement to which the Company or any of its Restricted Subsidiaries is a party as of or on the Issue Date, as these agreements may be amended, modified,

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supplemented, extended or renewed from time to time; provided, however, that any future amendment, modification, supplement, extension or renewal entered into after the Issue Date will be permitted to the extent that its terms are not materially more disadvantageous, taken as a whole, to the holders of the Notes than the terms of the agreements in effect on the Issue Date;

(11) transactions with customers, clients, suppliers, or purchasers or sellers of goods or services, in each case in the ordinary course of business and otherwise in compliance with the terms of the Indenture which are fair to the Company and its Restricted Subsidiaries, in the reasonable determination of the board of directors of the Company or the senior management thereof, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party;

(12) transactions with a Person (other than an Unrestricted Subsidiary) that is an Affiliate of the Company solely because the Company owns, directly or through a Restricted Subsidiary, an Equity Interest in such Person; and

(13) transactions between the Company or any Restricted Subsidiary and any Person, a director of which is also a director of the Company or any direct or indirect parent company of the Company and such director is the sole cause for such Person to be deemed an Affiliate of the Company or any Restricted Subsidiary; provided, however, that such director shall abstain from voting as a director of the Company or such direct or indirect parent company, as the case may be, on any matter involving such other Person.

Provision of financial information

The Indenture will provide that, whether or not the Company is subject to the reporting requirements of Section 13 or Section 15(d) of the Exchange Act, to the extent not prohibited by the Exchange Act, the Company will file with the SEC, and make available to the Trustee and the registered holders of the Notes without cost to any holder, the annual reports and the information, documents and other reports (or copies of such portions of any of the foregoing as the SEC may by rules and regulations prescribe) that are specified in Sections 13 and 15(d) of the Exchange Act and applicable to a U.S. corporation within the time periods specified therein with respect to an accelerated filer. In the event that the Company is not permitted to file such reports, documents and information with the SEC pursuant to the Exchange Act, the Company will nevertheless make available such Exchange Act information to the Trustee and the holders of the Notes without cost to any holder as if the Company were subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act within the time periods specified therein with respect to a non-accelerated filer.

So long as the Company continues to have designated certain of its Subsidiaries as Unrestricted Subsidiaries, then the financial information required will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in Management’s Discussion and Analysis of Financial Condition and Results of Operations, of the financial condition and results of operations of the Company and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Company.

The availability of the foregoing materials on the SEC’s website or on the Company’s website shall be deemed to satisfy the foregoing delivery obligations.

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Merger and consolidation

The Company will not consolidate with or merge with or into or wind up into (whether or not the Company is the surviving corporation), or convey, transfer or lease all or substantially all its assets in one or more related transactions to, any Person, unless:

(1) the resulting, surviving or transferee Person (the “Successor Company”) will be a corporation, partnership, trust or limited liability company organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and the Successor Company (if not the Company) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, in form reasonably satisfactory to the Trustee, all the obligations of the Company under the Notes and the Indenture;

(2) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the Successor Company or any Subsidiary of the Successor Company as a result of such transaction as having been Incurred by the Successor Company or such Subsidiary at the time of such transaction), no Default shall have occurred and be continuing;

(3) either (A) immediately after giving effect to such transaction, the Successor Company would be able to Incur at least an additional $1.00 of Indebtedness pursuant to the first paragraph of the covenant described under “—Limitation on Indebtedness and Preferred Stock” or (B) immediately after giving effect to such transaction on a pro forma basis and any related financing transactions as if the same had occurred at the beginning of the applicable four quarter period, the Consolidated Coverage Ratio of the Company is equal to or greater than the Consolidated Coverage Ratio of the Company immediately before such transaction;

(4) each Subsidiary Guarantor (unless it is the other party to the transactions above, in which case clause (1) shall apply) shall have by supplemental indenture confirmed that its Subsidiary Guarantee shall apply to such Person’s obligations in respect of the Indenture and the Notes shall continue to be in effect; and

(5) the Company shall have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indenture (if any) comply with the Indenture.

For purposes of this covenant, the sale, lease, conveyance, assignment, transfer or other disposition of all or substantially all of the properties and assets of one or more Subsidiaries of the Company, which properties and assets, if held by the Company instead of such Subsidiaries, would constitute all or substantially all of the properties and assets of the Company on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the properties and assets of the Company.

The Successor Company will succeed to, and be substituted for, and may exercise every right and power of, the Company under the Indenture; and its predecessor Company, except in the case of a lease of all or substantially all its assets, will be released from the obligation to pay the principal of and interest on the Notes.

Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the property or assets of a Person.

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Notwithstanding the preceding clause (3), (x) any Restricted Subsidiary may consolidate with, merge into or transfer all or part of its properties and assets to the Company and the Company may consolidate with, merge into or transfer all or part of its properties and assets to a Wholly-Owned Subsidiary and (y) the Company may merge with an Affiliate incorporated solely for the purpose of reincorporating the Company in another jurisdiction; provided that, in the case of a Restricted Subsidiary that consolidates with, merges into or transfers all or part of its properties and assets to the Company, the Company will not be required to comply with the preceding clause (5).

In addition, the Company will not permit any Subsidiary Guarantor to consolidate with or merge with or into, and will not permit the conveyance, transfer or lease of substantially all of the assets of any Subsidiary Guarantor to, any Person (other than the Company or another Subsidiary Guarantor) unless:

(1) (a) the resulting, surviving or transferee Person will be a corporation, partnership, trust or limited liability company organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and such Person (if not such Subsidiary Guarantor) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, all the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee and (b) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the resulting, surviving or transferee Person or any Restricted Subsidiary as a result of such transaction as having been Incurred by such Person or such Restricted Subsidiary at the time of such transaction), no Default shall have occurred and be continuing; or

(2) the transaction is made in compliance with the covenants described under “Subsidiary guarantees” and “Certain Covenants—Limitation on sales of assets and Subsidiary stock.”

Future subsidiary guarantors

The Indenture will provide that the Company will cause each Restricted Subsidiary that Guarantees any Indebtedness under a Credit Facility or other capital markets Indebtedness, other than a Foreign Subsidiary created or acquired by the Company or one or more of its Restricted Subsidiaries, to execute and deliver to the Trustee a Subsidiary Guarantee pursuant to which such Subsidiary Guarantor will unconditionally Guarantee, on a joint and several basis, the full and prompt payment of the principal of, premium, if any, and interest, if any, on the Notes on a senior basis; provided that any Restricted Subsidiary that constitutes an Immaterial Subsidiary need not become a Subsidiary Guarantor until such time as it ceases to be an Immaterial Subsidiary.

Payments for consent

Neither the Company nor any of its Restricted Subsidiaries will, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fees or otherwise, to any holder of any Notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the Indenture or the Notes unless such consideration is offered to be paid or is paid to all holders of the Notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or amendment.

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Covenant termination

From and after the occurrence of an Investment Grade Rating Event, the Company and its Restricted Subsidiaries will no longer be subject to the provisions of the Indenture described above under the following headings:

• “ —Limitation on Indebtedness and Preferred Stock,”

• “—Limitation on Restricted Payments,”

• “—Limitation on restrictions on distributions from Restricted Subsidiaries,”

• “—Limitation on sales of assets and Subsidiary stock,”

• “—Limitation on Affiliate Transactions,” and

• Clause (3) of “—Merger and consolidation”

(collectively, the “Eliminated Covenants”). As a result, after the date on which the Company and its Restricted Subsidiaries are no longer subject to the Eliminated Covenants, the Notes will be entitled to substantially reduced covenant protection.

After the foregoing covenants have been terminated, the Company may not designate any of its Subsidiaries as Unrestricted Subsidiaries pursuant to the second sentence of the definition of “Unrestricted Subsidiary.”

Events of default

Each of the following is an Event of Default:

(1) default in any payment of interest on any Note when due, continued for 30 days;

(2) default in the payment of principal of or premium, if any, on any Note when due at its Stated Maturity, upon optional redemption, upon required repurchase, upon declaration of acceleration or otherwise;

(3) failure by the Company or any Subsidiary Guarantor to comply with its obligations under “Certain covenants—Merger and consolidation”;

(4) failure by the Company to comply for 30 days after notice as provided below with any of its obligations under the covenant described under “Change of Control” above or under the covenants described under “Certain covenants” above (in each case, other than a failure to purchase Notes which will constitute an Event of Default under clause (2) above and other than a failure to comply with “Certain covenants—Merger and consolidation” which is covered by clause (3));

(5) failure by the Company to comply for 60 days (or 180 days in the case of a Reporting Failure) after notice as provided below with its other agreements contained in the Indenture;

(6) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), other than Indebtedness owed to the

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Company or a Restricted Subsidiary, whether such Indebtedness or guarantee now exists, or is created after the date of the Indenture, which default:

(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness (and any extensions of any grace period) (“payment default”); or

(b) results in the acceleration of such Indebtedness prior to its maturity (the “cross acceleration provision”);

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a payment default or the maturity of which has been so accelerated, aggregates $15.0 million or more;

(7) certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary (the “bankruptcy provisions”);

(8) failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary to pay final judgments aggregating in excess of $15.0 million (to the extent not covered by insurance by a reputable and creditworthy insurer as to which the insurer has not disclaimed coverage), which judgments are not paid or discharged, and there shall be any period of 60 consecutive days following entry of such final judgment or decree during which a stay of enforcement of such final judgment or decree, by reason of pending appeal or otherwise, shall not be in effect (the “judgment default provision”); or

(9) any Subsidiary Guarantee of a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries) would constitute a Significant Subsidiary ceases to be in full force and effect (except as contemplated by the terms of the Indenture) or is declared null and void in a judicial proceeding or any Subsidiary Guarantor that is a Significant Subsidiary or group of Subsidiary Guarantors that, taken together (as of the latest audited consolidated financial statements of the Company and its Restricted Subsidiaries) would constitute a Significant Subsidiary denies or disaffirms its obligations under the Indenture or its Subsidiary Guarantee.

However, a default under clauses (4) and (5) of this paragraph will not constitute an Event of Default until the Trustee or the holders of 25% in principal amount of the outstanding Notes notify the Company in writing and, in the case of a notice given by the holders, the Trustee of the default and the Company does not cure such default within the time specified in clauses (4) and (5) of this paragraph after receipt of such notice.

If an Event of Default (other than an Event of Default described in clause (7) above) occurs and is continuing, the Trustee by notice to the Company, or the holders of at least 25% in principal amount of the outstanding Notes by notice to the Company and the Trustee, may, and the Trustee at the request of such holders shall, declare the principal of, premium, if any, accrued and unpaid interest, if any, on all the Notes to be due and payable. If an Event of Default described in clause (7) above occurs and is continuing, the principal of, premium, if any, accrued

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and unpaid interest, if any, on all the Notes will become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders. The holders of a majority in principal amount of the outstanding Notes may waive all past defaults (except with respect to nonpayment of principal, premium or interest, if any) and rescind any such acceleration with respect to the Notes and its consequences if (1) rescission would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the Notes that have become due solely by such declaration of acceleration, have been cured or waived.

Notwithstanding the foregoing, if an Event of Default specified in clause (6) above shall have occurred and be continuing, such Event of Default and any consequential acceleration (to the extent not in violation of any applicable law) shall be automatically rescinded if (i) the Indebtedness that is the subject of such Event of Default has been repaid or (ii) if the default relating to such Indebtedness is waived or cured and if such Indebtedness has been accelerated, then the holders thereof have rescinded their declaration of acceleration in respect of such Indebtedness.

Subject to the provisions of the Indenture relating to the duties of the Trustee, if an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the Indenture at the request or direction of any of the holders unless such holders have offered to the Trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest when due, no holder may pursue any remedy with respect to the Indenture or the Notes unless:

(1) such holder has previously given the Trustee notice that an Event of Default is continuing;

(2) holders of at least 25% in principal amount of the outstanding Notes have requested the Trustee to pursue the remedy;

(3) such holders have offered the Trustee reasonable security or indemnity against any loss, liability or expense;

(4) the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

(5) the holders of a majority in principal amount of the outstanding Notes have not waived such Event of Default or otherwise given the Trustee a direction that, in the opinion of the Trustee, is inconsistent with such request within such 60-day period.

Subject to certain restrictions, the holders of a majority in principal amount of the outstanding Notes are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. The Indenture provides that in the event an Event of Default has occurred and is continuing, the Trustee will be required in the exercise of its powers to use the degree of care that a prudent person would use in the conduct of its own affairs. The Trustee, however, may refuse to follow any direction that conflicts with law or the Indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder or that would involve the Trustee in personal liability. Prior to taking any action under the Indenture, the Trustee will be entitled to indemnification satisfactory to it in its sole discretion against all losses and expenses caused by taking or not taking such action.

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The Trustee may withhold notice if and so long as a committee of trust officers of the Trustee in good faith determines that withholding notice is in the interests of the holders. In addition, the Company is required to deliver to the Trustee, within 120 days after the end of each fiscal year, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year. The Company also is required to deliver to the Trustee, within 30 days after the occurrence thereof, written notice of any events which would constitute certain Defaults, their status and what action the Company is taking or proposing to take in respect thereof.

Amendments and waivers

Subject to certain exceptions, the Indenture and the Notes may be amended or supplemented with the consent of the holders of a majority in principal amount of the Notes then outstanding (including without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes) and, subject to certain exceptions, any past default or compliance with any provisions may be waived with the consent of the holders of a majority in principal amount of the Notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes). However, without the consent of each holder of an outstanding Note affected, no amendment may, among other things:

(1) reduce the principal amount of Notes whose holders must consent to an amendment, supplement or waiver;

(2) reduce the stated rate of or extend the stated time for payment of interest on any Note;

(3) reduce the principal of or extend the Stated Maturity of any Note;

(4) reduce the premium payable upon the redemption of any Note as described above under “Optional redemption,” or change the time at which any Note may be redeemed as described above under “Optional redemption,” (other than the provisions described above under “Change of Control” and “—Certain covenants—Limitation on sales of assets or Subsidiary stock”);

(5) make any Note payable in money other than that stated in the Note;

(6) impair the right of any holder to receive payment of, premium, if any, principal of and interest on such holder’s Notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder’s Notes;

(7) make any change in the amendment provisions which require each holder’s consent or in the waiver provisions;

(8) modify the Subsidiary Guarantees in any manner adverse to the holders of the Notes; or

(9) make any change to or modify the ranking of the Notes that would adversely affect the holders.

Notwithstanding the foregoing, without the consent of any holder, the Company, the Guarantors and the Trustee may amend the Indenture and the Notes to:

(1) cure any ambiguity, omission, defect, mistake or inconsistency;

(2) provide for the assumption by a successor corporation of the obligations of the Company or any Subsidiary Guarantor under the Indenture;

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(3) provide for uncertificated Notes in addition to or in place of certificated Notes (provided that the uncertificated Notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated Notes are described in Section 163(f)(2)(B) of the Code);

(4) add Guarantees with respect to the Notes, including Subsidiary Guarantees, or release a Subsidiary Guarantor from its Subsidiary Guarantee and terminate such Subsidiary Guarantee; provided that the release and termination is in accord with the applicable provisions of the Indenture;

(5) secure the Notes or Subsidiary Guarantees;

(6) add to the covenants of the Company or a Subsidiary Guarantor for the benefit of the holders or surrender any right or power conferred upon the Company or a Subsidiary Guarantor;

(7) make any change that does not adversely affect the rights of any holder;

(8) comply with any requirement of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act; or

(9) provide for the succession of a successor Trustee.

The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. A consent to any amendment or waiver under the Indenture by any holder of Notes given in connection with a tender of such holder’s Notes will not be rendered invalid by such tender. After an amendment under the Indenture becomes effective, the Company is required to mail to the holders a notice briefly describing such amendment. However, the failure to give such notice to all the holders, or any defect in the notice will not impair or affect the validity of the amendment.

Defeasance

The Company at any time may terminate all its obligations under the Notes and the Indenture (“legal defeasance”), except for certain obligations, including those respecting the defeasance trust and obligations to register the transfer or exchange of the Notes, to replace mutilated, destroyed, lost or stolen Notes and to maintain a registrar and paying agent in respect of the Notes. If the Company exercises its legal defeasance option, the Subsidiary Guarantees in effect at such time will terminate.

The Company at any time may terminate its obligations described under “Change of Control” and under covenants described under “Certain covenants” (other than clauses (1), (2), (4) and (5) of “Merger and consolidation”), the operation of the cross default upon a payment default, cross acceleration provisions, the bankruptcy provisions with respect to Significant Subsidiaries, the judgment default provision, the Subsidiary Guarantee provision described under “Events of default” above and the limitations contained in clause (3) under “Certain covenants—Merger and consolidation” above, and the Company and the Subsidiary Guarantors may terminate the obligations of the Subsidiary Guarantors to provide the Subsidiary Guarantees, which thereupon shall be automatically released (“covenant defeasance”).

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The Company may exercise its legal defeasance option notwithstanding its prior exercise of its covenant defeasance option. If the Company exercises its legal defeasance option, payment of the Notes may not be accelerated because of an Event of Default with respect to the Notes. If the Company exercises its covenant defeasance option, payment of the Notes may not be accelerated because of an Event of Default specified in clause (4), (5), (6), (7) (with respect only to Significant Subsidiaries), (8) or (9) under “Events of default” above or because of the failure of the Company to comply with clause (3) under “Certain covenants—Merger and consolidation” above.

In order to exercise either defeasance option, the Company must, among other things, irrevocably deposit in trust (the “defeasance trust”) with the Trustee money or U.S. Government Obligations for the payment of principal, premium, if any, and interest on the Notes to redemption or maturity, as the case may be, and must comply with certain other conditions, including delivery to the Trustee of an Opinion of Counsel (subject to customary exceptions and exclusions) to the effect that holders of the Notes will not recognize income, gain or loss for federal income tax purposes as a result of such deposit and defeasance and will be subject to Federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance only, such Opinion of Counsel must be based on a ruling of the Internal Revenue Service or other change in applicable federal income tax law.

Satisfaction and discharge

The Indenture will be discharged and will cease to be of further effect as to all Notes issued thereunder, when either:

(1) all Notes that have been authenticated (except lost, stolen or destroyed Notes that have been replaced or paid and Notes for whose payment money has theretofore been deposited in trust or segregated and held in trust by the Company and thereafter repaid to the Company or discharged from such trust) have been delivered to the Trustee for cancellation, or

(2) all Notes that have not been delivered to the Trustee for cancellation have become due and payable or will become due and payable within one year by reason of the giving of a notice of redemption or otherwise and the Company or any Subsidiary Guarantor has irrevocably deposited or caused to be irrevocably deposited with the Trustee as trust funds in trust solely for such purpose, cash in U.S. dollars, U.S. Government Obligations, or a combination thereof, in such amounts as will be sufficient without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the Notes not delivered to the Trustee for cancellation for principal and accrued interest to the date of maturity or redemption, and in each case certain other requirements set forth in the Indenture are satisfied.

No personal liability of directors, officers, employees and stockholders

No director, officer, employee, incorporator, stockholder, member, partner or trustee of the Company or any Subsidiary Guarantor, as such, shall have any liability for any obligations of the Company or any Subsidiary Guarantor under the Notes, the Indenture or the Subsidiary Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

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Concerning the trustee

Wells Fargo Bank, National Association will be the Trustee under the Indenture and has been appointed by the Company as registrar and paying agent with regard to the Notes.

Governing law

The Indenture provides that it and the Notes will be governed by, and construed in accordance with, the laws of the State of New York.

Certain definitions

“Acquired Indebtedness” means Indebtedness (i) of a Person or any of its Subsidiaries existing at the time such Person becomes or is merged with and into a Restricted Subsidiary or (ii) assumed in connection with the acquisition of assets from such Person, in each case whether or not Incurred by such Person in connection with, or in anticipation or contemplation of, such Person becoming a Restricted Subsidiary or such acquisition. Acquired Indebtedness shall be deemed to have been Incurred, with respect to clause (i) of the preceding sentence, on the date such Person becomes or is merged with and into a Restricted Subsidiary and, with respect to clause (ii) of the preceding sentence, on the date of consummation of such acquisition of assets.

“Additional Assets” means:

(1) any properties or assets to be used by the Company or a Restricted Subsidiary in the Oil and Gas Business;

(2) capital expenditures by the Company or a Restricted Subsidiary in the Oil and Gas Business;

(3) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or a Restricted Subsidiary; or

(4) Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided, however, that, in the case of clauses (3) and (4), such Restricted Subsidiary is primarily engaged in the Oil and Gas Business.

“Adjusted Consolidated Net Tangible Assets” of a Person means (without duplication), as of the date of determination, the remainder of:

(a) the sum of:

(i) discounted future net revenues from proved oil and gas reserves of such Person and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated by the Company in a reserve report prepared as of the end of the Company’s most recently completed fiscal year for which audited financial statements are available, as increased by, as of the date of determination, the estimated discounted future net revenues from

(A) estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end reserve report, and

(B) estimated oil and gas reserves attributable to extensions, discoveries and other additions and upward revisions of estimates of proved oil and gas reserves since such

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year end due to exploration, development or exploitation, production or other activities, which would, in accordance with standard industry practice, cause such revisions,

in the case of clauses (A) and (B) calculated in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination), and decreased by, as of the date of determination, the estimated discounted future net revenues from

(C) estimated proved oil and gas reserves produced or disposed of since such year end, and

(D) estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since such year end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis and substantially in accordance with SEC guidelines

in the case of clauses (C) and (D) utilizing the prices for the fiscal quarter ending prior to the date of determination; provided, however, that in the case of each of the determinations made pursuant to clauses (A) through (D), such increases and decreases shall be as estimated by the Company’s petroleum engineers;

(ii) the capitalized costs that are attributable to Oil and Gas Properties of such Person and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on such Person’s books and records as of a date no earlier than the date of such Person’s latest available annual or quarterly financial statements;

(iii) the Net Working Capital of such Person on a date no earlier than the date of such Person’s latest annual or quarterly financial statements; and

(iv) the greater of

(A) the net book value of other tangible assets of such Person and its Restricted Subsidiaries, as of a date no earlier than the date of such Person’s latest annual or quarterly financial statement, and

(B) the appraised value, as estimated by independent appraisers, of other tangible assets of such Person and its Restricted Subsidiaries, as of a date no earlier than the date of such Person’s latest audited financial statements; provided, that, if no such appraisal has been performed the Company shall not be required to obtain such an appraisal and only clause (iv)(A) of this definition shall apply;

minus

(b) the sum of:

(i) Minority Interests;

(ii) any net gas balancing liabilities of such Person and its Restricted Subsidiaries reflected in such Person’s latest annual or quarterly balance sheet (to the extent not deducted in calculating Net Working Capital of such Person in accordance with clause (a)(iii) above of this definition);

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(iii) to the extent included in (a)(i) above, the discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in such Person’s year end reserve report), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto); and

(iv) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of such Person and its Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

If the Company changes its method of accounting from the successful efforts method of accounting to the full cost or a similar method, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if the Company were still using the successful efforts method of accounting.

“Affiliate” of any specified Person means any other Person, directly or indirectly, controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, “control” when used with respect to any Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing.

“Asset Disposition” means any direct or indirect sale, lease (other than an operating lease entered into in the ordinary course of the Oil and Gas Business), transfer, issuance or other disposition, or a series of related sales, leases, transfers, issuances or dispositions that are part of a common plan, of (A) shares of Capital Stock of a Restricted Subsidiary (other than Preferred Stock of Restricted Subsidiaries issued in compliance with the covenant described under the heading “Certain covenants—Limitation on Indebtedness and Preferred Stock,” and directors’ qualifying shares or shares required by applicable law to be held by a Person other than the Company or a Restricted Subsidiary), (B) all or substantially all the assets of any division or line of business of the Company or any Restricted Subsidiary (excluding any division or line of business the assets of which are owned by an Unrestricted Subsidiary) or (C) any other assets of the Company (excluding shares of Capital Stock of an Unrestricted Subsidiary) or any Restricted Subsidiary outside of the ordinary course of business of the Company or such Restricted Subsidiary (each referred to for the purposes of this definition as a “disposition”), in each case by the Company or any of its Restricted Subsidiaries, including any disposition by means of a merger, consolidation or similar transaction.

Notwithstanding the preceding, the following items shall not be deemed to be Asset Dispositions:

(1) a disposition by a Restricted Subsidiary to the Company or by the Company or a Restricted Subsidiary to a Restricted Subsidiary;

(2) the sale of cash and Cash Equivalents in the ordinary course of business;

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(3) a disposition of Hydrocarbons or mineral products inventory in the ordinary course of business;

(4) a disposition of damaged, unserviceable, obsolete or worn out equipment or equipment that is no longer necessary for the proper conduct of the business of the Company and its Restricted Subsidiaries and that is disposed of in each case in the ordinary course of business;

(5) transactions in accordance with the covenant described under “Certain covenants—Merger and consolidation”;

(6) an issuance of Capital Stock by a Restricted Subsidiary to the Company or to a Restricted Subsidiary;

(7) the making of a Permitted Investment or a Restricted Payment (or a disposition that would constitute a Restricted Payment but for the exclusions from the definition thereof) permitted by the covenant described under “Certain covenants—Limitation on Restricted Payments”;

(8) an Asset Swap;

(9) dispositions of assets with a fair market value of less than $5.0 million;

(10) Permitted Liens;

(11) dispositions of receivables in connection with the compromise, settlement or collection thereof in the ordinary course of business or in bankruptcy or similar proceedings and exclusive of factoring or similar arrangements;

(12) the licensing or sublicensing of intellectual property (including, without limitation, the licensing of seismic data) or other general intangibles and licenses, leases or subleases of other property in the ordinary course of business which do not materially interfere with the business of the Company and its Restricted Subsidiaries;

(13) foreclosure on assets;

(14) any Production Payments and Reserve Sales; provided that any such Production Payments and Reserve Sales, other than incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Company or a Restricted Subsidiary, shall have been created, Incurred, issued, assumed or Guaranteed in connection with the financing of, and within 60 days after the acquisition of, the property that is subject thereto;

(15) a disposition of oil and natural gas properties in connection with tax credit transactions complying with Section 29 or any successor or analogous provisions of the Code;

(16) surrender or waiver of contract rights, oil and gas leases, or the settlement, release or surrender of contract, tort or other claims of any kind;

(17) the abandonment, farmout, lease or sublease of developed or undeveloped Oil and Gas Properties in the ordinary course of business; and

(18) the sale or transfer (whether or not in the ordinary course of business) of any Oil and Gas Property or interest therein to which no proved reserves are attributable at the time of such sale or transfer.

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“Asset Swap” means any substantially contemporaneous (and in any event occurring within 180 days of each other) purchase and sale or exchange of any oil or natural gas properties or assets or interest therein between the Company or any of its Restricted Subsidiaries and another Person; provided, that any cash received must be applied in accordance with “Certain covenants— Limitation on sales of assets and Subsidiary stock” as if the Asset Swap were an Asset Disposition.

“Average Life” means, as of the date of determination, with respect to any Indebtedness or Preferred Stock, the quotient obtained by dividing (1) the sum of the products of the numbers of years from the date of determination to the dates of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Preferred Stock multiplied by the amount of such payment by (2) the sum of all such payments.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning.

“Board of Directors” means, as to any Person that is a corporation, the board of directors of such Person or any duly authorized committee thereof or as to any Person that is not a corporation, the board of managers or such other individual or group serving a similar function.

“Business Day” means each day that is not a Saturday, Sunday or other day on which commercial banking institutions in New York, New York are authorized or required by law to close.

“Capital Stock” of any Person means any and all shares, units, interests, rights to purchase, warrants, options, participation or other equivalents of or interests in (however designated) equity of such Person, including any Preferred Stock, but excluding any debt securities convertible into such equity.

“Capitalized Lease Obligations” means an obligation that is required to be classified and accounted for as a capitalized lease for financial reporting purposes in accordance with GAAP, and the amount of Indebtedness represented by such obligation will be the capitalized amount of such obligation at the time any determination thereof is to be made as determined in accordance with GAAP, and the Stated Maturity thereof will be the date of the last payment of rent or any other amount due under such lease prior to the first date such lease may be terminated without penalty.

“Cash Equivalents” means:

(1) securities issued or directly and fully guaranteed or insured by the United States Government or any agency or instrumentality of the United States (provided that the full faith and credit of the United States is pledged in support thereof), having maturities of not more than one year from the date of acquisition;

(2) marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition (provided that the full faith and credit of the United States is pledged in support thereof) and, at the time of acquisition, having a credit rating of “A” (or the equivalent thereof) or better from either S&P or Moody’s;

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(3) certificates of deposit, time deposits, eurodollar time deposits, overnight bank deposits or bankers’ acceptances having maturities of not more than one year from the date of acquisition thereof issued by any commercial bank the short-term deposit of which is rated at the time of acquisition thereof at least “A2” or the equivalent thereof by S&P, or “P-2” or the equivalent thereof by Moody’s, and having combined capital and surplus in excess of $100.0 million;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (1), (2) and (3) entered into with any bank meeting the qualifications specified in clause (3) above;

(5) commercial paper rated at the time of acquisition thereof at least “A-2” or the equivalent thereof by S&P or “P-2” or the equivalent thereof by Moody’s, or carrying an equivalent rating by a nationally recognized rating agency, if both of the two named rating agencies cease publishing ratings of investments, and in any case maturing within one year after the date of acquisition thereof; and

(6) interests in any investment company or money market fund which invests 95% or more of its assets in instruments of the type specified in clauses (1) through (5) above.

“Change of Control” means:

(1) any “person” or “group” of related persons (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act), is or becomes the Beneficial Owner, directly or indirectly, of more than 50% of the total voting power of the Voting Stock of the Company (or its successor by merger, consolidation or purchase of all or substantially all of its assets) (for the purposes of this clause (1), such person or group shall be deemed to Beneficially Own any Voting Stock of the Company held by a parent entity, if such person or group Beneficially Owns, directly or indirectly, more than 50% of the total voting power of the Voting Stock of such parent entity);

(2) the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors;

(3) the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act); or

(4) the adoption by the shareholders of the Company of a plan or proposal for the liquidation or dissolution of the Company.

“Code” means the Internal Revenue Code of 1986, as amended.

“Commodity Agreements” means, in respect of any Person, any forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement in respect of Hydrocarbons used, produced, processed or sold by such Person that are customary in the Oil and Gas Business and designed to protect such Person against fluctuation in Hydrocarbon prices.

“Common Stock” means, with respect to any Person, any and all shares, interests or other participations in, and other equivalents (however designated and whether voting or nonvoting)

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of such Person’s common stock whether or not outstanding on the Issue Date, and includes, without limitation, all series and classes of such common stock.

“Consolidated Coverage Ratio” means as of any date of determination, the ratio of (x) the aggregate amount of Consolidated EBITDAX of such Person for the period of the most recent four consecutive fiscal quarters ending prior to the date of such determination for which financial statements are in existence to (y) Consolidated Interest Expense for such four fiscal quarters, provided, however, that:

(1) if the Company or any Restricted Subsidiary:

(a) has Incurred any Indebtedness since the beginning of such period that remains outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such Indebtedness and the use of proceeds thereof as if such Indebtedness had been Incurred on the first day of such period and such proceeds had been applied as of such date (except that in making such computation, the amount of Indebtedness under any revolving Credit Facility outstanding on the date of such calculation will be deemed to be (i) the average daily balance of such Indebtedness during such four fiscal quarters or such shorter period for which such facility was outstanding or (ii) if such revolving Credit Facility was created after the end of such four fiscal quarters, the average daily balance of such Indebtedness during the period from the date of creation of such revolving Credit Facility to the date of such calculation, in each case, provided that such average daily balance shall take into account any repayment of Indebtedness under such revolving Credit Facility as provided in clause (b)); or

(b) has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of the period, including with the proceeds of such new Indebtedness, that is no longer outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio involves a discharge of Indebtedness (in each case other than Indebtedness Incurred under any revolving Credit Facility unless such Indebtedness has been permanently repaid and the related commitment terminated), Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such discharge of such Indebtedness as if such discharge had occurred on the first day of such period;

(2) if, since the beginning of such period, the Company or any Restricted Subsidiary has made any Asset Disposition or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is such an Asset Disposition, the Consolidated EBITDAX for such period will be reduced by an amount equal to the Consolidated EBITDAX (if positive) directly attributable to the assets which are the subject of such Asset Disposition for such period or increased by an amount equal to the Consolidated EBITDAX (if negative) directly attributable thereto for such period and Consolidated Interest Expense for such period shall be reduced by an amount equal to the Consolidated Interest Expense directly attributable to any Indebtedness of the Company or any Restricted Subsidiary repaid, repurchased, defeased or otherwise discharged with respect to the Company and its continuing Restricted Subsidiaries in connection with or with the proceeds from such Asset Disposition for such period (or, if the Capital Stock of any Restricted Subsidiary is sold, the Consolidated Interest Expense for

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such period directly attributable to the Indebtedness of such Restricted Subsidiary to the extent the Company and its continuing Restricted Subsidiaries are no longer liable for such Indebtedness after such sale);

(3) if, since the beginning of such period, the Company or any Restricted Subsidiary (by merger or otherwise) has made an Investment in any Restricted Subsidiary (or any Person which becomes a Restricted Subsidiary or is merged with or into the Company or a Restricted Subsidiary) or an acquisition (or will have received a contribution) of assets, including any acquisition or contribution of assets occurring in connection with a transaction causing a calculation to be made hereunder, which constitutes all or substantially all of a company, division, operating unit, segment, business, group of related assets or line of business, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto (including the Incurrence of any Indebtedness) as if such Investment or acquisition or contribution had occurred on the first day of such period; and

(4) if, since the beginning of such period, any Person (that subsequently became a Restricted Subsidiary or was merged with or into the Company or any Restricted Subsidiary since the beginning of such period) made any Asset Disposition or any Investment or acquisition of assets that would have required an adjustment pursuant to clause (2) or (3) above if made by the Company or a Restricted Subsidiary during such period, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto as if such Asset Disposition or Investment or acquisition of assets had occurred on the first day of such period.

For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined in good faith by a responsible financial or accounting officer of the Company; provided that such officer may in his or her discretion include any reasonably identifiable and factually supportable pro forma changes to Consolidated EBITDAX, including any pro forma expenses and cost reductions, that have occurred or in the judgment of such officer are reasonably expected to occur within 12 months of the date of the applicable transaction (regardless of whether such expense or cost reduction or any other operating improvements could then be reflected properly in pro forma financial statements prepared in accordance with Regulation S-X under the Securities Act or any other regulation or policy of the SEC). If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of such period to the date of determination had been the applicable rate for the entire period (taking into account any Interest Rate Agreement applicable to such Indebtedness, but if the remaining term of such Interest Rate Agreement is less than 12 months, then such Interest Rate Agreement shall only be taken into account for that portion of the period equal to the remaining term thereof). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of the Company, the interest rate shall be calculated by applying such optional rate chosen by the Company. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as the Company may designate.

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“Consolidated EBITDAX” for any period means, without duplication, the Consolidated Net Income for such period, plus the following, without duplication and to the extent deducted (and not added back) in calculating such Consolidated Net Income:

(1) Consolidated Interest Expense;

(2) Consolidated Income Taxes of the Company and its Restricted Subsidiaries;

(3) consolidated depletion and depreciation expense of the Company and its Restricted Subsidiaries;

(4) consolidated amortization expense or impairment charges of the Company and its Restricted Subsidiaries recorded in connection with the application of Statement of Financial Accounting Standard No. 142, “Goodwill and Other Intangibles” and Statement of Financial Accounting Standard No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets”;

(5) other non-cash charges of the Company and its Restricted Subsidiaries (excluding any such non-cash charge to the extent it represents an accrual of or reserve for cash charges in any future period or amortization of a prepaid cash expense that was paid in a prior period not included in the calculation); and

(6) consolidated exploration expense of the Company and its Restricted Subsidiaries,

if applicable for such period; and less, to the extent included in calculating such Consolidated Net Income and in excess of any costs or expenses attributable thereto that were deducted (and not added back) in calculating such Consolidated Net Income, the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments, (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments and (z) other non-cash gains (excluding any non-cash gain to the extent it represents the reversal of an accrual or reserve for a potential cash item that reduced Consolidated EBITDAX in any prior period).

Notwithstanding the preceding sentence, clauses (2) through (6) relating to amounts of a Restricted Subsidiary of a Person will be added to Consolidated Net Income to compute Consolidated EBITDAX of such Person only to the extent (and in the same proportion) that the net income (loss) of such Restricted Subsidiary was included in calculating the Consolidated Net Income of such Person and, to the extent the amounts set forth in clauses (2) through (6) are in excess of those necessary to offset a net loss of such Restricted Subsidiary or if such Restricted Subsidiary has net income for such period included in Consolidated Net Income, only if a corresponding amount would be permitted at the date of determination to be dividended to the Company by such Restricted Subsidiary without prior approval (that has not been obtained), pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Restricted Subsidiary or its stockholders.

“Consolidated Income Taxes” means, with respect to any Person for any period, taxes imposed upon such Person or other payments required to be made by such Person by any governmental authority which taxes or other payments are calculated by reference to the income, profits or capital of such Person or such Person and its Restricted Subsidiaries (to the extent such income or

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profits were included in computing Consolidated Net Income for such period), regardless of whether such taxes or payments are required to be remitted to any governmental authority.

“Consolidated Interest Expense” means, for any period, the total consolidated interest expense of the Company and its Restricted Subsidiaries, whether paid or accrued, plus, to the extent not included in such interest expense and without duplication:

(1) interest expense attributable to Capitalized Lease Obligations and the interest component of any deferred payment obligations;

(2) amortization of debt discount and debt issuance cost (provided that any amortization of bond premium will be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such amortization of bond premium has otherwise reduced Consolidated Interest Expense);

(3) non-cash interest expense;

(4) commissions, discounts and other fees and charges owed with respect to letters of credit and bankers’ acceptance financing;

(5) the interest expense on Indebtedness of another Person that is Guaranteed by the Company or one of its Restricted Subsidiaries or secured by a Lien on assets of the Company or one of its Restricted Subsidiaries, to the extent such Guarantee becomes payable or such Lien becomes subject to foreclosure;

(6) costs associated with Interest Rate Agreements (including amortization of fees); provided, however, that if Interest Rate Agreements result in net benefits rather than costs, such benefits shall be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such net benefits are otherwise reflected in Consolidated Net Income;

(7) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; and

(8) all dividends paid or payable in cash, Cash Equivalents or Indebtedness or accrued during such period on any series of Disqualified Stock of the Company or on Preferred Stock of its Restricted Subsidiaries payable to a party other than the Company or a Wholly-Owned Subsidiary.

minus, to the extent included above, write-off of deferred financing costs (and interest) attributable to Dollar-Denominated Production Payments.

For the purpose of calculating the Consolidated Coverage Ratio in connection with the Incurrence of any Indebtedness described in the final paragraph of the definition of “Indebtedness,” the calculation of Consolidated Interest Expense shall include all interest expense (including any amounts described in clauses (1) through (8) above) relating to any Indebtedness of the Company or any Restricted Subsidiary described in the final paragraph of the definition of “Indebtedness.”

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“Consolidated Net Income” means, for any period, the aggregate net income (loss) of the Company and its consolidated Subsidiaries determined in accordance with GAAP and before any reduction in respect of Preferred Stock dividends of such Person; provided, however, that there will not be included (to the extent otherwise included therein) in such Consolidated Net Income:

(1) any net income (loss) of any Person (other than the Company) if such Person is not a Restricted Subsidiary, except that:

(a) subject to the limitations contained in clauses (3) and (4) below, the Company’s equity in the net income of any such Person for such period will be included in such Consolidated Net Income up to the aggregate amount of cash actually distributed by such Person during such period to the Company or a Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to a Restricted Subsidiary, to the limitations contained in clause (2) below); and

(b) the Company’s equity in a net loss of any such Person for such period will be included in determining such Consolidated Net Income to the extent such loss has been funded with cash from the Company or a Restricted Subsidiary during such period;

(2) any net income (but not loss) of any Restricted Subsidiary if such Subsidiary is subject to restrictions, directly or indirectly, on the payment of dividends or the making of distributions by such Restricted Subsidiary, directly or indirectly, to the Company, except that:

(a) subject to the limitations contained in clauses (3), (4) and (5) below, the Company’s equity in the net income of any such Restricted Subsidiary for such period will be included in such Consolidated Net Income up to the aggregate amount of cash that could have been distributed by such Restricted Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution paid to another Restricted Subsidiary, to the limitation contained in this clause); and

(b) the Company’s equity in a net loss of any such Restricted Subsidiary for such period will be included in determining such Consolidated Net Income;

(3) any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of the Company or its consolidated Subsidiaries (including pursuant to any Sale/Leaseback Transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person;

(4) any extraordinary or nonrecurring gains or losses, together with any related provision for taxes on such gains or losses and all related fees and expenses;

(5) the cumulative effect of a change in accounting principles;

(6) any asset impairment writedowns on Oil and Gas Properties under GAAP or SEC guidelines;

(7) any unrealized non-cash gains or losses or charges in respect of Hedging Obligations (including those resulting from the application of Statement of Financial Accounting Standard No. 133);

(8) income or loss attributable to discontinued operations (including, without limitation, operations disposed of during such period whether or not such operations were classified as discontinued); and

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(9) any non-cash compensation charge arising from any grant of stock, stock options or other equity based awards; provided that the proceeds resulting from any such grant will be excluded from clause (c)(ii) of the first paragraph of the covenant described under “—Limitations on Restricted Payments.”

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Company who: (1) was a member of such Board of Directors on the date of the Indenture; or (2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board of Directors at the time of such nomination or election.

“Credit Facility” means, with respect to the Company or any Restricted Subsidiary, one or more debt facilities (including, without limitation, the Senior Secured Credit Agreement), indentures or commercial paper facilities providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time (and whether or not with the original administrative agent and lenders or another administrative agent or agents or other lenders and whether provided under the original Senior Secured Credit Agreement or any other credit or other agreement or indenture).

“Currency Agreement” means in respect of a Person any foreign exchange contract, currency swap agreement, futures contract, option contract or other similar agreement as to which such Person is a party or a beneficiary.

“Default” means any event which is, or after notice or passage of time or both would be, an Event of Default.

“Disqualified Stock” means, with respect to any Person, any Capital Stock of such Person which by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) at the option of the holder of the Capital Stock) or upon the happening of any event:

(1) matures or is mandatorily redeemable (other than redeemable only for Capital Stock of such Person which is not itself Disqualified Stock) pursuant to a sinking fund obligation or otherwise;

(2) is convertible or exchangeable for Indebtedness or Disqualified Stock (excluding Capital Stock which is convertible or exchangeable solely at the option of the Company or a Restricted Subsidiary); or

(3) is redeemable at the option of the holder of the Capital Stock in whole or in part,

in each case on or prior to the date that is 91 days after the earlier of the date (a) of the Stated Maturity of the Notes or (b) on which there are no Notes outstanding; provided that only the portion of Capital Stock which so matures or is mandatorily redeemable, is so convertible or exchangeable or is so redeemable at the option of the holder thereof prior to such date will be deemed to be Disqualified Stock; provided further, that any Capital Stock that would constitute Disqualified Stock solely because the holders thereof have the right to require the Company to repurchase such Capital Stock upon the occurrence of a change of control or asset sale (each defined in a substantially identical manner to the corresponding definitions in the Indenture)

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shall not constitute Disqualified Stock if the terms of such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) provide that (i) the Company may not repurchase or redeem any such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) pursuant to such provision prior to compliance by the Company with the provisions of the Indenture described under the captions “Change of control” and “Certain covenants—Limitation on sales of assets and Subsidiary stock” and (ii) such repurchase or redemption will be permitted solely to the extent also permitted in accordance with the provisions of the Indenture described under the caption “Certain covenants—Limitation on Restricted Payments.”

The amount of any Disqualified Stock that does not have a fixed redemption, repayment or repurchase price will be calculated in accordance with the terms of such Disqualified Stock as if such Disqualified Stock were redeemed, repaid or repurchased on any date on which the amount of such Disqualified Stock is to be determined pursuant to the Indenture; provided, however, that if such Disqualified Stock could not be required to be redeemed, repaid or repurchased at the time of such determination, the redemption, repayment or repurchase price will be the book value of such Disqualified Stock as reflected in the most recent financial statements of such Person.

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

“Equity Offering” means a public or private offering for cash by the Company of Capital Stock (other than Disqualified Stock), other than public offerings registered on Form S-8.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Foreign Subsidiary” means any Restricted Subsidiary that is not organized under the laws of the United States of America or any state thereof or the District of Columbia.

“GAAP” means generally accepted accounting principles in the United States of America as in effect from time to time. All ratios and computations based on GAAP contained in the Indenture will be computed in conformity with GAAP.

“Guarantee” means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of any other Person and any obligation, direct or indirect, contingent or otherwise, of such Person:

(1) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay, or to maintain financial statement conditions or otherwise); or

(2) entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part);

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provided, however, that the term “Guarantee” will not include endorsements for collection or deposit in the ordinary course of business or any obligation to the extent it is payable only in Capital Stock of the Guarantor that is not Disqualified Stock. The term “Guarantee” used as a verb has a corresponding meaning.

“Guarantor Subordinated Obligation” means, with respect to a Subsidiary Guarantor, any Indebtedness of such Subsidiary Guarantor (whether outstanding on the Issue Date or thereafter Incurred) which is expressly subordinate in right of payment to the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee pursuant to a written agreement.

“Hedging Obligations” of any Person means the obligations of such Person pursuant to any Interest Rate Agreement, Currency Agreement or Commodity Agreement.

“holder” means a Person in whose name a Note is registered on the registrar’s books.

“Hydrocarbons” means oil, natural gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“Immaterial Subsidiary” means, as of any date, any Restricted Subsidiary whose total assets, as of that date, are less than $1,000,000 and whose total revenues for the most recent 12-month period do not exceed $1,000,000; provided that a Restricted Subsidiary will not be considered to be an Immaterial Subsidiary if it, directly or indirectly, Guarantees or otherwise provides direct credit support for any Indebtedness of the Company.

“Incur” means issue, create, assume, Guarantee, incur or otherwise become directly or indirectly liable for, contingently or otherwise; provided, however, that any Indebtedness or Capital Stock of a Person existing at the time such Person becomes a Restricted Subsidiary (whether by merger, consolidation, acquisition or otherwise) will be deemed to be Incurred by such Restricted Subsidiary at the time it becomes a Restricted Subsidiary; and the terms “Incurred” and “Incurrence” have meanings correlative to the foregoing.

“Indebtedness” means, with respect to any Person on any date of determination (without duplication, whether or not contingent):

(1) the principal of and premium (if any) in respect of indebtedness of such Person for borrowed money;

(2) the principal of and premium (if any) in respect of obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;

(3) the principal component of all obligations of such Person in respect of letters of credit, bankers’ acceptances or other similar instruments (including reimbursement obligations with respect thereto except to the extent such reimbursement obligation relates to a trade payable, to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such obligation is satisfied within 30 days of payment on the letter of credit);

(4) the principal component of all obligations of such Person (other than obligations payable solely in Capital Stock that is not Disqualified Stock) to pay the deferred and unpaid purchase price of property (except as described in clause (8) of the penultimate paragraph of this definition of Indebtedness), which purchase price is due more than six months after the date of placing such property in service or taking delivery and title thereto to the extent such obligations would appear as a liabilities upon the consolidated balance sheet of such Person in accordance with GAAP;

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(5) Capitalized Lease Obligations of such Person to the extent such Capitalized Lease Obligations would appear as liabilities on the consolidated balance sheet of such Person in accordance with GAAP;

(6) the principal component or liquidation preference of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock or, with respect to any Subsidiary that is not a Subsidiary Guarantor, any Preferred Stock (but excluding, in each case, any accrued dividends);

(7) the principal component of all Indebtedness of other Persons secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person; provided, however, that the amount of such Indebtedness will be the lesser of (a) the fair market value of such asset at such date of determination (as determined in the good faith by the Board of Directors) and (b) the amount of such Indebtedness of such other Persons;

(8) the principal component of Indebtedness of other Persons to the extent Guaranteed by such Person; and

(9) to the extent not otherwise included in this definition, net obligations of such Person under Commodity Agreements, Currency Agreements and Interest Rate Agreements (the amount of any such obligations to be equal at any time to the termination value of such agreement or arrangement giving rise to such obligation that would be payable by such Person at such time);

provided, however, that any indebtedness which has been defeased in accordance with GAAP or defeased pursuant to the deposit of cash or Cash Equivalents (in an amount sufficient to satisfy all such indebtedness obligations at maturity or redemption, as applicable, and all payments of interest and premium, if any) in a trust or account created or pledged for the sole benefit of the holders of such indebtedness, and subject to no other Liens, shall not constitute “Indebtedness.”

The amount of Indebtedness of any Person at any date will be the outstanding balance at such date of all unconditional obligations as described above and the maximum liability, upon the occurrence of the contingency giving rise to the obligation, of any contingent obligations at such date.

Notwithstanding the preceding, “Indebtedness” shall not include:

(1) Production Payments and Reserve Sales;

(2) any obligation of a Person in respect of a farm-in agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an oil or gas property;

(3) any obligations under Currency Agreements, Commodity Agreements and Interest Rate Agreements; provided that such Agreements are entered into for bona fide hedging purposes of the Company or its Restricted Subsidiaries (as determined in good faith by the Board of Directors or senior management of the Company, whether or not accounted for as a hedge in accordance with GAAP) and, in the case of Currency Agreements or Commodity

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Agreements, such Currency Agreements or Commodity Agreements are related to business transactions of the Company or its Restricted Subsidiaries entered into in the ordinary course of business and, in the case of Interest Rate Agreements, such Interest Rate Agreements substantially correspond in terms of notional amount, duration and interest rates, as applicable, to Indebtedness of the Company or its Restricted Subsidiaries Incurred without violation of the Indenture;

(4) any obligation arising from agreements of the Company or a Restricted Subsidiary providing for indemnification, Guarantees, adjustment of purchase price, holdbacks, contingency payment obligations or similar obligations (other than Guarantees of Indebtedness), in each case, Incurred or assumed in connection with the acquisition or disposition of any business, assets or Capital Stock of a Restricted Subsidiary, provided that such Indebtedness is not reflected on the face of the balance sheet of the Company or any Restricted Subsidiary;

(5) any obligation arising from the honoring by a bank or other financial institution of a check, draft or similar instrument (except in the case of daylight overdrafts) drawn against insufficient funds in the ordinary course of business, provided that such Indebtedness is extinguished within five business days of Incurrence;

(6) in-kind obligations relating to net oil or natural gas balancing positions arising in the ordinary course of business;

(7) all contracts and other obligations, agreements instruments or arrangements described in clauses (20), (21), (22), (29)(a) or (30) of the definition of “Permitted Liens;”

(8) accrued expenses and trade payables and other accrued liabilities arising in the ordinary course of business that are not overdue by 90 days past the invoice or billing date or more or are being contested in good faith by appropriate proceedings promptly instituted and diligently conducted; and

(9) payables (except as described in the immediately preceding clause (8) of this paragraph) and Indebtedness of the Company or a Restricted Subsidiary owing to and held by any wholly-owned (other than directors’ qualifying shares or other de minimis shareholders) Unrestricted Subsidiary of the Company (a “Close Unrestricted Subsidiary”); provided, however, that (i) any subsequent issuance or transfer of Capital Stock or any other event which results in any such payables and Indebtedness being held by a Person other than a Close Unrestricted Subsidiary and (ii) any sale or other transfer of any such payables or Indebtedness to a Person other than the Company, a Restricted Subsidiary of the Company or a Close Unrestricted Subsidiary shall be deemed, in each case, to constitute and Incurrence of Indebtedness by the Company or such Restricted Subsidiary, as the case may be.

In addition, “Indebtedness” of any Person shall include Indebtedness described in the first paragraph of this definition of “Indebtedness” that would not appear as a liability on the balance sheet of such Person if:

(1) such Indebtedness is the obligation of a partnership or joint venture that is not a Restricted Subsidiary (a “Joint Venture”);

(2) such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture or otherwise liable for all or a portion of the Joint Venture’s liabilities (a “General Partner”); and

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(3) there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets of such Person or a Restricted Subsidiary of such Person; and then such Indebtedness shall be included in an amount not to exceed:

(a) the lesser of (i) the net assets of the General Partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or

(b) if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount.

“Interest Rate Agreement” means with respect to any Person any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement as to which such Person is party or a beneficiary.

“Investment” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of any direct or indirect advance, loan or other extensions of credit (including by way of Guarantee or similar arrangement, but excluding any debt or extension of credit represented by a bank deposit other than a time deposit and advances or extensions of credit to customers in the ordinary course of business) or capital contribution to (by means of any transfer of cash or other property to others or any payment for property or services for the account or use of others), or any purchase or acquisition of Capital Stock, Indebtedness or other similar instruments (excluding any interest in a crude oil or natural gas leasehold to the extent constituting a security under applicable law) issued by, such other Person and all other items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP; provided that none of the following will be deemed to be an Investment:

(1) Hedging Obligations entered into in the ordinary course of business and in compliance with the Indenture;

(2) endorsements of negotiable instruments and documents in the ordinary course of business; and

(3) an acquisition of assets, Capital Stock or other securities by the Company or a Subsidiary for consideration to the extent such consideration consists of Common Stock of the Company.

The amount of any Investment shall not be adjusted for increases or decreases in value, write-ups, write-downs or write-offs with respect to such Investment.

For purposes of the definition of “Unrestricted Subsidiary” and the covenant described under “Certain covenants—Limitation on Restricted Payments,”

(1) “Investment” will include the portion (proportionate to the Company’s equity interest in a Restricted Subsidiary to be designated as an Unrestricted Subsidiary) of the fair market value of the net assets of such Restricted Subsidiary at the time that such Restricted Subsidiary is designated an Unrestricted Subsidiary; provided, however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the Company will be deemed to continue to have a permanent “Investment” in an Unrestricted Subsidiary in an amount (if positive) equal to

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(a) the Company’s “Investment” in such Subsidiary at the time of such redesignation less (b) the portion (proportionate to the Company’s equity interest in such Subsidiary) of the fair market value of the net assets of such Subsidiary (as conclusively determined by the Board of Directors of the Company in good faith) at the time that such Subsidiary is so re-designated a Restricted Subsidiary; and

(2) any property transferred to or from an Unrestricted Subsidiary will be valued at its fair market value at the time of such transfer, in each case as determined in good faith by the Board of Directors of the Company.

“Investment Grade Rating” means a rating equal to or higher than:

(1) Baa3 (or the equivalent) with a stable or better outlook by Moody’s; and

(2) BBB– (or the equivalent) with a stable or better outlook by S&P,

or, if either such entity ceases to rate the Notes for reasons outside of the Company’s control, the equivalent investment grade credit rating from any other Rating Agency.

“Investment Grade Rating Event” means the first day on which the Notes have an Investment Grade Rating from each Rating Agency and no Default has occurred and is then continuing under the Indenture.

“Issue Date” means the first date on which the Notes are issued under the Indenture.

“Lien” means, with respect to any asset, any mortgage, lien (statutory or otherwise), pledge, hypothecation, charge, security interest, preference, priority or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction; provided that in no event shall an operating lease be deemed to constitute a Lien.

“Minority Interest” means the percentage interest represented by any shares of any class of Capital Stock of a Restricted Subsidiary that are not owned by the Company or a Restricted Subsidiary.

“Moody’s” means Moody’s Investors Service, Inc., or any successor to the rating agency business thereof.

“Net Available Cash” from an Asset Disposition means cash payments received (including any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise and net proceeds from the sale or other disposition of any securities received as consideration, but only as and when received, but excluding any other consideration received in the form of assumption by the acquiring Person of Indebtedness or other obligations relating to the properties or assets that are the subject of such Asset Disposition or received in any other non-cash form) therefrom, in each case net of:

(1) all legal, accounting, investment banking, title and recording tax expenses, commissions and other fees and expenses Incurred, and all federal, state, provincial, foreign and local taxes required to be paid or accrued as a liability under GAAP (after taking into account any available tax credits or deductions and any tax sharing agreements), as a consequence of such Asset Disposition;

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(2) all payments made on any Indebtedness which is secured by any assets subject to such Asset Disposition, in accordance with the terms of any Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Disposition, or by applicable law be repaid out of the proceeds from such Asset Disposition;

(3) all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures or to holders of royalty or similar interests as a result of such Asset Disposition; and

(4) the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, against any liabilities associated with the assets disposed of in such Asset Disposition and retained by the Company or any Restricted Subsidiary after such Asset Disposition.

“Net Cash Proceeds,” with respect to any issuance or sale of Capital Stock or any contribution to equity capital, means the cash proceeds of such issuance, sale or contribution net of attorneys’ fees, accountants’ fees, underwriters’ or placement agents’ fees, listing fees, discounts or commissions and brokerage, consultant and other fees and charges actually Incurred in connection with such issuance, sale or contribution and net of taxes paid or payable as a result of such issuance or sale (after taking into account any available tax credit or deductions and any tax sharing arrangements).

“Net Working Capital” means (a) all current assets of the Company and its Restricted Subsidiaries, except current assets from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, less (b) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness and any current liabilities from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness of a Person:

(1) as to which neither the Company nor any Restricted Subsidiary (a) provides any Guarantee or credit support of any kind (including any undertaking, guarantee, indemnity, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable (as a guarantor or otherwise);

(2) no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit (upon notice, lapse of time or both) any holder of any other Indebtedness of the Company or any Restricted Subsidiary to declare a default under such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its stated maturity; and

(3) the explicit terms of which provide there is no recourse against any of the assets of the Company or its Restricted Subsidiaries.

“Officer” means the Chairman of the Board, the Chief Executive Officer, the President, the Chief Financial Officer, any Vice President, the Treasurer or the Secretary of the Company. Officer of any Subsidiary Guarantor has a correlative meaning.

“Officers’ Certificate” means a certificate signed by an Officer of the Company.

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“Oil and Gas Business” means:

(1) the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, natural gas, liquid natural gas and other Hydrocarbon and mineral properties or products produced in association with any of the foregoing;

(2) the business of gathering, marketing, distributing, treating, processing, storing, refining, selling and transporting of any production from such interests or properties and products produced in association therewith and the marketing of oil, natural gas, other Hydrocarbons and minerals obtained from unrelated Persons;

(3) any other related energy business, including power generation and electrical transmission business, directly or indirectly, from oil, natural gas and other Hydrocarbons and minerals produced substantially from properties in which the Company or its Restricted Subsidiaries, directly or indirectly, participates;

(4) any business relating to oil field sales and service; and

(5) any business or activity relating to, arising from, or necessary, appropriate or incidental to the activities described in the foregoing clauses (1) through (4) of this definition.

“Oil and Gas Properties” means all properties, including equity or other ownership interests therein, owned by a Person which contain or are believed to contain oil and gas reserves.

“Opinion of Counsel” means a written opinion from legal counsel who is acceptable to the Trustee. The counsel may be an employee of or counsel to the Company or the Trustee.

“Pari Passu Indebtedness” means Indebtedness that ranks equally in right of payment to the Notes.

“Permitted Acquisition Indebtedness” means Indebtedness or Disqualified Stock of the Company or any of the Restricted Subsidiaries to the extent such Indebtedness or Disqualified Stock was Indebtedness or Disqualified Stock:

(1) of an acquired Person prior to the date on which such Person became a Restricted Subsidiary as a result of having been acquired and not incurred in contemplation of such acquisition; or

(2) of a Person that was merged, consolidated or amalgamated into the Company or a Restricted Subsidiary that was not incurred in contemplation of such merger, consolidation or amalgamation, provided that on the date such Subsidiary became a Restricted Subsidiary or the date such Person was merged, consolidated and amalgamated into the Company or a Restricted Subsidiary, as applicable, after giving pro forma effect thereto,

(a) the Restricted Subsidiary or the Company, as applicable, would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Consolidated Coverage Ratio test described under “—Certain covenants—Limitation on Indebtedness and Preferred Stock,” or

(b) the Consolidated Coverage Ratio for the Restricted Subsidiary or the Company, as applicable, would be greater than the Consolidated Coverage Ratio for such Restricted Subsidiary or the Company immediately prior to such transaction.

“Permitted Business Investment” means any Investment made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business including investments or expenditures for actively exploiting, exploring for, acquiring, developing, producing,

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processing, gathering, marketing or transporting oil, natural gas or other hydrocarbons and minerals through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties including:

(1) ownership interests in oil, natural gas, other hydrocarbons and minerals properties, liquid natural gas facilities, processing facilities, gathering systems, pipelines, storage facilities or related systems or ancillary real property interests;

(2) Investments in the form of or pursuant to operating agreements, working interests, royalty interests, mineral leases, processing agreements, farm-in agreements, farm-out agreements, contracts for the sale, transportation or exchange of oil, natural gas, other hydrocarbons and minerals, production sharing agreements, participation agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements, stockholder agreements and other similar agreements (including for limited liability companies) with third parties (including Unrestricted Subsidiaries); and

(3) direct or indirect ownership interests in drilling rigs and related equipment, including, without limitation, transportation equipment.

“Permitted Investment” means an Investment by the Company or any Restricted Subsidiary in:

(1) the Company, a Restricted Subsidiary or a Person which will, upon the making of such Investment, become a Restricted Subsidiary; provided, however, that the primary business of such Restricted Subsidiary is the Oil and Gas Business;

(2) another Person whose primary business is the Oil and Gas Business if as a result of such Investment such other Person becomes a Restricted Subsidiary or is merged or consolidated with or into, or transfers or conveys all or substantially all its assets to, the Company or a Restricted Subsidiary and, in each case, any Investment held by such Person; provided that such Investment was not acquired by such Person in contemplation of such acquisition, merger, consolidation or transfer;

(3) cash and Cash Equivalents;

(4) receivables owing to the Company or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms; provided, however, that such trade terms may include such concessionary trade terms as the Company or any such Restricted Subsidiary deems reasonable under the circumstances;

(5) payroll, commission, travel, relocation and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses for accounting purposes and that are made in the ordinary course of business;

(6) loans or advances to employees made in the ordinary course of business consistent with past practices of the Company or such Restricted Subsidiary;

(7) Capital Stock, obligations or securities received in settlement of debts (x) created in the ordinary course of business and owing to the Company or any Restricted Subsidiary or in satisfaction of judgments or (y) pursuant to any plan of reorganization or similar arrangement in a bankruptcy or insolvency proceeding;

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(8) Investments made as a result of the receipt of non-cash consideration from an Asset Disposition that was made pursuant to and in compliance with the covenant described under “Certain covenants—Limitation on sales of assets and Subsidiary stock”;

(9) Investments in existence on the Issue Date;

(10) Commodity Agreements, Currency Agreements, Interest Rate Agreements and related Hedging Obligations, which transactions or obligations are Incurred in compliance with “Certain covenants—Limitation on Indebtedness and Preferred Stock”;

(11) Guarantees issued in accordance with the covenant described under “Certain covenants— Limitation on Indebtedness and Preferred Stock”;

(12) any Asset Swap or acquisition of Additional Assets or Capital Stock of PVG or PVR, in each case made in accordance with the covenant described under “Certain covenants—Limitation on sales of assets and Subsidiary stock”;

(13) Investments in Unrestricted Subsidiaries having an aggregate fair market value, taken together with all other Investments made pursuant to this clause (13) that are at the time outstanding, not to exceed the greater of $50.0 million and 5.0% of the Company’s Adjusted Consolidated Net Tangible Assets (with the fair market value of such Investment being measured at the time such Investment is made and without giving effect to subsequent changes in value);

(14) Permitted Business Investments;

(15) any Person where such Investment was acquired by the Company or any of its Restricted Subsidiaries (a) in exchange for any other Investment or accounts receivable held by the Company or any such Restricted Subsidiary in connection with or as a result of a bankruptcy, workout, reorganization or recapitalization of the issuer of such other Investment or accounts receivable or (b) as a result of a foreclosure by the Company or any of its Restricted Subsidiaries with respect to any secured Investment or other transfer of title with respect to any secured Investment in default;

(16) any Person to the extent such Investments consist of prepaid expenses, negotiable instruments held for collection and lease, utility and workers’ compensation, performance and other similar deposits made in the ordinary course of business by the Company or any Restricted Subsidiary;

(17) Guarantees of performance or other obligations (other than Indebtedness) arising in the ordinary course in the Oil and Gas Business, including obligations under oil and natural gas exploration, development, joint operating, and related agreements and licenses, concessions or operating leases related to the Oil and Gas Business;

(18) acquisitions of assets, Equity Interests or other securities by the Company for consideration consisting of Capital Stock (other than Disqualified Stock) of the Company;

(19) Investments in the Notes; and

(20) Investments by the Company or any of its Restricted Subsidiaries, together with all other Investments pursuant to this clause (20), in an aggregate amount outstanding at the time of such Investment not to exceed the greater of $10.0 million and 1.0% of the Company’s

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Adjusted Consolidated Net Tangible Assets (with the fair market value of such Investment being measured at the time such Investment is made and without giving effect to subsequent changes in value).

“Permitted Liens” means, with respect to any Person:

(1) Liens securing Indebtedness and other obligations under, and related Hedging Obligations and Liens on assets of Restricted Subsidiaries securing Guarantees of Indebtedness and other obligations of the Company under, any Credit Facility permitted to be Incurred under the Indenture under the provisions described in clause (1) of the second paragraph under “Certain covenants—Limitation on Indebtedness and Preferred Stock”;

(2) pledges or deposits by such Person under workmen’s compensation laws, unemployment insurance laws, social security or old age pension laws or similar legislation, or good faith deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits (which may be secured by a Lien) to secure public or statutory obligations of such Person including letters of credit and bank guarantees required or requested by the United States, any State thereof or any foreign government or any subdivision, department, agency, organization or instrumentality of any of the foregoing in connection with any contract or statute (including lessee or operator obligations under statutes, governmental regulations, contracts or instruments related to the ownership, exploration and production of oil, natural gas, other hydrocarbons and minerals on State, Federal or foreign lands or waters), or deposits of cash or United States government bonds to secure indemnity performance, surety or appeal bonds or other similar bonds to which such Person is a party, or deposits as security for contested taxes or import or customs duties or for the payment of rent, in each case Incurred in the ordinary course of business;

(3) statutory and contractual Liens of landlords and Liens imposed by law, including carriers’, warehousemen’s, mechanics’ materialmen’s and repairmen’s Liens, in each case for sums not yet due or being contested in good faith by appropriate proceedings if a reserve or other appropriate provisions, if any, as shall be required by GAAP shall have been made in respect thereof;

(4) Liens for taxes, assessments or other governmental charges or claims not yet subject to penalties for non-payment or which are being contested in good faith by appropriate proceedings; provided that appropriate reserves, if any, required pursuant to GAAP have been made in respect thereof;

(5) Liens in favor of issuers of surety or performance bonds or letters of credit or bankers’ acceptances issued pursuant to the request of and for the account of such Person in the ordinary course of its business; provided, however, that such letters of credit do not constitute Indebtedness;

(6) survey exceptions, encumbrances, ground leases, easements or reservations of, or rights of others for, licenses, rights of way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning, building codes or other restrictions (including, without limitation, minor defects or irregularities in title and similar encumbrances) as to the use of real properties or Liens incidental to the conduct of the business of such Person or to the ownership of its properties which do not in the aggregate materially adversely affect the

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value of the assets of such Person and its Restricted Subsidiaries, taken as a whole, or materially impair their use in the operation of the business of such Person;

(7) Liens securing Hedging Obligations so long as the related Indebtedness is, and is permitted to be under the Indenture, secured by a Lien on the same property securing such Hedging Obligation;

(8) leases, licenses, subleases and sublicenses of assets (including, without limitation, real property and intellectual property rights) which do not materially interfere with the ordinary conduct of the business of the Company or any of its Restricted Subsidiaries;

(9) prejudgment Liens and judgment Liens not giving rise to an Event of Default so long as such Lien is adequately bonded and any appropriate legal proceedings which may have been duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired;

(10) Liens for the purpose of securing the payment of all or a part of the purchase price of, or Capitalized Lease Obligations, purchase money obligations or other payments Incurred to finance the acquisition, lease, improvement or construction of or repairs or additions to, assets or property acquired or constructed in the ordinary course of business; provided that:

(a) the aggregate principal amount of Indebtedness secured by such Liens is otherwise permitted to be Incurred under the Indenture and does not exceed the cost of the assets or property so acquired or constructed; and

(b) such Liens are created within 180 days of the later of the acquisition, lease, completion of improvements, construction, repairs or additions or commencement of full operation of the assets or property subject to such Lien and do not encumber any other assets or property of the Company or any Restricted Subsidiary other than such assets or property and assets affixed or appurtenant thereto;

(11) Liens arising solely by virtue of any statutory or common law provisions relating to banker’s Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a depositary institution; provided that:

(a) such deposit account is not a dedicated cash collateral account and is not subject to restrictions against access by the Company in excess of those set forth by regulations promulgated by the Federal Reserve Board; and

(b) such deposit account is not intended by the Company or any Restricted Subsidiary to provide collateral to the depository institution;

(12) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;

(13) Liens existing on the Issue Date;

(14) Liens on property or shares of Capital Stock of a Person at the time such Person becomes a Subsidiary; provided, however, that such Liens are not created or Incurred in connection with, or in contemplation of, such other Person becoming a Subsidiary; provided further, however, that any such Lien may not extend to any other property owned by the Company or any Restricted Subsidiary (other than assets or property affixed or appurtenant thereto);

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(15) Liens on property at the time the Company or any of its Subsidiaries acquired the property, including any acquisition by means of a merger or consolidation with or into the Company or any of its Subsidiaries; provided, however, that such Liens are not created or Incurred in connection with, or in contemplation of, such acquisition; provided further, however, that such Liens may not extend to any other property owned by the Company or any Restricted Subsidiary (other than assets or property affixed or appurtenant thereto);

(16) Liens securing Indebtedness or other obligations of a Subsidiary owing to the Company or a Wholly-Owned Subsidiary;

(17) Liens securing the Notes, Subsidiary Guarantees and other obligations under the Indenture;

(18) Liens securing Refinancing Indebtedness Incurred to refinance Indebtedness that was previously so secured, provided that any such Lien is limited to all or part of the same property or assets (plus improvements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property or assets that is the security for a Permitted Lien hereunder;

(19) any interest or title of a lessor under any Capitalized Lease Obligation or operating lease;

(20) Liens in respect of Production Payments and Reserve Sales, which Liens shall be limited to the property that is the subject of such Production Payments and Reserve Sales;

(21) Liens arising under farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, joint venture agreements, partnership agreements, operating agreements, royalties, working interests, net profits interests, joint interest billing arrangements, participation agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements which are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the assets that are the subject of the relevant agreement, program, order or contract;

(22) Liens on pipelines or pipeline facilities that arise by operation of law;

(23) Liens securing Indebtedness in an aggregate principal amount outstanding at any one time, added together with all other Indebtedness secured by Liens Incurred pursuant to this clause (23), not to exceed the greater of $10.0 million and 1.0% of the Company’s Adjusted Consolidated Net Tangible Assets, as determined on the date of Incurrence of such Indebtedness after giving pro forma effect to such Incurrence and the application of the proceeds therefrom;

(24) Liens in favor of the Company or any Subsidiary Guarantor;

(25) deposits made in the ordinary course of business to secure liability to insurance carriers;

(26) Liens in favor of customs and revenue authorities arising as a matter of law to secure payment of customs duties in connection with the importation of goods in the ordinary course of business;

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(27) Liens deemed to exist in connection with Investments in repurchase agreements permitted under “Certain covenants—Limitation on Indebtedness and Preferred Stock”; provided that such Liens do not extend to any assets other than those that are the subject of such repurchase agreement;

(28) Liens encumbering reasonable customary initial deposits and margin deposits and similar Liens attaching to commodity trading accounts or other brokerage accounts incurred in the ordinary course of business and not for speculative purposes;

(29) any (a) interest or title of a lessor or sublessor under any lease, liens reserved in oil, gas or other Hydrocarbons, minerals, leases for bonus, royalty or rental payments and for compliance with the terms of such leases; (b) restriction or encumbrance that the interest or title of such lessor or sublessor may be subject to (including, without limitation, ground leases or other prior leases of the demised premises, mortgages, mechanics’ liens, tax liens, and easements); or (c) subordination of the interest of the lessee or sublessee under such lease to any restrictions or encumbrance referred to in the preceding clause (b);

(30) Liens (other than Liens securing Indebtedness) on, or related to, assets to secure all or part of the costs incurred in the ordinary course of the Oil and Gas Business for the exploration, drilling, development, production, processing, transportation, marketing, storage or operation thereof;

(31) Liens upon specific items of inventory or other goods and proceeds of any Person securing such Person’s obligations in respect of bankers’ acceptances issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

(32) Liens arising under the Indenture in favor of the Trustee for its own benefit and similar Liens in favor of other trustees, agents and representatives arising under instruments governing Indebtedness permitted to be incurred under the Indenture, provided, however, that such Liens are solely for the benefit of the trustees, agents or representatives in their capacities as such and not for the benefit of the holders of such Indebtedness;

(33) Liens arising from the deposit of funds or securities in trust for the purpose of decreasing or defeasing Indebtedness so long as such deposit of funds or securities and such decreasing or defeasing of Indebtedness are permitted under the covenant described under “—Certain covenants—Limitation on Restricted Payments”; and

(34) Liens in favor of collecting or payer banks having a right of setoff, revocation, or charge back with respect to money or instruments of the Company or any Subsidiary of the Company on deposit with or in possession of such bank.

In each case set forth above, notwithstanding any stated limitation on the assets that may be subject to such Lien, a Permitted Lien on a specified asset or group or type of assets may include Liens on all improvements, additions and accessions thereto and all products and proceeds thereof (including dividends, distributions and increases in respect thereof).

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company, government or any agency or political subdivision hereof or any other entity.

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“Preferred Stock,” as applied to the Capital Stock of any corporation, means Capital Stock of any class or classes (however designated) which is preferred as to the payment of dividends, or as to the distribution of assets upon any voluntary or involuntary liquidation or dissolution of such corporation, over shares of Capital Stock of any other class of such corporation.

“Production Payments and Reserve Sales” means the grant or transfer by the Company or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in Oil and Gas Properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical services to the Company or a Restricted Subsidiary.

“PVG” means Penn Virginia GP Holdings, L.P., a Delaware limited partnership.

“PVR” means Penn Virginia Resources Partners, L.P., a Delaware limited partnership.

“Rating Agency” means each of S&P and Moody’s, or if S&P or Moody’s or both shall not make a rating on the Notes publicly available, a nationally recognized statistical rating agency or agencies, as the case may be, selected by the Company (as certified by a resolution of the Board of Directors) which shall be substituted for S&P or Moody’s, or both, as the case may be.

“Refinancing Indebtedness” means Indebtedness that is Incurred to refund, refinance, replace, exchange, renew, repay, extend, prepay, redeem or retire (including pursuant to any defeasance or discharge mechanism) (collectively, “refinance,” “refinances” and “refinanced” shall have correlative meanings) any Indebtedness (including Indebtedness of the Company that refinances Indebtedness of any Restricted Subsidiary and Indebtedness of any Restricted Subsidiary that refinances Indebtedness of another Restricted Subsidiary, but excluding Indebtedness of a Subsidiary that is not a Restricted Subsidiary that refinances Indebtedness of the Company or a Restricted Subsidiary), including Indebtedness that refinances Refinancing Indebtedness, provided, however, that:

(1) (a) if the Stated Maturity of the Indebtedness being Refinanced is earlier than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being refinanced or (b) if the Stated Maturity of the Indebtedness being refinanced is later than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity at least 91 days later than the Stated Maturity of the Notes;

(2) the Refinancing Indebtedness has an Average Life at the time such Refinancing Indebtedness is Incurred that is equal to or greater than the Average Life of the Indebtedness being refinanced;

(3) such Refinancing Indebtedness is Incurred in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the

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aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of the Indebtedness being refinanced (plus, without duplication, any additional Indebtedness Incurred to pay interest, premiums or defeasance costs required by the instruments governing such existing Indebtedness and fees and expenses Incurred in connection therewith); and

(4) if the Indebtedness being Refinanced is subordinated in right of payment to the Notes or the Subsidiary Guarantee, such Refinancing Indebtedness is subordinated in right of payment to the Notes or the Subsidiary Guarantee on terms at least as favorable to the holders as those contained in the documentation governing the Indebtedness being Refinanced.

“Reporting Failure” means the failure of the Company to file with the SEC and make available or otherwise deliver to the Trustee and each holder of Notes, within the time periods specified in “Certain covenants—Provision of financial information” (after giving effect to any grace period specified under Rule 12b-25 under the Exchange Act), the periodic reports, information, documents or other reports which the Company may be required to file with the SEC pursuant to such provision.

“Restricted Investment” means any Investment other than a Permitted Investment.

“Restricted Subsidiary” means any Subsidiary of the Company other than an Unrestricted Subsidiary.

“S&P” means Standard & Poor’s Rating Service, a division of The McGraw-Hill Companies, Inc., or any successor to the rating agency business thereof.

“Sale/Leaseback Transaction” means an arrangement relating to property now owned or hereafter acquired whereby the Company or a Restricted Subsidiary transfers such property to a Person and the Company or a Restricted Subsidiary leases it from such Person.

“SEC” means the United States Securities and Exchange Commission.

“Senior Secured Credit Agreement” means the Amended and Restated Credit Agreement dated as of December 4, 2003 among the Company, as Borrower, JPMorgan Chase Bank, N.A. (successor by merger to Bank One, N.A. (Main Office Chicago)), as Administrative Agent, and the lenders parties thereto from time to time, including any guarantees, collateral documents, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications, extensions, renewals, restatements, refundings or refinancings thereof and any indentures or credit facilities or commercial paper facilities with banks or other institutional lenders or investors that replace, refund or refinance any part of the loans, notes, other credit facilities or commitments thereunder, including any such replacement, refunding or refinancing facility or indenture that increases the amount borrowable thereunder or alters the maturity thereof (provided that such increase in borrowings is permitted under “Certain covenants—Limitation on Indebtedness and Preferred Stock” above).

“Significant Subsidiary” means any Restricted Subsidiary that would be a “Significant Subsidiary” of the Company within the meaning of Rule 1-02 under Regulation S-X promulgated by the SEC, as in effect on the Issue Date.

“Stated Maturity” means, with respect to any security, the date specified in such security as the fixed date on which the payment of principal of such security is due and payable, including

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pursuant to any mandatory redemption provision, but shall not include any contingent obligations to repay, redeem or repurchase any such principal prior to the date originally scheduled for the payment thereof.

“Subordinated Obligation” means any Indebtedness of the Company (whether outstanding on the Issue Date or thereafter Incurred) which is expressly subordinate in right of payment to the Notes pursuant to a written agreement.

“Subsidiary” of any Person means (a) any corporation, association or other business entity (other than a partnership, joint venture, limited liability company or similar entity) of which more than 50% of the total ordinary voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof (or Persons performing similar functions) or (b) any partnership, joint venture, limited liability company or similar entity of which more than 50% of the capital accounts, distribution rights, total equity and voting interests or general or limited partnership interests, as applicable, is, in the case of clauses (a) and (b), at the time owned or controlled, directly or indirectly, by (1) such Person, (2) such Person and one or more Subsidiaries of such Person or (3) one or more Subsidiaries of such Person. Unless otherwise specified herein, each reference to a Subsidiary (other than in this definition) will refer to a Subsidiary of the Company.

“Subsidiary Guarantee” means, individually, any Guarantee of payment of the Notes by a Subsidiary Guarantor pursuant to the terms of the Indenture and any supplemental indenture thereto, and, collectively, all such Guarantees. Each such Subsidiary Guarantee will be in the form prescribed by the Indenture.

“Subsidiary Guarantors” means each of Penn Virginia Holding Corp., Penn Virginia Oil & 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. and any Restricted Subsidiary created or acquired by the Company after the Issue Date other than a Foreign Subsidiary.

“Unrestricted Subsidiary” means:

(1) any Subsidiary of the Company that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Company in the manner provided below; and

(2) any Subsidiary of an Unrestricted Subsidiary.

The Board of Directors of the Company may designate any Subsidiary of the Company (including any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) to be an Unrestricted Subsidiary only if:

(1) such Subsidiary or any of its Subsidiaries does not own any Capital Stock or Indebtedness of or have any Investment in, or own or hold any Lien on any property of, any other Subsidiary of the Company which is not a Subsidiary of the Subsidiary to be so designated or otherwise an Unrestricted Subsidiary;

(2) all the Indebtedness of such Subsidiary and its Subsidiaries shall, at the date of designation, and will at all times thereafter, consist of Non-Recourse Debt;

(3) on the date of such designation, such designation and the Investment of the Company or a Restricted Subsidiary in such Subsidiary complies with “Certain covenants—Limitation on Restricted Payments”;

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(4) such Subsidiary is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation:

(a) to subscribe for additional Capital Stock of such Person; or

(b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

(5) on the date such Subsidiary is designated an Unrestricted Subsidiary, such Subsidiary is not a party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary with terms substantially less favorable to the Company than those that might have been obtained from Persons who are not Affiliates of the Company.

In addition, without further designation, each of PVG, PVR and each of their respective Subsidiaries and certain other Subsidiaries of the Company (including Penn Virginia Resource Holdings Corp., Penn Virginia Resource LP Corp., Penn Virginia Resource GP Corp., Kanawa Rail Corp. and Penn Virginia Equities Corporation) will be an Unrestricted Subsidiary.

Any such designation by the Board of Directors of the Company shall be evidenced to the Trustee by filing with the Trustee a resolution of the Board of Directors of the Company giving effect to such designation and an Officers’ Certificate certifying that such designation complies with the foregoing conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the foregoing requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary shall be deemed to be Incurred as of such date.

The Board of Directors of the Company may designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that immediately after giving effect to such designation, no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof and the Company could Incur at least $1.00 of additional Indebtedness under the first paragraph of the covenant described under “Certain covenants—Limitation on Indebtedness and Preferred Stock” on a pro forma basis taking into account such designation.

“U.S. Government Obligations” means securities that are (a) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged or (b) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the timely payment of which is unconditionally guaranteed as a full faith and credit obligation of the United States of America, which, in either case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depositary receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act), as custodian with respect to any such U.S. Government Obligations or a specific payment of principal of or interest on any such U.S. Government Obligations held by such custodian for the account of the holder of such depositary receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligations or the specific payment of principal of or interest on the U.S. Government Obligations evidenced by such depositary receipt.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

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“Voting Stock” of an entity means all classes of Capital Stock of such entity then outstanding and normally entitled to vote in the election of members of such entity’s Board of Directors.

“Wholly-Owned Subsidiary” means a Restricted Subsidiary, all of the Capital Stock of which (other than directors’ qualifying shares) is owned by the Company or another Wholly-Owned Subsidiary.

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Book-entry, delivery and form

We have obtained the information in this section concerning The Depository Trust Company (“DTC”), Clearstream Banking, S.A., Luxembourg (“Clearstream, Luxembourg”) and Euroclear Bank S.A./N.V., as operator of the Euroclear System (“Euroclear”), and their book-entry systems and procedures from sources that we believe to be reliable. We take no responsibility for an accurate portrayal of this information. In addition, the description of the clearing systems in this section reflects our understanding of the rules and procedures of DTC, Clearstream, Luxembourg and Euroclear as they are currently in effect. Those systems could change their rules and procedures at any time.

The notes will initially be represented by one or more fully registered global notes. Each such global note will be deposited with, or on behalf of, DTC or any successor thereto and registered in the name of Cede & Co. (DTC’s nominee). You may hold your interests in the global notes in the United States through DTC, or in Europe through Clearstream, Luxembourg or Euroclear, either as a participant in such systems or indirectly through organizations which are participants in such systems. Clearstream, Luxembourg and Euroclear will hold interests in the global notes on behalf of their respective participating organizations or customers through customers’ securities accounts in Clearstream, Luxembourg’s or Euroclear’s names on the books of their respective depositaries, which in turn will hold those positions in customers’ securities accounts in the depositaries’ names on the books of DTC. Citibank, N.A. will act as depositary for Clearstream, Luxembourg and JPMorgan Chase Bank, N.A. will act as depositary for Euroclear.

So long as DTC or its nominee is the registered owner of the global securities representing the notes, DTC or such nominee will be considered the sole owner and holder of the notes for all purposes of the notes and the indenture. Except as provided below, owners of beneficial interests in the notes will not be entitled to have the notes registered in their names, will not receive or be entitled to receive physical delivery of the notes in definitive form and will not be considered the owners or holders of the notes under the indenture, including for purposes of receiving any reports delivered by us or the trustee pursuant to the indenture. Accordingly, each person owning a beneficial interest in a note must rely on the procedures of DTC or its nominee and, if such person is not a participant, on the procedures of the participant through which such person owns its interest, in order to exercise any rights of a holder of notes.

Unless and until we issue the notes in fully certificated, registered form under the limited circumstances described below under the heading “—Certificated Notes”:

• you will not be entitled to receive a certificate representing your interest in the notes;

• all references in this prospectus supplement to actions by holders will refer to actions taken by DTC upon instructions from its direct participants; and

• all references in this prospectus supplement to payments and notices to holders will refer to payments and notices to DTC or Cede & Co., as the registered holder of the notes, for distribution to you in accordance with DTC procedures.

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The Depository Trust Company

DTC will act as securities depositary for the notes. The notes will be issued as fully registered notes registered in the name of Cede & Co. DTC is:

• a limited-purpose trust company organized under the New York Banking Law;

• a “banking organization” under the New York Banking Law;

• a member of the Federal Reserve System;

• a “clearing corporation” under the New York Uniform Commercial Code; and

• a “clearing agency” registered under the provisions of Section 17A of the Exchange Act.

DTC holds securities that its direct participants deposit with DTC. DTC facilitates the settlement among direct participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in direct participants’ accounts, thereby eliminating the need for physical movement of securities certificates.

Direct participants of DTC include securities brokers and dealers (including the underwriters), banks, trust companies, clearing corporations and certain other organizations. DTC is owned by a number of its direct participants. Indirect participants of DTC, such as securities brokers and dealers, banks and trust companies, can also access the DTC system if they maintain a custodial relationship with a direct participant.

Purchases of notes under DTC’s system must be made by or through direct participants, which will receive a credit for the notes on DTC’s records. The ownership interest of each beneficial owner is in turn to be recorded on the records of direct participants and indirect participants. Beneficial owners will not receive written confirmation from DTC of their purchase, but beneficial owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the direct participants or indirect participants through which such beneficial owners entered into the transaction. Transfers of ownership interests in the notes are to be accomplished by entries made on the books of participants acting on behalf of beneficial owners. Beneficial owners will not receive certificates representing their ownership interests in notes, except as provided below in “—Certificated Notes.”

To facilitate subsequent transfers, all notes deposited with DTC are registered in the name of DTC’s nominee, Cede & Co. The deposit of notes with DTC and their registration in the name of Cede & Co. effect no change in beneficial ownership. DTC has no knowledge of the actual beneficial owners of the notes. DTC’s records reflect only the identity of the direct participants to whose accounts such notes are credited, which may or may not be the beneficial owners. The participants will remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by DTC to direct participants, by direct participants to indirect participants and by direct participants and indirect participants to beneficial owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

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Book-entry format

Under the book-entry format, the paying agent will pay interest or principal payments to Cede & Co., as nominee of DTC. DTC will forward the payment to the direct participants, who will then forward the payment to the indirect participants (including Clearstream, Luxembourg or Euroclear) or to you as the beneficial owner. You may experience some delay in receiving your payments under this system. Neither we, the trustee under the indenture nor any paying agent has any direct responsibility or liability for the payment of principal or interest on the notes to owners of beneficial interests in the notes.

DTC is required to make book-entry transfers on behalf of its direct participants and is required to receive and transmit payments of principal, premium, if any, and interest on the notes. Any direct participant or indirect participant with which you have an account is similarly required to make book-entry transfers and to receive and transmit payments with respect to the notes on your behalf. We and the trustee under the indenture have no responsibility for any aspect of the actions of DTC, Clearstream, Luxembourg or Euroclear or any of their direct or indirect participants. In addition, we and the trustee under the indenture have no responsibility or liability for any aspect of the records kept by DTC, Clearstream, Luxembourg, Euroclear or any of their direct or indirect participants relating to or payments made on account of beneficial ownership interests in the notes or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests. We also do not supervise these systems in any way.

The trustee will not recognize you as a holder under the indenture, and you can only exercise the rights of a holder indirectly through DTC and its direct participants. DTC has advised us that it will only take action regarding a note if one or more of the direct participants to whom the note is credited directs DTC to take such action and only in respect of the portion of the aggregate principal amount of the notes as to which that participant or participants has or have given that direction. DTC can only act on behalf of its direct participants. Your ability to pledge notes to non-direct participants, and to take other actions, may be limited because you will not possess a physical certificate that represents your notes.

Neither DTC nor Cede & Co. (nor any other DTC nominee) will consent or vote with respect to the notes unless authorized by a direct participant in accordance with DTC’s procedures. Under its usual procedures, DTC will mail an omnibus proxy to us as soon as possible after the record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those direct participants to whose accounts the notes are credited on the record date (identified in a listing attached to the omnibus proxy).

Clearstream, Luxembourg or Euroclear will credit payments to the cash accounts of Clearstream, Luxembourg customers or Euroclear participants in accordance with the relevant system’s rules and procedures, to the extent received by its depositary. These payments will be subject to tax reporting in accordance with relevant United States tax laws and regulations. Clearstream, Luxembourg or the Euroclear operator, as the case may be, will take any other action permitted to be taken by a holder under the indenture on behalf of a Clearstream, Luxembourg customer or Euroclear participant only in accordance with its relevant rules and procedures and subject to its depositary’s ability to effect those actions on its behalf through DTC.

DTC, Clearstream, Luxembourg and Euroclear have agreed to the foregoing procedures in order to facilitate transfers of the notes among participants of DTC, Clearstream, Luxembourg and Euroclear. However, they are under no obligation to perform or continue to perform those procedures, and they may discontinue those procedures at any time.

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Transfers within and among book-entry systems

Transfers between DTC’s direct participants will occur in accordance with DTC rules. Transfers between Clearstream, Luxembourg customers and Euroclear participants will occur in accordance with its applicable rules and operating procedures.

DTC will effect cross-market transfers between persons holding directly or indirectly through DTC, on the one hand, and directly or indirectly through Clearstream, Luxembourg customers or Euroclear participants, on the other hand, in accordance with DTC rules on behalf of the relevant European international clearing system by its depositary. However, cross-market transactions will require delivery of instructions to the relevant European international clearing system by the counterparty in that system in accordance with its rules and procedures and within its established deadlines (European time). The relevant European international clearing system will, if the transaction meets its settlement requirements, instruct its depositary to effect final settlement on its behalf by delivering or receiving securities in DTC and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Clearstream, Luxembourg customers and Euroclear participants may not deliver instructions directly to the depositaries.

Because of time-zone differences, credits of securities received in Clearstream, Luxembourg or Euroclear resulting from a transaction with a DTC direct participant will be made during the subsequent securities settlement processing, dated the business day following the DTC settlement date. Those credits or any transactions in those securities settled during that processing will be reported to the relevant Clearstream, Luxembourg customer or Euroclear participant on that business day. Cash received in Clearstream, Luxembourg or Euroclear as a result of sales of securities by or through a Clearstream, Luxembourg customer or a Euroclear participant to a DTC direct participant will be received with value on the DTC settlement date but will be available in the relevant Clearstream, Luxembourg or Euroclear cash amount only as of the business day following settlement in DTC.

Although DTC, Clearstream, Luxembourg and Euroclear has agreed to the foregoing procedures in order to facilitate transfers of debt securities among their respective participants, they are under no obligation to perform or continue to perform such procedures and such procedures may be discontinued at any time.

Certificated Notes

Unless and until they are exchanged, in whole or in part, for notes in definitive form in accordance with the terms of the notes, the notes may not be transferred except (1) as a whole by DTC to a nominee of DTC or (2) by a nominee of DTC to DTC or another nominee of DTC or (3) by DTC or any such nominee to a successor of DTC or a nominee of such successor.

We will issue notes to you or your nominees, in fully certificated registered form, rather than to DTC or its nominees, only if:

• we advise the trustee in writing that DTC is no longer willing or able to discharge its responsibilities properly or that DTC is no longer a registered clearing agency under the Exchange Act, and the trustee or we are unable to locate a qualified successor within 90 days;

• an event of default has occurred and is continuing under the indenture; or

• we, at our option, elect to terminate the book-entry system through DTC.

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If any of the three above events occurs, DTC is required to notify all direct participants that notes in fully certificated registered form are available through DTC. DTC will then surrender the global note representing the notes along with instructions for re-registration. The trustee will re-issue the notes in fully certificated registered form and will recognize the registered holders of the certificated notes as holders under the indenture.

Unless and until we issue the notes in fully certificated, registered form, (1) you will not be entitled to receive a certificate representing your interest in the notes; (2) all references in this prospectus supplement to actions by holders will refer to actions taken by the depositary upon instructions from their direct participants; and (3) all references in this prospectus supplement to payments and notices to holders will refer to payments and notices to the depositary, as the registered holder of the notes, for distribution to you in accordance with its policies and procedures.

Same day settlement and payment

We will make payments in respect of the notes represented by the global notes (including principal, premium, if any, and interest) by wire transfer of immediately available funds to the accounts specified by DTC or its nominee. We will make all payments of principal, interest and premium, if any, with respect to certificated notes by wire transfer of immediately available funds to the accounts specified by the holders of the certificated notes or, if no such account is specified, by mailing a check to each such holder’s registered address. The Notes represented by the global notes are expected to be eligible to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in such notes will, therefore, be required by DTC to be settled in immediately available funds. We expect that secondary trading in any certificated notes will also be settled in immediately available funds.

Because of time zone differences, the securities account of a Clearstream, Luxembourg customer or Euroclear participant purchasing an interest in a global note from another customer or participant will be credited, and any such crediting will be reported to the relevant Clearstream, Luxembourg customer or Euroclear participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised us that cash received in Clearstream, Luxembourg or Euroclear as a result of sales of interests in a global note by or through a Clearstream, Luxembourg customer or Euroclear participant to another customer or participant will be received with value on the settlement date of DTC but will be available in the relevant Clearstream, Luxembourg or Euroclear cash account only as of the business day for Euroclear or Clearstream, Luxembourg following DTC’s settlement date.

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Certain United States federal income and estate tax consequences

The following discussion summarizes certain U.S. federal income tax considerations and, in the case of a non-U.S. holder (as defined below), U.S. federal estate tax considerations, that may be relevant to the acquisition, ownership and disposition of the notes. This discussion is based upon the provisions of the Internal Revenue Code of 1986, as amended, or the Code, applicable U.S. Treasury Regulations promulgated thereunder, judicial authority and administrative interpretations, as of the date of this document, all of which are subject to change, possibly with retroactive effect, or are subject to different interpretations. We cannot assure you that the Internal Revenue Service, or the IRS, will not challenge one or more of the tax consequences described in this discussion, and we have not obtained, nor do we intend to obtain, a ruling from the IRS or an opinion of counsel with respect to the U.S. federal tax consequences of acquiring, holding or disposing of the notes.

This discussion is limited to holders who purchase the notes in this offering for a price equal to the issue price of the notes (i.e., the first price at which a substantial amount of the notes is sold other than to bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers) and who hold the notes as capital assets (generally, property held for investment). This discussion does not address the tax considerations arising under the laws of any foreign, state, local or other jurisdiction. In addition, this discussion does not address all tax considerations that may be important to a particular holder in light of the holder’s circumstances, or to certain categories of investors that may be subject to special rules, such as:

• dealers in securities or currencies;

• traders in securities that have elected the mark-to-market method of accounting for their securities;

• U.S. holders (as defined below) whose functional currency is not the U.S. dollar;

• persons holding notes as part of a hedge, straddle, conversion or other “synthetic security” or integrated transaction;

• certain U.S. expatriates;

• financial institutions;

• insurance companies;

• regulated investment companies;

• real estate investment trusts;

• persons subject to the alternative minimum tax;

• entities that are tax-exempt for U.S. federal income tax purposes; and

• partnerships and other pass-through entities and investors therein.

If a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holds notes, the tax treatment of a partner generally will depend upon the status of the partner

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and the activities of the partnership. If you are a partner of a partnership acquiring the notes, you are urged to consult your own tax advisor about the U.S. federal income tax consequences of acquiring, holding and disposing of the notes.

INVESTORS CONSIDERING THE PURCHASE OF NOTES ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP OR DISPOSITION OF THE NOTES UNDER U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL OR FOREIGN JURISDICTION OR UNDER ANY APPLICABLE TAX TREATY.

In certain circumstances (see “Description of notes—Optional redemption—Change of control”), we may be obligated to pay amounts on the notes that are in excess of stated interest or principal on the notes. These potential payments may implicate the provisions of the U.S. Treasury Regulations relating to “contingent payment debt instruments.” We do not intend to treat the possibility of paying such additional amounts as causing the notes to be treated as contingent payment debt instruments. However, additional income will be recognized if any such additional payment is made. It is possible that the IRS may take a different position, in which case a holder might be required to accrue interest income at a higher rate than the stated interest rate and to treat as ordinary interest income any gain realized on the taxable disposition of the note. The remainder of this discussion assumes that the notes will not be treated as contingent payment debt instruments. Investors should consult their own tax advisors regarding the possible application of the contingent payment debt instrument rules to the notes.

Tax consequences to U.S. holders

You are a “U.S. holder” for purposes of this discussion if you are a beneficial owner of a note and you are for U.S. federal income tax purposes:

• an individual who is a U.S. citizen or U.S. resident alien;

• a corporation, or other entity taxable as a corporation for U.S. federal income tax purposes, that was created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

• an estate whose income is subject to U.S. federal income taxation regardless of its source; or

• a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust or that has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a United States person.

The following discussion assumes that you have not made the election to include all interest that accrues on a note in gross income on a constant yield basis (as described below under “Stated interest and OID on the notes”).

Stated interest and OID on the notes

Stated interest on the notes generally will be taxable to you as ordinary income at the time it is received or accrued in accordance with your regular method of accounting for U.S. federal income tax purposes.

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The notes are being issued with original issue discount for U.S. federal income tax purposes. The amount of OID is equal to the excess of a note’s “stated redemption price at maturity” over its issue price (as defined above). The stated redemption price at maturity of a note is the sum of all payments required to be made on the note other than payments of “qualified stated interest” (i.e., generally, stated interest that is unconditionally payable in money at least annually). All of the stated interest on a note should constitute qualified stated interest and therefore the stated redemption price at maturity of a note should be its stated principal amount. Regardless of your method of accounting, you will be required to accrue OID on a constant yield basis and include such accruals in gross income in advance of the receipt of cash attributable to that income. The amount of OID allocable to an accrual period is equal to the difference between (1) the product of the “adjusted issue price” of the note at the beginning of the accrual period and its yield to maturity (determined on the basis of a compounding assumption that reflects the length of the accrual period) and (2) the amount of any qualified stated interest allocable to the accrual period. The “adjusted issue price” of a note at the beginning of any accrual period is the sum of the issue price of the note plus the amount of OID allocable to all prior accrual periods reduced by any payments you received on the note that were not qualified stated interest. The “yield to maturity” of a note is the interest rate that, when used to compute the present value of all payments to be made on the note, produces an amount equal to the issue price of the note. Under these rules, you will generally have to include in income increasingly greater amounts of OID in successive accrual periods. Your adjusted tax basis in the note generally will be your original cost increased by the amount of OID included in your gross income with respect to such note under the rules discussed above.

You may elect, subject to certain limitations, to include all interest that accrues on a note in gross income on a constant yield basis. For purposes of this election, interest includes stated interest and OID. When applying the constant yield method to a note for which this election has been made, the issue price of a note will equal your basis in the note immediately after its acquisition and the issue date of the note will be the date of its acquisition by you. This election generally will apply only to the note with respect to which it is made and may not be revoked without IRS consent.

Disposition of notes

You will generally recognize capital gain or loss on the sale, redemption, exchange, retirement or other taxable disposition of a note. This gain or loss will equal the difference between your adjusted tax basis in the note and the proceeds you receive (excluding any proceeds attributable to accrued but unpaid stated interest which will be recognized as ordinary interest income to the extent you have not previously included the accrued interest in income). The proceeds you receive will include the amount of any cash and the fair market value of any other property received for the note. Your adjusted tax basis in the note will generally equal the amount you paid for the note, increased by the amount of OID you have previously included in income. The gain or loss will be long-term capital gain or loss if you held the note for more than one year at the time of the sale, redemption, exchange, retirement or other disposition. Long-term capital gains of individuals, estates and trusts generally are subject to a reduced rate of U.S. federal income tax. The deductibility of capital losses may be subject to limitation.

Information reporting and backup withholding

Information reporting will apply to payments of principal and interest (including OID) on, and the proceeds of the sale or other disposition (including a retirement or redemption) of, notes

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held by you, and backup withholding may apply to such payments unless you are an exempt recipient (such as a corporation) or, in the case of backup withholding, you provide the appropriate intermediary with a taxpayer identification number, certified under penalties of perjury, as well as certain other information. Backup withholding is not an additional tax. Any amount withheld under the backup withholding rules is allowable as a credit against your U.S. federal income tax liability, if any, and a refund may be obtained if the amounts withheld exceed your actual U.S. federal income tax liability and you timely provide the required information or appropriate claim form to the IRS.

Tax consequences to non-U.S. holders

Except as otherwise modified for U.S. federal estate tax purposes, you are a “non-U.S. holder” for purposes of this discussion if you are a beneficial owner of notes who is an individual, corporation, estate or trust and is not a U.S. holder.

Interest on the notes

Payments to you of interest and OID on the notes generally will be exempt from withholding of U.S. federal income tax under the “portfolio interest” exemption if you properly certify as to your foreign status as described below, and:

• you do not own, actually or constructively, 10% or more of the total combined voting power of all classes of our stock entitled to vote;

• you are not a “controlled foreign corporation” that is related to us (actually or constructively) through sufficient stock ownership;

• you are not a bank whose receipt of interest on the notes is in connection with an extension of credit made pursuant to a loan agreement entered into in the ordinary course of your trade or business; and

• interest on the notes is not effectively connected with your conduct of a U.S. trade or business.

The portfolio interest exemption and several of the special rules for non-U.S. holders described below generally apply only if you appropriately certify as to your foreign status. You can generally meet this certification requirement by providing a properly executed IRS Form W-8BEN or appropriate substitute form to us or our paying agent. Under certain circumstances, you may be required to obtain a U.S. taxpayer identification number. If you hold the notes through a financial institution or other agent acting on your behalf, you may be required to provide appropriate certifications to the agent. Your agent will then generally be required to provide appropriate certifications to us or our paying agent, either directly or through other intermediaries. Special rules apply to foreign partnerships, estates and trusts, and in certain circumstances certifications as to foreign status of partners, trust owners or beneficiaries may have to be provided to us or our paying agent. In addition, special rules apply to qualified intermediaries that enter into withholding agreements with the IRS.

If you cannot satisfy the requirements described above, payments of interest made to you will be subject to U.S. federal withholding tax at a 30% rate, unless you provide us or our paying agent with a properly executed IRS Form W-8BEN (or successor form) claiming an exemption from (or a

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reduction of) withholding under the benefit of a tax treaty, or the payments of interest are effectively connected with your conduct of a trade or business in the United States and you meet the certification requirements described below. (See “—Tax consequences to non-U.S. holders—Income or gain effectively connected with a U.S. trade or business.”)

Disposition of notes

You generally will not be subject to U.S. federal income tax on any gain realized on the sale, redemption, exchange, retirement or other taxable disposition of a note unless:

• the gain is effectively connected with the conduct by you of a U.S. trade or business; or

• you are an individual who has been present in the United States for 183 days or more in the taxable year of disposition and certain other requirements are met.

If you are a non-U.S. holder described in the first bullet point above, you generally will be subject to U.S. federal income tax in the same manner as a U.S. holder (See “—Tax consequences to non-U.S. holders—Income or gain effectively connected with a U.S. trade or business”). If you are a non-U.S. holder described in the second bullet point above, you will be subject to a flat 30% U.S. federal income tax on the gain derived from the sale or other disposition, which may be offset by U.S. source capital losses.

Income or gain effectively connected with a U.S. trade or business

If any interest (including OID) on the notes or gain from the sale, exchange or other taxable disposition of the notes is effectively connected with a U.S. trade or business conducted by you (and, if required by an income tax treaty, is treated as attributable to a permanent establishment in the United States), then the interest income or gain will be subject to U.S. federal income tax at regular graduated income tax rates. If you are a corporation, that portion of your earnings and profits that is effectively connected with your U.S. trade or business may also be subject to a “branch profits tax” at a 30% rate, although an applicable income tax treaty may provide for a lower rate. Effectively connected income will not be subject to U.S. withholding tax if you satisfy certain certification requirements by providing to us or our paying agent a properly executed IRS Form W-8ECI or W-8BEN (claiming an exemption under an applicable income tax treaty).

Information reporting and backup withholding

Payments to you of interest and OID on a note, and amounts withheld from such payments, if any, generally will be required to be reported to the IRS and to you.

United States backup withholding tax generally will not apply to payments of interest or OID on a note if the statement described in “Tax consequences to non-U.S. holders—Interest on the notes” is duly provided or you otherwise establish an exemption, provided that we do not have actual knowledge or reason to know that you are a United States person.

Payment of the proceeds of a disposition of a note (including a retirement or redemption) effected by the U.S. office of a U.S. or foreign broker will be subject to information reporting requirements and backup withholding unless you properly certify under penalties of perjury as to your foreign status and certain other conditions are met or you otherwise establish an exemption. Information reporting requirements and backup withholding generally will not apply

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to any payment of the proceeds of the disposition of a note effected outside the United States by a foreign office of a broker. However, unless such a broker has documentary evidence in its records that you are a non-U.S. holder and certain other conditions are met, or you otherwise establish an exemption, information reporting will apply to a payment of the proceeds of the disposition of a note effected outside the United States by such a broker if it:

• is a United States person;

• derives 50% or more of its gross income for certain periods from the conduct of a trade or business in the United States;

• is a controlled foreign corporation for U.S. federal income tax purposes; or

• is a foreign partnership that, at any time during its taxable year, has more than 50% of its income or capital interests owned by United States persons or is engaged in the conduct of a U.S. trade or business.

Backup withholding is not an additional tax. Any amount withheld under the backup withholding rules is allowable as a credit against your U.S. federal income tax liability, if any, and a refund may be obtained if the amounts withheld exceed your actual U.S. federal income tax liability and you timely provide the required information or appropriate claim form to the IRS.

U.S. federal estate tax

If you are an individual and are not a resident of the United States (as specially defined for U.S. federal estate tax purposes) at the time of your death, the notes will not be included in your estate for U.S. federal estate tax purposes provided, at the time of your death, interest (including OID) on the notes qualifies for the portfolio interest exemption under the rules described above without regard to the certification requirement.

THE PRECEDING DISCUSSION OF CERTAIN U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS IS FOR GENERAL INFORMATION ONLY AND IS NOT TAX ADVICE. WE URGE EACH PROSPECTIVE INVESTOR TO CONSULT ITS OWN TAX ADVISOR REGARDING THE PARTICULAR FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES OF PURCHASING, HOLDING AND DISPOSING OF THE NOTES, INCLUDING THE CONSEQUENCES OF ANY PROPOSED CHANGE IN APPLICABLE LAWS.

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Underwriting

Subject to the terms and conditions in the underwriting agreement between us and the underwriters, we have agreed to sell to each underwriter, and each underwriter has severally agreed to purchase from us, the principal amount of notes that appears opposite its name in the table below:

Underwriter	Principal amount
J.P. Morgan Securities Inc.	$
Banc of America Securities LLC
Wachovia Capital Markets, LLC
Barclays Capital Inc.
BNP Paribas Securities Corp.
RBC Capital Markets Corporation
Capital One Southcoast, Inc.
PNC Capital Markets LLC
UBS Securities LLC
Total	$	250,000,000

The underwriters have agreed to purchase all of the notes if any of them are purchased. The underwriting agreement provides that the obligations of the underwriters to purchase the notes included in this offering are subject to, among other customary conditions, the delivery of certain legal opinions by their counsel. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may also be increased or the offering may be terminated.

The underwriters initially propose to offer the notes to the public at the public offering price that appears on the cover page of this prospectus supplement. The underwriters may offer the notes to selected dealers at the public offering price minus a concession of up to     % of the principal amount. In addition, the underwriters may allow, and those selected dealers may reallow, a concession of up to     % of the principal amount to certain other dealers. After the initial offering, the underwriters may change the public offering price and any other selling terms. The underwriters may offer and sell notes through certain of their affiliates.

In the underwriting agreement, we have agreed that:

• We will not offer or sell any of our debt securities (other than the notes) for a period of 45 days after the date of this prospectus supplement without the prior consent of J.P. Morgan Securities Inc.

• We will indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in respect of those liabilities.

The notes are new issues of securities with no established trading market. We do not intend to apply for the notes to be listed on any securities exchange or to arrange for the notes to be quoted on any quotation system. The underwriters have advised us that they intend to make a market in the notes. However, they are not obligated to do so and they may discontinue any market making at any time in their sole discretion. Therefore, we cannot assure you that a liquid trading market will develop for the notes, that you will be able to sell your notes at a particular time or that the prices that you receive when you sell will be favorable.

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In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”), each underwriter has not made and will not make an offer of notes to the public in that Relevant Member State prior to the publication of a prospectus in relation to the notes which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of notes to the public in that Relevant Member State at any time:

• to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

• to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000; and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts; or

• in any other circumstances which do not require the publication by us of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer of notes to the public” in relation to any notes in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the notes to be offered so as to enable an investor to decide to purchase or subscribe the notes, as the same may be varied in that Member State by any measure implementing the Prospectus Directive in that Member State and the expression “Prospectus Directive” means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive (“Qualified Investors”) that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This prospectus and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant person should not act or rely on this document or any of its contents.

In connection with this offering of the notes, the underwriters may engage in overallotments, stabilizing transactions and syndicate covering transactions in accordance with Regulation M under the Exchange Act. Overallotment involves sales in excess of the offering size, which creates a short position for the underwriter. Stabilizing transactions involve bids to purchase the notes in the open market for the purpose of pegging, fixing or maintaining the price of the notes, as applicable. Syndicate covering transactions involve purchases of the notes in the open market after the distribution has been completed in order to cover short positions. Stabilizing transactions and syndicate covering transactions may cause the price of the notes to be higher than it would otherwise be in the absence of those transactions. If any of the underwriters engages in stabilizing or syndicate covering transactions, it may discontinue them at any time.

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Affiliates of Barclays Capital Inc., one of the underwriters of this offering, own more than 5% of our common stock. In addition, certain of the underwriters and their affiliates have in the past and may in the future provide investment banking, commercial banking, derivative transactions and financial advisory services to us and our affiliates in the ordinary course of business. In particular, affiliates of J.P. Morgan Securities Inc., Banc of America Securities LLC, Wachovia Capital Markets, LLC, BNP Paribas Securities Corp., RBC Capital Markets Corporation, Capital One Southcoast, Inc. and PNC Capital Markets LLC are lenders to us under our Revolver. In addition, Wells Fargo Bank, National Association, an affiliate of Wachovia Capital Markets, LLC, is the trustee under the indenture governing the notes and the trustee under the indenture governing our Convertible Notes. We intend to use more than 10% of the net proceeds of this offering to repay indebtedness owed by us to certain affiliates of the underwriters who are lenders under our Revolver. See “Use of proceeds.” Accordingly, this offering is being made in compliance with the requirements of Rule 5110(h) of the Conduct Rules of the Financial Industry Regulatory Authority. This rule provides generally that if more than 10% of the net proceeds from the sale of debt securities, not including underwriting compensation, is paid to the underwriters of such debt securities or their affiliates, the yield on the debt securities may not be lower than that recommended by a “qualified independent underwriter” meeting certain standards. UBS Securities LLC is assuming the responsibilities of acting as the qualified independent underwriter in connection with this offering. The yield on the notes, when sold to the public at the public offering price set forth on the cover page of this prospectus supplement, is no lower than that recommended by UBS Securities LLC.

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Legal matters

Certain legal matters related to the notes being offered hereby are being passed upon for us by Vinson & Elkins L.L.P., New York, New York. The underwriters will be represented by Davis Polk & Wardwell, New York, New York and Cahill Gordon & Reindel LLP, New York, New York. Vinson & Elkins L.L.P. will rely, as to matters of Virginia law, on the opinion of Hunton & Williams LLP, Virginia counsel for the Company.

Engineers

The estimated reserve evaluations and related calculations of Wright & Company, Inc., independent petroleum engineering consultants, included in this prospectus supplement have been include in reliance on the authority of that firm as experts in petroleum engineering.

Experts

The consolidated financial statements of Penn Virginia Corporation as of and for each of the years in the three year period ended December 31, 2008 have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of that firm as experts in accounting and auditing. The audit report covering the December 31, 2008 consolidated financial statements refers to a change in accounting for income tax uncertainties.

Available information

We are subject to the informational requirements of the Exchange Act and file reports, proxy statements and other information with the SEC. You may read, free of charge, and copy, at the prescribed rates, any reports, proxy statements and other information at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. Copies of such material also can be obtained by mail from the Public Reference Section of the SEC, at 100 F Street, N.E., Washington, D.C. 20549, at the prescribed rates. The SEC also maintains a website that contains reports, proxy and information statements and other information. The website address is: http://www.sec.gov.

Our internet address is http://www.pennvirginia.com. We make available free of charge on or through our website our Corporate Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics, Audit Committee Charter, Nominating and Governance Committee Charter and Compensation and Benefits Committee Charter, and we will provide copies of such documents to any shareholder who so requests. We also make available free of charge on or through our website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

Our common stock is listed on the NYSE under the symbol “PVA,” and reports, proxy statements and other information also can be inspected at the offices of the NYSE located at 20 Broad Street, New York, New York 10005.

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Incorporation of certain documents by reference

We have filed a registration statement with the SEC to register the securities offered by this prospectus supplement. As permitted by SEC rules, this prospectus supplement and the accompanying prospectus do not contain all of the information we have included in the registration statement and the accompanying exhibits and schedules we file with the SEC. You may refer to the registration statement, exhibits and schedules for more information about us and the securities. The registration statement, exhibits and schedules are available at the SEC’s public reference room or through its Internet website.

The SEC allows us to “incorporate by reference” the information we have filed with it, which means that we can disclose important information to you by referring you to those documents. The information we incorporate by reference is an important part of this prospectus supplement or the accompanying prospectus, and later information that we file with the SEC will automatically update and supersede this information. We incorporate by reference the documents listed below and any future filings we make with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended (excluding any information furnished pursuant to Item 2.02 and Item 7.01 on any Current Report on Form 8-K), after the date of this prospectus supplement and prior to the termination of this offering. Any statement contained in a document incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for purposes of this prospectus supplement to the extent that a statement contained herein or in any other subsequently filed document which also is incorporated or deemed to be incorporated by reference herein modifies or supersedes such statement. Any such statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this prospectus supplement. The documents we incorporate by reference are:

• our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2009, filed on May 11, 2009, Registration File No. 001-13283);

• our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, Registration File No. 001-13283 (including information specifically incorporated by reference into the Annual Report on Form 10-K from Penn Virginia Corporation’s definitive proxy statement filed on April 6, 2009, Registration File No. 001-13283); and

• our Current Reports on Form 8-K filed on June 3, 2009, May 20, 2009, May 18, 2009, April 28, 2009, April 3, 2009, March 31, 2009, March 27, 2009, February 26, 2009 and February 23, 2009, Registration File No. 001-13283.

We will provide without charge to each person, including any beneficial owner, to whom a copy of this prospectus supplement is delivered, upon the written or oral request of such person, a copy of any or all of the information incorporated by reference in this prospectus supplement, other than exhibits to such information (unless such exhibits are specifically incorporated by reference into the information that this prospectus supplement incorporates). Requests for such copies should be directed to Nancy M. Snyder, Corporate Secretary, Penn Virginia Corporation, Three Radnor Corporate Center, Suite 300, 100 Matsonford Road, Radnor, Pennsylvania, 19087 (telephone: (610) 687-8900).

S-252

Glossary of selected terms

The following are abbreviations and definitions commonly used in the oil, natural gas and coal industries that are used in this prospectus supplement.

Bbl a standard barrel of 42 U.S. gallons liquid volume

Bcf one billion cubic feet

Bcfe one billion cubic feet equivalent with one barrel of oil or condensate converted to six thousand cubic feet of natural gas based on the estimated relative energy content

BTU British thermal unit

CBM coalbed methane

Developed acreage lease acreage that is allocated or assignable to producing wells or wells capable of production

Development well a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive

Dry hole a well found to be incapable of producing either oil or gas in sufficient quantities to justify completion of the well

Exploratory or exploration well a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir

Gross acre or well an acre or well in which a working interest is owned

Mbbl one thousand barrels

Mbf one thousand board feet

Mcf one thousand cubic feet

Mcfe one thousand cubic feet equivalent

MMbbl one million barrels

MMbf one million board feet

MMBtu one million British thermal units

MMcf one million cubic feet

MMcfd one million cubic feet per day

MMcfe one million cubic feet equivalent

Net acre or well gross acres or wells multiplied by the owned working interest in those gross acres or wells

A-1

NGL natural gas liquid

NYMEX New York Mercantile Exchange

Present value of proved reserves the present value (discounted at 10%) of estimated future cash flows from proved oil and natural gas reserves, as estimated by our independent engineers, reduced by additional estimated future operating expenses, development expenditures and abandonment costs (net of salvage value) associated therewith (before income taxes)

Probable coal reserves those reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation

Productive wells wells that are producing oil or gas or that are capable of production

Proved developed reserves reserves that can be expected to be recovered through existing wells with existing equipment and operating methods

Proved reserves those 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 undeveloped reserves reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion

Proven coal reserves those reserves for which: (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling; and (b) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined, that the size, shape, depth and mineral content of reserves are well-established

Standardized measure present value of proved reserves further reduced by the present value (discounted at 10%) of estimated future income taxes on cash flows using prices in effect at a fiscal year end and estimated future costs as of that fiscal year end. Prices are held constant throughout the life of the properties except where SEC guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations

A-2

Undeveloped acreage lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas, regardless of whether such acreage contains estimated net proved reserves

Working interest a cost-bearing interest under an oil and gas lease that gives the holder the right to develop and produce the minerals under the lease

A-3

Penn Virginia Corporation and Subsidiaries

Index to financial statements

	Page
Unaudited financial statements
Consolidated statements of income for the three months ended March 31, 2009 and 2008	F-2
Consolidated balance sheets as of March 31, 2009 and December 31, 2008	F-3
Consolidated statements of cash flows for the three months ended March 31, 2009 and 2008	F-4
Notes to consolidated financial statements	F-5
Audited financial statements
Report of independent registered public accounting firm	F-31
Consolidated statements of income for the years ended December 31, 2008, 2007 and 2006	F-32
Consolidated balance sheets as of December 31, 2008 and 2007	F-33
Consolidated statements of cash flows for the years ended December 31, 2008, 2007 and 2006	F-34
Consolidated statements of shareholders’ equity and comprehensive income for the years ended December  31, 2008, 2007 and 2006	F-35
Notes to consolidated financial statements	F-39
Supplemental quarterly financial information (unaudited)	F-90
Supplemental information on oil and gas producing activities (unaudited)	F-91

F-1

Penn Virginia Corporation and Subsidiaries

Consolidated statements of income—unaudited

	Three months ended March 31,
(in thousands, except per share data)	2009			2008
Revenues
Natural gas	$	52,821		$	80,513
Crude oil		6,328			9,215
Natural gas liquids (NGLs)		3,370			1,868
Natural gas midstream		95,206			125,048
Coal royalties		30,630			23,962
Other		10,805			8,529
Total revenues		199,160			249,135
Expenses
Cost of midstream gas purchased		79,398			99,697
Operating		22,702			21,002
Exploration (see Note 13)		21,312			4,680
Taxes other than income		6,432			7,395
General and administrative		18,486			17,659
Impairments		1,196			—
Depreciation, depletion and amortization		57,073			38,569
Total expenses		206,599			189,002
Operating income (loss)		(7,439	)		60,133
Other income (expense)
Interest expense		(12,502	)		(10,747	)
Other		1,573			2,331
Derivatives		10,255			(25,901	)
Income (loss) before income taxes and noncontrolling interests		(8,113	)		25,816
Income tax benefit (expense)		4,562			(2,594	)
Net income (loss)		(3,551	)		23,222
Less net income attributable to noncontrolling interests		(3,658	)		(20,028	)
Net income (loss) attributable to Penn Virginia Corporation	$	(7,209	)	$	3,194
Earnings per share—basic and diluted (see Note 10):
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, basic	$	(0.17	)	$	0.08
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, diluted	$	(0.17	)	$	0.07
Weighted average shares outstanding, basic		41,922			41,558
Weighted average shares outstanding, diluted		41,922			41,803

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

F-2

Penn Virginia Corporation and Subsidiaries

Consolidated balance sheets—unaudited

(in thousands, except share data)	March 31, 2009			December 31, 2008
Assets
Current assets
Cash and cash equivalents	$	29,721		$	18,338
Accounts receivable, net of allowance for doubtful accounts		110,443			149,241
Derivative assets		62,727			67,569
Inventory		17,993			18,468
Other current assets		10,980			9,902
Total current assets		231,864			263,518
Property and equipment
Oil and gas properties (successful efforts method)		2,176,467			2,107,128
Other property and equipment		1,092,922			1,076,471
		3,269,389			3,183,599
Accumulated depreciation, depletion and amortization		(726,585	)		(671,422	)
Net property and equipment		2,542,804			2,512,177
Equity investments		80,003			78,443
Intangibles, net		90,817			92,672
Derivative assets		1,276			4,070
Other assets		53,734			45,685
Total assets	$	3,000,498		$	2,996,565
Liabilities and Shareholders’ Equity
Current liabilities
Short-term borrowings	$	—		$	7,542
Accounts payable and accrued liabilities		157,307			206,902
Derivative liabilities		17,741			15,534
Deferred taxes		15,292			17,598
Income taxes payable		—			18
Total current liabilities		190,340			247,594
Other liabilities		45,011			45,887
Derivative liabilities		7,550			8,721
Deferred income taxes		255,964			258,037
Convertible Notes (see Note 7)		201,545			199,896
Revolving Credit Facility		390,000			332,000
Long-term debt of PVR		595,100			568,100
Shareholders’ equity:
Penn Virginia Corporation 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; 41,883,695 and 41,870,893 shares issued and outstanding at March 31, 2009 and December 31, 2008		230			230
Paid-in capital		599,984			599,855
Retained earnings		434,087			443,646
Deferred compensation obligation		2,012			2,237
Accumulated other comprehensive loss		(3,931	)		(4,182	)
Treasury stock—81,257 and 95,378 shares common stock, at cost, on March 31, 2009 and December 31, 2008		(2,459	)		(2,683	)
Total Penn Virginia Corporation shareholders’ equity		1,029,923			1,039,103
Noncontrolling interests of subsidiaries (see Note 4)		285,065			297,227
Total shareholders’ equity		1,314,988			1,336,330
Total liabilities and shareholders’ equity	$	3,000,498		$	2,996,565

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

F-3

Penn Virginia Corporation and Subsidiaries

Consolidated statements of cash flows—unaudited

	Three months ended March 31,
(in thousands)	2009			2008
Cash flows from operating activities
Net income (loss)	$	(3,551	)	$	23,222
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		57,073			38,569
Impairments		1,196			—
Derivative contracts:
Total derivative losses (gains)		(9,801	)		27,009
Cash received (paid) to settle derivatives		19,148			(8,953	)
Deferred income taxes		(4,634	)		2,142
Dry hole and unproved leasehold expense		10,504			3,553
Non-cash interest expense		2,711			1,952
Other		780			(2,918	)
Changes in operating assets and liabilities		29,593			(18,424	)
Net cash provided by operating activities		103,019			66,152
Cash flows from investing activities
Acquisitions		(3,073	)		(4,740	)
Additions to property and equipment		(136,213	)		(108,662	)
Other		254			405
Net cash used in investing activities		(139,032	)		(112,997	)
Cash flows from financing activities
Dividends paid		(2,349	)		(2,344	)
Distributions paid to noncontrolling interests holders		(18,455	)		(13,740	)
Repayments of bank borrowings		(7,542	)		—
Proceeds from Company borrowings		58,000			54,000
Proceeds from borrowings of PVR		27,000			25,000
Repayments of borrowings of PVR		—			(23,000	)
Other		(9,258	)		5,282
Net cash provided by financing activities		47,396			45,198
Net increase (decrease) in cash and cash equivalents		11,383			(1,647	)
Cash and cash equivalents—beginning of period		18,338			34,527
Cash and cash equivalents—end of period	$	29,721		$	32,880
Supplemental disclosures:
Cash paid during the periods for:
Interest (net of amounts capitalized)	$	10,286		$	7,237
Income taxes	$	2,269		$	1,245

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

F-4

Penn Virginia Corporation and Subsidiaries

Notes to consolidated financial statements—unaudited

March 31, 2009

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 interest 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 March 31, 2009, 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. PVG derives its cash flow solely from cash distributions received from PVR. 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

F-5

business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

3. Summary of significant accounting policies

Our accounting policies are consistent with those described in our Annual Report on Form 10-K for the year ended December 31, 2008. Please refer to such Form 10-K for a further discussion of those policies.

Basis of presentation

Our consolidated financial statements include the accounts of Penn Virginia and all of its subsidiaries, including PVG and PVR. Intercompany balances and transactions have been eliminated in consolidation. Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our consolidated financial statements have been included. Our consolidated financial statements should be read in conjunction with our consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2008. Operating results for the three months ended March 31, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009.

New accounting standards

In April 2009, the Financial Accounting Standards Board (“FASB”) issued FSP FAS 107-1 and APB 28-1, Interim Disclosures About Fair Value of Financial Instruments (“FSP FAS 107-1 and APB 28-1”). This FSP requires disclosures about the fair value of financial instruments whenever we issue financial statements. The disclosures outlined in FSP FAS 107-1 and APB 28-1 are required for interim and annual periods ending after June 15, 2009. Early adoption is permitted for periods ending after March 15, 2009, and we have elected to adopt this FSP for the three months ended March 31, 2009. This FSP does not require disclosures for earlier periods presented for comparative purposes at initial adoption. See Note 5, “Fair Value Measurements” for the disclosure required under FSP FAS 107-1 and APB 28-1.

In April 2009, the FASB issued FSP FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies (“FSP FAS 141(R)-1”). This FSP requires us to recognize assets acquired or liabilities assumed in a business combination that arise from a contingency if the acquisition-date fair value of that asset or liability can be determined during the measurement period. If the acquisition-date fair value of an asset acquired or a liability assumed in a business combination that arises from a contingency cannot be determined during the measurement period, an asset or liability shall be recognized at the acquisition at the amount that would be recognized in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 5, Accounting for Contingencies and FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss—an interpretation of FASB Statement No. 5. Certain disclosures are also required under this FSP. FSP FAS 141(R)-1 is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after December 15, 2008. We have had no material acquisitions since our adoption of this FSP.

F-6

For each acquisition that includes assets acquired or liabilities assumed arising from contingencies, we will determine the fair value of the assets or liabilities and will make the appropriate disclosures.

4. Noncontrolling interests

We adopted SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, effective January 1, 2009. SFAS No. 160 requires that noncontrolling interests in PVG and PVR be classified as a separate component of shareholders’ equity. Net income attributable to the noncontrolling interests in PVG and PVR is separately presented on the consolidated statements of income, applied retrospectively for all periods presented.

The following is a reconciliation of the carrying amount of total shareholders’ equity, shareholders’ equity attributable to us and shareholders’ equity attributable to the noncontrolling interests in PVG and PVR:

(in thousands)	Penn Virginia Corporation shareholders			Noncontrolling interests			Total shareholders’ equity			Comprehensive income (loss)
Balance at December 31, 2008	$	1,039,103		$	297,227		$	1,336,330
Dividends paid ($0.05625 per share)		(2,349	)		—			(2,349	)
Distributions to noncontrolling interest holders		—			(18,455	)		(18,455	)
Other changes to shareholders’ equity		127			2,412			2,539
Comprehensive Income:
Net income (loss)		(7,209	)		3,658			(3,551	)		(3,551	)
Hedging unrealized loss, net of tax of ($205)		(28	)		(353	)		(381	)		(381	)
Hedging reclassification adjustment, net of tax of $442		244			576			820			820
Other, net of tax of $19		35			—			35			35
Balance at March 31, 2009	$	1,029,923		$	285,065		$	1,314,988		$	(3,077	)
Balance at December 31, 2007	$	835,793		$	174,420		$	1,010,213
Dividends paid ($0.05625 per share)		(2,344	)		—			(2,344	)
Distributions to noncontrolling interest holders		—			(13,740	)		(13,740	)
Other changes to shareholders’ equity		3,510			1,703			5,213
Comprehensive Income:
Net income		3,194			20,028			23,222			23,222
Hedging unrealized loss, net of tax of ($2,343)		(1,060	)		(3,291	)		(4,351	)		(4,351	)
Hedging reclassification adjustment, net of tax of $303		24			538			562			562
Other, net of tax of $22		41			—			41			41
Balance at March 31, 2008	$	839,158		$	179,658		$	1,018,816		$	19,474

F-7

5. Fair value measurements

We adopted SFAS No. 157, Fair Value Measurements, effective January 1, 2008, for financial assets and liabilities measured on a recurring basis. FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”), delayed the application of SFAS No. 157 for nonfinancial assets and liabilities to fiscal years and interim periods beginning after November 15, 2008. Prior to the adoption of FSP FAS 157-2, we only applied fair value measurements to our financial assets and liabilities. Effective January 1, 2009, SFAS No. 157 now applies to both financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis.

Our financial instruments consist of cash and cash equivalents, receivables, accounts payable, derivative instruments and long-term debt. At March 31, 2009, the carrying values of all of these financial instruments, except the convertible senior subordinated notes (“Convertible Notes”) portion of our long-term debt, approximated fair value. The fair value of the Convertible Notes portion of our long-term debt at March 31, 2009 was $137.4 million, which was derived from quoted market prices.

SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 requires fair value measurements to be classified and disclosed in one of the following three categories:

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

• 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 certain assets and liabilities by the above SFAS No. 157 categories as of March 31, 2009 (in thousands):

				Fair value measurement at March 31, 2009, using
Description	Fair value measurements, March 31, 2009			Quoted prices in active markets for identical assets (level 1)			Significant other observable inputs (level 2)			Significant unobservable inputs (level 3)
Marketable securities—noncurrent asset	$	4,559		$	4,559		$	—		$	—
Deferred compensation—noncurrent liability		(4,769	)		(4,769	)		—			—
Oil and gas properties—current		4,394						—			4,394
Interest rate swap liability—current		(8,947	)		—			(8,947	)		—
Interest rate swap liability— noncurrent		(7,550	)		—			(7,550	)		—
Commodity derivative assets— current		62,727			—			62,727			—
Commodity derivative assets— noncurrent		1,276			—			1,276			—
Commodity derivative liability— current		8,794			—			8,794			—
Total	$	60,484		$	(210	)	$	56,300		$	4,394

F-8

See Note 6—“Derivative Instruments,” for the effects of derivative instruments on our consolidated financial statements.

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.

• Deferred compensation: The fair values for deferred compensation are based on quoted market prices of the underlying securities, which are Level 1 inputs.

• Oil and gas segment properties: In accordance with the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, oil and gas properties of $5.6 million were written down to their fair value of $4.4 million, resulting in impairment. See Note 9, “Impairments and Unproved Leasehold Expense” for a further description of the impairment charge. The fair value of the oil and gas properties is estimated to be the present value of future net cash flows from the underlying reserves, using a forward strip commodity price discounted at a rate commensurate with the risk and remaining life of the asset. This is a Level 3 input.

• Commodity derivative instruments: Both our oil and gas commodity derivatives and PVR’s natural gas midstream segment commodity derivatives utilize collar derivative contracts, commodity price swaps and three-way collar derivative contracts. PVR also utilizes a combination of collar derivative contracts and commodity price swaps to hedge against the variability in its 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 forward prices as of March 31, 2009. PVR determines the fair values of its commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities, and use discount rates adjusted for the credit risk of the counterparties if the derivative is in an asset position and our own credit risk for derivatives in a liability position. 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 6—“Derivative Instruments.”

• Interest rate swaps: We have entered into interest rate swaps (the “Interest Rate Swaps”) to establish fixed rates on a portion of the outstanding borrowings under our revolving credit facility (the “Revolver”). PVR has entered into interest rate swaps (the “PVR Interest Rate Swaps”) to establish fixed rates on a portion of the outstanding borrowings under PVR’s revolving credit facility (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, and use discount rates adjusted for the credit risk of the counterparties if the derivative is in an asset position and our own credit risk for derivatives in a liability position. Each of these is a Level 2 input. See Note 6—“Derivative Instruments.”

F-9

6. Derivative instruments

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

Oil and gas segment commodity derivatives

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

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

A three-way collar contract 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.

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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 Intermediate crude oil forward prices as of March 31, 2009. 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 March 31, 2009:

	Average volume per day		Weighted average price						Estimated fair value (in thousands)
			Additional put option		Floor		Ceiling
	(in MMBtus)				(per MMBtu)
Natural Gas Costless Collars
Second Quarter 2009	15,000				$	4.25	$	5.70	$	791
Third Quarter 2009	15,000				$	4.25	$	5.70		633
Fourth Quarter 2009	15,000				$	4.25	$	5.70		(89	)
First Quarter 2010	35,000				$	4.96	$	7.41		(101	)
Second Quarter 2010	30,000				$	5.33	$	8.02		1,077
Third Quarter 2010	30,000				$	5.33	$	8.02		653
Fourth Quarter 2010	30,000				$	5.42	$	8.67		276
First Quarter 2011	30,000				$	5.42	$	8.67		(730	)
	(in MMBtus	)				(per MMBtu)
Natural Gas Three-way Collars
Second Quarter 2009	40,000		$	6.38	$	8.75	$	10.79		8,577
Third Quarter 2009	40,000		$	6.38	$	8.75	$	10.79		8,234
Fourth Quarter 2009	30,000		$	6.83	$	9.50	$	13.60		6,358
First Quarter 2010	30,000		$	6.83	$	9.50	$	13.60		5,527
	(in MMBtus	)				(per MMBtu)
Natural Gas Swaps
Second Quarter 2009	40,000				$	4.91				4,095
Third Quarter 2009	40,000				$	4.91				2,735
Fourth Quarter 2009	40,000				$	4.91				(105	)
	(Bbl	)				(Bbl)
Crude Oil Three-way Collars
Second Quarter 2009	500		$	80.00	$	110.00	$	179.00		1,372
Third Quarter 2009	500		$	80.00	$	110.00	$	179.00		1,326
Fourth Quarter 2009	500		$	80.00	$	110.00	$	179.00		1,261
Settlements to be paid in subsequent period										421
Oil and gas segment commodity derivatives—net asset									$	42,311

At March 31, 2009, we reported a net derivative asset related to the oil and gas commodity derivatives of $42.3 million. See the Financial Statement Impact of Derivatives section below for the impact of the oil and gas commodity derivatives on our consolidated financial statements.

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 a combination of collar derivative contracts and swap contracts to hedge against the variability in its frac spread. PVR’s frac spread is the spread between the

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purchase price for the natural gas PVR purchases from producers and the sale price for natural gas liquids (“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.

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 March 31, 2009, 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 March 31, 2009 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:

		Weighted average price collars
	Average volume per day	Additional put option		Put		Call		Fair value (in thousands)
	(in barrels)			(per barrel)
Crude Oil Three-way Collar
Second Quarter 2009 through Fourth Quarter 2009	1,000	$	70.00	$	90.00	$	119.25	$	4,939
	(in MMBtu)			(per MMBtu)
Frac Spread Collar
Second Quarter 2009 through Fourth Quarter 2009	6,000			$	9.09	$	13.94		5,594
Settlements to be received in subsequent period									2,366
Natural gas midstream segment commodity derivatives—net asset								$	12,899

At March 31, 2009, PVR reported a net derivative asset related to the natural gas midstream segment of $12.9 million. See the Financial Statement Impact of Derivatives section below for the impact of the PVR natural gas midstream commodity derivatives on our consolidated financial statements.

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 Interest Rate Swaps total $50.0 million, or approximately 13% of our total long-term debt outstanding under the Revolver at March 31, 2009. 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. We reported a (i) net derivative liability of $3.4 million at March 31, 2009 and (ii) loss in AOCI of $2.2 million, net of the related income tax benefit of $1.2

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million, at March 31, 2009 related to the Interest Rate Swaps. In connection with periodic settlements, we recognized $0.3 million in net hedging losses, net of the related income tax benefit of $0.1 million, on the Interest Rate Swaps in interest expense in the three months ended March 31, 2009. See the Financial Statement Impact of Derivatives section below for the impact of the Interest Rate Swaps on our consolidated financial statements.

During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps are recognized in earnings currently. At March 31, 2009, a $2.2 million loss remained in AOCI related to these discontinued Interest Rate Swaps hedges. The $2.2 million loss will be recognized in earnings through the end of 2011 as the originally forecasted transactions occur.

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. The following table sets forth the PVR Interest Rate Swap positions at March 31, 2009:

Dates	Notional amounts		Weighted-average fixed rate
	(in millions)
Until March 2010	$	310.0	3.54%
March 2010 – December 2011	$	250.0	3.37%
December 2011 – December 2012	$	100.0	2.09%

The notional amount of $310.0 million represents approximately 52% of PVR’s total long-term debt outstanding at March 31, 2009. The weighted-average fixed rate is paid by PVR based on the notional amount, with 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 PVR Revolver. The PVR Interest Rate Swaps have been entered into with seven financial institution counterparties, with no counterparty having more than 24% of the open positions.

During the first quarter of 2009, PVR discontinued hedge accounting for all of the PVR Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the PVR Interest Rate Swaps are recognized in earnings currently. At March 31, 2009, a $3.9 million loss remained in AOCI related to these discontinued PVR Interest Rate Swap hedges. The $3.9 million loss will be recognized in earnings through the end of 2011 as the originally forecasted transactions occur.

PVR reported a (i) net derivative liability of $13.1 million at March 31, 2009 and (ii) loss in AOCI of $3.9 million at March 31, 2009 related to the PVR Interest Rate Swaps. In connection with periodic settlements, PVR recognized $0.8 million of net hedging losses in interest expense in the three months ended March 31, 2009. See the Financial Statement Impact of Derivatives section below for the impact of the PVR Interest Rate Swaps on our consolidated financial statements.

Financial statement impact of derivatives

In the three months ended March 31, 2009, we reclassified a total of $0.8 million, net of income tax expense of $0.5 million, out of AOCI and into earnings. We also recorded unrealized hedging losses of $0.4 million, net of income tax benefit of $0.2 million, in AOCI in the three months ended March 31, 2009 related to the Interest Rate Swaps and the PVR Interest Rate Swaps. See Note 4, “Noncontrolling Interests,” 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 three months ended March 31, 2009 and 2008 (in thousands):

	Location of gain (loss) on derivatives recognized in income	Three months ended March 31,
		2009			2008
Derivatives de-designated as hedging instruments under SFAS No. 133:
Interest rate contracts(1)	Interest expense	$	(1,263	)	$	243
Increase (decrease) in net income resulting from derivatives de-designated as hedging instruments under SFAS No. 133		$	(1,263	)	$	243
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivatives	$	(1,114	)	$	—
Commodity contracts(1)	Natural gas midstream revenues		—			(2,251	)
Commodity contracts(1)	Cost of midstream gas purchased		—			1,143
Commodity contracts	Derivatives		11,369			(25,901	)
Increase (decrease) in net income resulting from derivatives not designated as hedging instruments under SFAS No. 133		$	10,255		$	(27,009	)
Total increase (decrease) in net income resulting from derivatives		$	8,992		$	(26,766	)
Realized and unrealized derivative impact:
Cash received (paid) for commodity and interest rate contract settlements	Derivatives	$	19,148		$	(8,953	)
Cash paid for interest rate contract settlements	Interest expense		(808	)		243
Unrealized derivative gain	(2)		(9,348	)		(18,056	)
Total increase (decrease) in net income resulting from derivatives		$	8,992		$	(26,766	)

(1) This represents amounts reclassified out of AOCI and into earnings. At March 31, 2009, a $3.9 million loss remained in AOCI related to the PVR Interest Rate Swaps on which PVR discontinued hedge accounting.

(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 March 31, 2009 and December 31, 2008 (in thousands):

	Balance sheet location	Fair values at March 31, 2009				Fair values at December 31, 2008
		Derivative assets		Derivative liabilities		Derivative assets		Derivative liabilities
Derivatives de-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 de-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	$	—	$	8,947	$	—	$	4,663
Interest rate contracts	Derivative liabilities—noncurrent		—		7,550		—		5,073
Commodity contracts	Derivative assets/liabilities — current		62,727		8,794		67,569		7,694
Commodity contracts	Derivative assets/liabilities —noncurrent		1,276		—		4,070		—
Total derivatives not designated as hedging instruments under SFAS No. 133		$	64,003	$	25,291	$	71,639	$	17,430
Total estimated fair value of derivative instruments		$	64,003	$	25,291	$	71,639	$	24,255

See Note 5, “Fair Value Measurements” 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 three months ended March 31, 2009 and 2008 (in thousands):

	Three months ended March 31,
Source	2009			2008
Interest on borrowings	$	(11,680	)	$	(12,292	)
Capitalized interest(1)		441			1,302
Interest rate swaps		(1,263	)		243
Total interest expense	$	(12,502	)	$	(10,747	)

(1) Capitalized interest was primarily related to 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 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 our consolidated statements of cash flows.

At March 31, 2009, PVR reported a net commodity derivative asset related to the natural gas midstream segment of $12.9 million that is with two counterparties, which are financial institutions, and is substantially concentrated with one of those counterparties. We reported a net commodity derivative asset related to our oil and gas segment of $42.3 million, 80% of which was concentrated with three

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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. The maximum amount of loss due to credit risk if counterparties to our or PVR’s derivative asset positions fail to perform according to the terms of the contracts would be equal to the fair value of the contracts as of March 31, 2009 and March 31, 2008. No significant uncertainties related to the collectability of amounts owed to us or PVR exists with regard to these counterparties.

The above hedging activity represents cash flow hedges. As of March 31, 2009 neither PVR nor we actively traded derivative instruments or has any fair value hedges. In addition, as of March 31, 2009, neither PVR nor we owned derivative instruments containing credit risk contingencies.

7. Convertible notes and adoption of FSP APB 14-1

We adopted FASB Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (“FSP APB 14-1”) effective January 1, 2009. We are accounting for the adoption of this standard as a change in accounting principle in accordance with FSP APB 14-1 and SFAS 154, Accounting Changes and Error Corrections. FSP APB 14-1 has therefore been applied retrospectively to all periods presented.

Because our Convertible Notes can be settled wholly or partly in cash upon conversion into our common stock, FSP APB 14-1 requires us to separately account for the liability and equity components in a manner that reflects our nonconvertible debt borrowing rate when measuring interest cost of the Convertible Notes. The value assigned to the liability component was the estimated value of a similar debt issuance without the conversion feature as of the issuance date in November 2007. Transaction costs associated with issuing the instrument were allocated to the liability and equity components in proportion to the allocation of the original proceeds and were accounted for as debt issuance costs and equity issuance costs. In addition, recognizing our Convertible Notes as two separate components resulted in a tax basis difference associated with the liability component that represents a temporary difference for purposes of applying SFAS No. 109, Accounting for Income Taxes. Because the liability component was valued exclusive of the conversion feature, the Convertible Notes were recorded at a discount reflecting the below-market coupon interest rate. This discount is accreted to par value over the expected life of the debt through additional interest expense.

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The following table reflects the effects of adopting FSP APB 14-1 on our consolidated statements of income for the three months ended March 31, 2009 and 2008 (in thousands):

Effects of FSP APB 14-1 adoption on the consolidated statement of income
Three months ended March 31, 2009
Consolidated statement of income	As computed under prior accounting principle			As adjusted			Effects of change
Interest expense—(1)	$	(10,666	)	$	(12,502	)	$	(1,836	)
Income tax benefit—(2)		3,851			4,562			711
Net income (loss)		(2,426	)		(3,551	)		(1,125	)
Net loss attributable to Penn Virginia Corporation		(6,084	)		(7,209	)		(1,125	)
Earnings per share—basic and diluted:
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, basic	$	(0.15	)	$	(0.17	)	$	(0.02	)
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, diluted	$	(0.14	)	$	(0.17	)	$	(0.03	)

Three months ended March 31, 2008
Consolidated statement of income	As originally reported			As adjusted			Effects of change
Interest expense—(3)	$	(9,552	)	$	(10,747	)	$	(1,195	)
Income tax expense—(2)		(3,057	)		(2,594	)		463
Net income		23,954			23,222			(732	)
Net income (loss) attributable to Penn Virginia Corporation		3,926			3,194			(732	)
Earnings per share—basic and diluted:
Net income per share attributable to Penn Virginia Corporation common shareholders, basic	$	0.09		$	0.08		$	(0.02	)
Net income per share attributable to Penn Virginia Corporation common shareholders, diluted	$	0.09		$	0.07		$	(0.02	)

(1) The additional interest expense incurred in the three months ended March 31, 2009 as a result of adopting FSP APB 14-1 is due to the debt discount that was created, which increased the amount of interest expense recognized for the period. This increase is partially offset by the amortization of debt issuance costs, which resulted from the separation of the debt and equity components of the Convertible Notes.

(2) The adjustment to income tax benefit (expense) is based on our effective tax rates.

(3) The impact on interest expense as presented for the three months ended March 31, 2008 is due to the additional interest expense that would have been incurred from the debt discount had FSP APB 14-1 been in place when the Convertible Notes were issued. This increase is partially offset by changes in capitalized interest and the amortization of debt issuance costs, which resulted from the separation of the debt and equity components of the Convertible Notes.

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The following table reflects the effects of adopting FSP APB 14-1 on our consolidated balance sheets at March 31, 2009 and December 31, 2008 (in thousands):

Effects of FSP APB 14-1 adoption on the consolidated balance sheets
Three months ended March 31, 2009
Consolidated balance sheet	As computed under prior accounting principle		As adjusted		Effect of change
Oil and gas properties (successful efforts method)—(1)	$	2,175,214	$	2,176,467	$	1,253
Other assets—(2)		54,660		53,734		(926	)
Deferred income taxes—(3)		243,716		255,964		12,248
Convertible Notes—(4)		230,000		201,545		(28,455	)
Paid-in capital—(5)		578,768		599,984		21,216
Retained earnings—(6)		439,019		434,087		(4,932	)

December 31, 2008
Consolidated balance sheet	As originally reported		As adjusted		Effects of change
Oil and gas properties (successful efforts method)—(1)	$	2,106,126	$	2,107,128	$	1,002
Other assets—(2)		46,674		45,685		(989	)
Deferred income taxes—(3)		245,789		258,037		12,248
Convertible Notes—(4)		230,000		199,896		(30,104	)
Paid-in capital—(5)		578,639		599,855		21,216
Retained earnings—(6)		446,993		443,646		(3,347	)

(1) The impact on oil and gas properties is due to capitalized interest.

(2) The adjustment to other assets reflects a decrease in debt issuance costs as a portion of such costs with allocated to equity upon issuance of Convertible Notes.

(3) The impact on deferred income taxes is due to the change in the tax basis of the liability component.

(4) The impact on the Convertible Notes balance is due to the unamortized debt discount attributable to the equity component to the Convertible Note.

(5) The impact on the paid-in capital balance is due to the equity component and related issuance costs as well as the change in deferred income taxes.

(6) The impact on retained earnings is due to the additional interest expense, net of tax, that would have been incurred had FSP APB 14-1 been in place when the Convertible Notes were issued.

The following table reflects the effects of adopting FSP APB 14-1 on our consolidated statements of cash flows at March 31, 2009 and December 31, 2008 (in thousands):

Effects of FSP APB 14-1 adoption on the consolidated statements of cash flows
Three months ended March 31, 2009
Consolidated statement of cash flows	As computed under prior accounting principle			As adjusted			Effects of change
Cash flows from operating activities
Net income	$	(2,426	)	$	(3,551	)	$	(1,125	)
Deferred income taxes		(3,923	)		(4,634	)		(711	)
Non-cash interest expense		875			2,711			1,836
Total impact on the statement of cash flows	$	(5,474	)	$	(5,474	)	$	—

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Three months ended March 31, 2008
Consolidated statement of cash flows	As originally reported		As adjusted		Effects of change
Cash flows from operating activities
Net income	$	23,954	$	23,222	$	(732	)
Deferred income taxes		2,605		2,142		(463	)
Non-cash interest expense		757		1,952		1,195
Total impact on the statement of cash flows	$	27,316	$	27,316	$	—

The following table reflects the carrying amounts of the liability and equity components of the Convertible Notes:

	March 31, 2009			December 31, 2008
Principal	$	230,000		$	230,000
Unamortized discount		(28,455	)		(30,104	)
Net carrying amount of liability component	$	201,545		$	199,896
Carrying amount of equity component	$	36,850		$	36,850

The net carrying amount of the liability component is reported as long-term debt of the Company in the consolidated balance sheets. The carrying amount of the equity component is reported in paid-in capital in the consolidated balance sheets. The discount amortization is recorded in interest expense in the consolidated statements of income.

As of March 31, 2009, the remaining period over which the discount will be amortized is approximately four years. The effective interest rate on the liability component for the three months ended March 31, 2009 and 2008 was 8.50%. For the three months ended March 31, 2009, we recognized $2.6 million of interest expense related to the contractual coupon rate on the Convertible Notes and $1.6 million of interest expense related to the amortization of the discount. For the three months ended March 31, 2008, we recognized $2.5 million of interest expense related to the contractual coupon rate on the Convertible Notes and $1.5 million of interest expense related to the amortization of the discount.

The Convertible Notes are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.3160 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment, and, if not converted or repurchased earlier, will mature on November 15, 2012.

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

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

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

8. Long-term debt

In March 2009, our bank group completed a semi-annual re-determination of the borrowing base under the Revolver. As a result, the borrowing base has been revised to $450.0 million, which is approximately 6% less than its previous level of $479.0 million.

In March 2009, PVR increased the size of the PVR Revolver from $700.0 million to $800.0 million. The PVR Revolver is secured with substantially all of PVR’s assets. The December 2011 maturity date for the PVR Revolver did not change. Interest is payable at a base rate plus an applicable margin of up to 1.25% 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 1.75% to 2.75% if PVR selects the LIBOR-based borrowing option. As of March 31, 2009 the interest rate on the PVR Revolver was at the bank’s base rate of 3.75%. Effective April 1, 2009, the interest rate on the PVR Revolver was a LIBOR-based rate of 2.87%.

9. Impairments and unproved leasehold expense

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 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.

For the three months ended March 31, 2009, we recorded impairment charges related to our oil and gas segment properties of $1.2 million. These charges were primarily related to market declines in the spot and future oil and gas prices.

Costs related to unproved properties are capitalized and periodically evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management. We continue to experience an

F-20

increase in lease expirations and unproved leasehold expense caused by current economic conditions which have impacted our future drilling plans thereby increasing the amount of expected lease expirations. Effective January 1, 2009, we changed our accounting process to amortize additional insignificant unproved properties over the average estimated life of the leases versus amortizing some leases and assessing other leases on an occurrence basis. As a result of amortizing additional leases, we recorded additional unproved leasehold expense, which is included in exploration expense on the consolidated statements of income, of $6.3 million in the three months ended March 31, 2009. The impact of this change on net income for the three months ended March 31, 2009 was a decrease of $3.9 million, net of income taxes. The impact of this change decreased basic and diluted earnings per share for the three months ended March 31, 2009 by $0.09.

10. Earnings per share

The following is a reconciliation of the numerators and denominators used in the calculation of basic and diluted earnings per share for the three months ended March 31, 2009 and 2008:

	Three months ended March 31,
(in thousands, except per share data)	2009			2008
Net income (loss) attributable to Penn Virginia Corporation common shareholders	$	(7,209	)	$	3,194
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards (net of tax)		(13	)		(103	)
	$	(7,222	)	$	3,091
Weighted average shares, basic		41,922			41,558
Effect of dilutive securities:
Stock options(1)		—			245
Weighted average shares, diluted		41,922			41,803
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, basic	$	(0.17	)	$	0.08
Net income (loss) per share attributable to Penn Virginia Corporation common shareholders, diluted	$	(0.17	)	$	0.07

(1) For the three months ended March 31, 2009, 0.2 million, potentially dilutive securities, including stock options and phantom stock had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.

11. Share-based compensation

Stock compensation plans

We recognized compensation expense related to the granting of common stock and deferred common stock units and the vesting of stock options and restricted and phantom stock granted under our stock compensation plans. For the three months ended March 31, 2009 and 2008, we recognized a total of $2.6 million and $1.2 million of compensation expense related to our stock compensation plans. The total income tax benefit recognized in our consolidated statements of income for our stock compensation plans was $1.0 million and $0.4 million for the three months ended March 31, 2009 and 2008. Compensation expense is recorded on the general and administrative expense line on the consolidated statements of income.

F-21

Stock options.    In February 2009, we granted 1,147,472 stock options with a weighted average exercise price of $15.06 and a weighted average grant date fair value of $5.57 per option. The options granted vest over a three-year period, with one-third vesting in each year. We recognize compensation expense on a straight-line basis over the vesting period.

Phantom units.    In February 2009, we granted 104,449 phantom units of our stock to non-employee directors with a weighted average grant date fair value of $15.06 per share. The phantom units granted vest over a three-year period, with one-third vesting in each year. We recognize compensation expense on a straight-line basis over the vesting period.

Deferred common stock units.    In February 2009, we granted 7,966 deferred common stock units to non-employee directors with a weighted average grant date fair value of $19.76 per share. The deferred common stock units granted vest immediately. We recognized compensation expense in the period these units were granted.

PVR long-term incentive plan

PVR recognized a total of $1.4 million and $0.7 million 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 for the three months ended March 31, 2009 and 2008. During the three months ended March 31, 2009, PVR’s general partner granted 354,792 phantom units with a weighted average grant date fair value of $11.59 per unit to employees of Penn Virginia and its affiliates. During the same period, 98,322 restricted units with a weighted average grant date fair value of $27.44 per unit vested. The phantom units granted in 2009 vest over a three-year period, with one-third vesting in each year. PVR recognizes compensation expense on a straight-line basis over the vesting period. These expenses are recorded on the general and administrative expense line on our consolidated statements of income.

12. Commitments and contingencies

Drilling rig commitments and standby charges

In the first quarter of 2009, our oil and gas segment opted to defer drilling of many wells due to unfavorable economic conditions. As a result, we amended certain drilling rig contracts to delay commencement of drilling until January 2010. In the first quarter of 2009, we incurred a liability of approximately $9.9 million for lump sum delay fees, minimum daily standby fees and demobilization fees expected to be paid during the standby period. These fees and costs are recorded in accounts payable and accrued liabilities on the consolidated balance sheets and as exploration expense on the consolidated statements of income. We will continue to evaluate economic conditions through the remainder of 2009 to determine whether or not to defer additional drilling. This could result in additional exploration expenses of up to approximately $14.8 million for 2009.

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.

F-22

Environmental compliance

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

PVR’s operations and those of its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of PVR’s coal property leases impose liability 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 March 31, 2009 and December 31, 2008, PVR’s environmental liabilities were $1.1 million and $1.2 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.

F-23

13. 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

	March 31, 2009
(in thousands)	Penn Virginia Corporation		Guarantor Subsidiaries		Non-guarantor subsidiaries		Eliminations			Consolidated
Assets
Cash and cash equivalents	$	7,977	$	—	$	21,744	$	—		$	29,721
Accounts receivable		—		53,197		57,246		—			110,443
Inventory		—		15,982		2,011		—			17,993
Other current assets		44,002		5,164		24,658		(117	)		73,707
Total current assets		51,979		74,343		105,659		(117	)		231,864
Property and equipment, net		7,979		1,667,336		896,341		(28,852	)		2,542,804
Investments in affiliates (equity method)		1,597,215		257,026		—		(1,854,241	)		—
Other assets		25,858		47		240,987		(41,061	)		225,830
Total assets	$	1,683,031	$	1,998,752	$	1,242,987	$	(1,924,271	)	$	3,000,498
Liabilities and shareholders’ equity
Accounts payable and accrued liabilities	$	6,496	$	97,476	$	53,335	$	—		$	157,307
Other current liabilities		16,646		—		16,504		(117	)		33,033
Total current liabilities		23,142		97,476		69,839		(117	)		190,340
Deferred income taxes		—		297,025		—		(41,061	)		255,964
Long-term debt of the Company		591,545		—		—		—			591,545
Long-term debt of subsidiary		—		—		595,100		—			595,100
Other long-term liabilities		9,568		7,036		35,957		—			52,561
Penn Virginia Corporation’s equity		1,058,776		1,597,215		257,026		(1,883,093	)		1,029,923
Noncontrolling interests in subsidiaries		—		—		285,065		—			285,065
Total liabilities and shareholders’ equity	$	1,683,031	$	1,998,752	$	1,242,987	$	(1,924,271	)	$	3,000,498

F-24

	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		1,637,832		895,247		(29,157	)		2,512,177
Investments in affiliates (equity method)		1,574,758		268,314		—		(1,843,072	)		—
Other assets		32,857		49		237,065		(49,101	)		220,870
Total assets	$	1,653,325	$	2,005,993	$	1,258,625	$	(1,921,378	)	$	2,996,565
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		11,868		295,270		—		(49,101	)		258,037
Long-term debt of the Company		531,896		—		—		—			531,896
Long-term debt of subsidiary		—		—		568,100		—			568,100
Other long-term liabilities		10,433		6,775		37,400		—			54,608
Penn Virginia Corporation’s equity		1,068,260		1,574,758		268,314		(1,872,229	)		1,039,103
Noncontrolling interests in subsidiaries		—		—		297,227		—			297,227
Total liabilities and shareholders’ equity	$	1,653,325	$	2,005,993	$	1,258,625	$	(1,921,378	)	$	2,996,565

F-25

Income statements

	Three months ended March 31, 2009
(in thousands)	Penn Virginia Corporation			Guarantor subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	64,564		$	156,767		$	(22,171	)	$	199,160
Cost of midstream gas purchased		—			—			100,620			(21,222	)		79,398
Operating		—			14,763			8,890			(951	)		22,702
Exploration		—			21,312			—			—			21,312
Taxes other than income		383			4,826			1,223			—			6,432
General and administrative		5,222			5,124			8,140			—			18,486
Impairment of oil and gas properties		—			1,196			—			—			1,196
Depreciation, depletion and amortization		871			39,999			16,509			(306	)		57,073
Operating expenses		6,476			87,220			135,382			(22,479	)		206,599
Operating income		(6,476	)		(22,656	)		21,385			308			(7,439	)
Equity in earnings of subsidiaries		(10,275	)		3,658			—			6,617			—
Interest expense and other		(6,501	)		—			(4,427	)		(1	)		(10,929	)
Derivatives		17,415			—			(7,160	)		—			10,255
Income before minority interest and income taxes		(5,837	)		(18,998	)		9,798			6,924			(8,113	)
Minority interest		—			—			3,658			—			3,658
Income tax expense		1,679			(8,723	)		2,482			—			(4,562	)
Net income	$	(7,516	)	$	(10,275	)	$	3,658		$	6,924		$	(7,209	)

	Three months ended March 31, 2008
(in thousands)	Penn Virginia Corporation			Guarantor subsidiaries		Non-guarantor subsidiaries			Eliminations			Consolidated
Revenues	$	2		$	92,298	$	156,835		$	—		$	249,135
Cost of midstream gas purchased		—			—		99,697			—			99,697
Operating		—			14,209		6,793			—			21,002
Exploration		—			4,680		—			—			4,680
Taxes other than income		464			5,858		1,073			—			7,395
General and administrative		5,934			4,585		7,140			—			17,659
Depreciation, depletion and amortization		819			26,616		11,506			(372	)		38,569
Operating expenses		7,217			55,948		126,209			(372	)		189,002
Operating income		(7,215	)		36,350		30,626			372			60,133
Equity in earnings of subsidiaries		30,469			8,641		—			(39,110	)		—
Interest expense and other		(4,445	)		—		(3,971	)		—			(8,416	)
Derivatives		(33,677	)		—		7,776			—			(25,901	)
Income before minority interest and income taxes		(14,868	)		44,991		34,431			(38,738	)		25,816
Minority interest		—			—		20,028			—			20,028
Income tax expense		(17,690	)		14,522		5,762			—			2,594
Net income	$	2,822		$	30,469	$	8,641		$	(38,738	)	$	3,194

F-26

Statements of Cash Flows

	Three months ended March 31, 2009
(in thousands)	Penn Virginia Corporation			Guarantor subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	10,732		$	58,594		$	33,693		$	—		$	103,019
Cash flows provided by (used in) investing activities:
Investment in (distributions from) affiliates		(50,458	)		11,533						38,925			—
Proceeds from the sale of property and equipment and other					(11	)		265			—			254
Additions to property and equipment		(406	)		(120,574	)		(18,306	)		—			(139,286	)
Net cash provided by (used in) investing activities		(50,864	)		(109,052	)		(18,041	)		38,925			(139,032	)
Cash flows provided by (used in) financing activities:
Distributions paid to NCI holders								(18,455	)		—			(18,455	)
Proceeds from long-term debt borrowings		58,000									—			58,000
Repayment of long-term debt principal		(7,542	)								—			(7,542	)
Capital contributions from (distributions to) affiliates					50,458			(11,533	)		(38,925	)		—
Proceeds from PVR long-term debt								27,000			—			27,000
Other		(2,349	)					(9,258	)		—			(11,607	)
Net cash provided by (used in) financing activities		48,109			50,458			(12,246	)		(38,925	)		47,396
Net increase (decrease) in cash and cash equivalents		7,977			—			3,406			—			11,383
Cash and Cash equivalents-beginning of period		—			—			18,338			—			18,338
Cash and Cash equivalents-end of period	$	7,977		$	—		$	21,744		$	—		$	29,721

F-27

	Three months ended March 31, 2008
(in thousands)	Penn Virginia Corporation			Guarantor subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	7,489		$	30,693		$	27,970		$	—		$	66,152
Cash flows provided by (used in) investing activities:
(Investment in) distributions from affiliates		(54,000	)		10,432			—			43,568			—
Proceeds from the sale of property and equipment and other		—			64			341			—			405
Additions to property and equipment		(543	)		(95,189	)		(17,670	)		—			(113,402	)
Net cash provided by (used in) investing activities		(54,543	)		(84,693	)		(17,329	)		43,568			(112,997	)
Cash flows provided by (used in) financing activities:
Distributions paid to NCI holders		—			—			(13,740	)		—			(13,740	)
Proceeds from borrowings of the Company		54,000			—			—			—			54,000
Capital contributions from (distributions to) affiliates		—			54,000			(10,432	)		(43,568	)		—
Proceeds from PVR long-term debt		—			—			25,000			—			25,000
Repayment of PVR long-term debt		—			—			(23,000	)		—			(23,000	)
Other		2,938			—			—			—			2,938
Net cash provided by (used in) financing activities		56,938			54,000			(22,172	)		(43,568	)		45,198
Net increase (decrease) in cash and cash equivalents		9,884			—			(11,531	)		—			(1,647	)
Cash and cash equivalents-beginning of period		4,035			—			30,492			—			34,527
Cash and cash equivalents-end of period	$	13,919		$	—		$	18,961		$	—		$	32,880

14. Segment information

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

F-28

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.

Other items primarily represent corporate functions and elimination of intercompany sales.

The following table presents a summary of certain financial information relating to our segments as of and for the three months ended March 31, 2009 and 2008 (in thousands):

	Revenues						Intersegment revenues(1)
	Three months ended March 31,						Three months ended March 31,
	2009			2008			2009			2008
Oil and gas	$	64,565		$	92,772		$	(346	)	$	(473	)
Coal and natural resource		38,252			30,492			198			(198	)
Natural gas midstream		118,507			126,047			22,520			473
Other		(22,164	)		(176	)		(22,372	)		198
Consolidated totals	$	199,160		$	249,135		$	—		$	—

	Operating income						DD&A expense
	Three months ended March 31,						Three months ended March 31,
	2009			2008			2009		2008
Oil and gas	$	(22,655	)	$	36,352		$	39,999	$	26,616
Coal and natural resource		24,974			17,582			7,394		6,413
Natural gas midstream		(3,047	)		13,652			9,109		5,087
Other		(6,711	)		(7,453	)		571		453
Consolidated totals	$	(7,439	)	$	60,133		$	57,073	$	38,569
Interest expense		(12,502	)		(10,747	)
Other		1,573			2,331
Derivatives		10,255			(25,901	)
Income tax expense		4,562			(2,594	)
Net income attributable to noncontrolling interest		(3,658	)		(20,028	)
Net income attributable to Penn Virginia Corporation	$	(7,209	)	$	3,194

F-29

	Additions to property and equipment
	Three months ended March 31,				Total assets at
	2009		2008		March 31, 2009		December 31, 2008
Oil and gas	$	120,574	$	95,189	$	1,737,860	$	1,728,375
Coal and natural resource		1,300		48		609,372		600,418
Natural gas midstream		17,006		17,622		597,347		618,402
Other		406		543		55,919		49,370
Consolidated totals	$	139,286	$	113,402	$	3,000,498	$	2,996,565

(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.

15. Subsequent Events

On May 22, 2009, we completed the sale of 3.5 million shares of our common stock in a registered public offering. The net proceeds of the sale were $64.9 million and were used to repay a portion of the outstanding borrowings under our Revolver.

F-30

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 in Internal 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

F-31

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.

F-32

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.

F-33

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.

F-34

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

F-35

Penn Virginia Corporation and Subsidiaries

Consolidated statements of shareholders’ equity and comprehensive income—(Continued)

(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

F-36

Penn Virginia Corporation and Subsidiaries

Consolidated statements of shareholders’ equity and comprehensive income—(Continued)

(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

F-37

Penn Virginia Corporation and Subsidiaries

Consolidated statements of shareholders’ equity and comprehensive income—(Continued)

(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.

F-38

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

F-39

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

F-40

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

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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 Disposal of 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 the Adoption of SFAS No. 161 section below for the impact of the oil and gas commodity derivatives on our consolidated statements of income.

PVR natural gas midstream segment commodity derivatives

PVR utilizes 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 the Adoption of SFAS No. 161 section 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. 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.

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

F-79

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

F-83

	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

F-84

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

F-87

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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26. 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 Oil and 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 for Modernization 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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PROSPECTUS

$700,000,000

Penn Virginia Corporation

Debt Securities

Guarantees of Debt Securities

Common Stock

Preferred Stock

Depositary Shares

Warrants

From time to time we may offer and sell the following securities:

• Unsecured debt securities, which may be senior or subordinated, and which may be guaranteed by one or more of our subsidiaries;

• Shares of common stock;

• Shares of preferred stock;

• Depositary shares; and

• Warrants.

This prospectus provides you with a general description of these securities and the general manner in which we will offer the securities. Each time we sell securities, we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add, update or change information contained in this prospectus. You should read this prospectus and any supplement carefully before you invest.

Our common stock is traded on the New York Stock Exchange under the symbol “PVA.”

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

The date of this prospectus is June 18, 2007.

TABLE OF CONTENTS

ABOUT THIS PROSPECTUS	1
ABOUT PENN VIRGINIA CORPORATION	1
THE SUBSIDIARY GUARANTORS	1
WHERE YOU CAN FIND MORE INFORMATION	2
FORWARD-LOOKING STATEMENTS	3
USE OF PROCEEDS	5
RATIOS OF EARNINGS TO FIXED CHARGES	5
DESCRIPTION OF DEBT SECURITIES	5
General	5
Senior Debt Securities	7
Subordinated Debt Securities	7
The Subsidiary Guarantees	8
Form, Exchange and Transfer	8
Global Securities	9
Payment and Paying Agents	10
Consolidation, Merger and Sale of Assets	10
Reports	11
Events of Default	11
Amendments and Waivers	12
Defeasance and Covenant Defeasance	14
Defeasance and Discharge	14
Defeasance of Certain Covenants	14
Notices	15
Title	15
Governing Law	15
DESCRIPTION OF CAPITAL STOCK	15
Common Stock	15
Listing	15
Dividends	15
Fully Paid	15
Preferred Share Purchase Rights	16
Voting Rights	16
Other Rights	16
Preferred Stock	16
Anti-Takeover Provisions	17
Certain Provisions of Our Articles of Incorporation	17
Shareholder Action by Unanimous Consent	17
Blank Check Preferred Stock	17
Fair Price Provisions	17
Election and Removal of Directors	17
Virginia Anti-Takeover Statutes and Other Virginia Laws	18
Control Share Acquisition Statute	18
Affiliated Transactions	18
Director Standards of Conduct	18
Shareholder Rights Plan	18
Indemnification of Officers and Directors	20
Transfer Agent and Registrar	20
DESCRIPTION OF DEPOSITARY SHARES	21
DESCRIPTION OF WARRANTS	21

i

PLAN OF DISTRIBUTION	22
By Agents	22
By Underwriters	22
Direct Sales; Rights Offerings	22
Delayed Delivery Arrangements	22
General Information	23
LEGAL MATTERS	23
EXPERTS	23

You should rely only on the information contained in this prospectus, any prospectus supplement and the documents we have incorporated by reference. We have not authorized anyone else to give you different information. We are not offering these securities in any state where the offer is not permitted. We will disclose any material changes in our affairs in an amendment to this prospectus, a prospectus supplement or a future filing with the United States Securities and Exchange Commission (the “SEC”) incorporated by reference in this prospectus.

ii

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we have filed with the SEC using a “shelf” registration process. Under this shelf registration process, we may sell up to $700,000,000 in aggregate offering price of the securities described in this prospectus in one or more offerings. This prospectus generally describes Penn Virginia Corporation and the debt securities, guarantees of debt securities, common stock, preferred stock, depositary shares and warrants included in the registration statement. Each time we sell securities with this prospectus, we will provide a prospectus supplement that will contain specific information about the terms of that offering. Any such prospectus supplement may also add to, update or change information in this prospectus. The information in this prospectus is accurate as of June 18, 2007. You should carefully read both this prospectus and any prospectus supplement and the additional information described under the heading “Where You Can Find More Information.”

ABOUT PENN VIRGINIA CORPORATION

Penn Virginia Corporation is a Virginia corporation founded in 1882. We are engaged in the development, exploration and production of natural gas and crude oil in Appalachia, Mississippi, East Texas, the Mid-Continent and the Gulf Coast regions of the United States through our subsidiary, Penn Virginia Oil & Gas Corporation. In addition, we collect royalties on various oil and gas properties in which we own a mineral fee interest.

We also own partner interests in Penn Virginia Resource Partners, L.P., a publicly traded Delaware limited partnership (“PVR”), which is involved in the coal land management and natural gas midstream businesses, and Penn Virginia GP Holdings, L.P. (“PVG”), which owns PVR’s general partner. We own the sole general partner of and an approximate 82% limited partner interest in PVG, which in turn owns the sole 2% general partner interest and an approximate 42% limited partner interest in PVR. We directly own an additional 0.5% limited partner interest in PVR. As part of its ownership of PVR’s general partner, PVG owns the rights, referred to as “incentive distribution rights,” to receive an increasing percentage of PVR’s quarterly distributions of available cash from operating surplus after certain levels of cash distributions have been achieved. PVR conducts operations in two business segments: coal land management and natural gas midstream. PVR manages coal properties and leases its coal reserves to various mine operators in exchange for royalty payments. PVR does not operate any coal mines. Additionally, PVR provides fee-based coal preparation and loading facilities to some of its lessees and to other third party industrial end-users. PVR also owns and operates midstream assets in Oklahoma and the panhandle of Texas.

Our corporate headquarters and principal executive offices are located at Three Radnor Corporate Center, Suite 300, 100 Matsonford Road, Radnor, Pennsylvania 19087, and our telephone number is (610) 687-8900. Our website address is www.pennvirginia.com. The information on our website is not part of this prospectus.

As used in this prospectus, “we,” “us,” “our” and “Penn Virginia” mean Penn Virginia Corporation.

THE SUBSIDIARY GUARANTORS

One or more of Penn Virginia Holding Corp., a Delaware corporation, Penn Virginia Oil & Gas Corporation, a Virginia corporation, Penn Virginia Oil & Gas GP LLC, a Delaware limited liability company, Penn Virginia Oil & Gas LP LLC, a Delaware limited liability company, Penn Virginia MC Corporation, a Delaware corporation, Penn Virginia MC Energy L.L.C., a Delaware limited liability company, Penn Virginia MC Operating Company L.L.C., a Delaware limited liability company, and Penn Virginia Oil & Gas, L.P., a Texas limited partnership may fully, irrevocably and unconditionally guarantee any series of debt securities of Penn Virginia offered by this prospectus, as set forth in a related prospectus supplement. As used in this prospectus, the term “Subsidiary Guarantors” shall mean the subsidiaries of Penn Virginia, if any, that will serve as subsidiary guarantors of the debt of Penn Virginia described in this registration statement.

1

WHERE YOU CAN FIND MORE INFORMATION

We are subject to the informational requirements of the Exchange Act and file reports, proxy statements and other information with the Commission. You may read, free of charge, and copy, at the prescribed rates, any reports, proxy statements and other information at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the Commission at 1-800-SEC-0330. Copies of such material also can be obtained by mail from the Public Reference Section of the Commission, at 100 F Street, N.E., Washington, D.C. 20549, at the prescribed rates. The Commission also maintains a website that contains reports, proxy and information statements and other information. The website address is: http://www.sec.gov.

Our internet address is http://www.pennvirginia.com. We make available free of charge on or through our website our Corporate Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics, Audit Committee Charter, Nominating and Governance Committee Charter and Compensation and Benefits Committee Charter, and we will provide copies of such documents to any shareholder who so requests. We also make available free of charge on or through our website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information on our website is not part of this prospectus.

Our common stock is listed on the NYSE under the symbol “PVA,” and reports, proxy statements and other information also can be inspected at the offices of the NYSE located at 20 Broad Street, New York, New York 10005.

The SEC allows us to “incorporate by reference” the information we have filed with the SEC. This means that Penn Virginia can disclose important information to you without actually including the specific information in this prospectus by referring you to those documents. The information incorporated by reference is an important part of this prospectus. Information that Penn Virginia files later with the SEC will automatically update and may replace information in this prospectus and information previously filed with the SEC. The documents listed below and any future filings made with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 are incorporated by reference in this prospectus until the termination of each offering under this prospectus.

• Annual Report on Form 10-K for the fiscal year ended December 31, 2006, Registration File No. 001-13283 (including information specifically incorporated by reference into the Annual Report on Form 10-K from Penn Virginia Corporation’s definitive proxy statement filed on April 9, 2007, Registration File No. 001-13283);

• Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, Registration File No. 001-13283);

• Current Report on Form 8-K filed on January 11, 2007, Registration File No. 001-13283;

• Current Report on Form 8-K filed on February 26, 2007, Registration File No. 001-13283;

• Current Report on Form 8-K filed on March 2, 2007, Registration File No. 001-13283;

• Current Report on Form 8-K filed on April 16, 2007, Registration File No. 001-13283;

• Current Report on Form 8-K filed on April 30, 2007, Registration File No. 001-13283;

• Current Report on Form 8-K filed on May 8, 2007, Registration File No. 001-13283;

• Current Report on Form 8-K filed on June 12, 2007, Registration File No. 001-13283;

• Current Report on Form 8-K filed on June 18, 2007, Registration File No. 001-13283; and

• Form 8-A/A filed on March 28, 2002, Registration File No. 001-13283.

2

You may request a copy of any document incorporated by reference in this prospectus, at no cost, by writing or calling us at the following address:

Investor Relations Department

Penn Virginia Corporation

Three Radnor Corporate Center

100 Matsonford Road

Suite 300

Radnor, Pennsylvania 19087

(610) 687-8900

Should you want more information regarding PVR or PVG, please refer to the annual, quarterly and special reports and proxy statements, as applicable, that each of them files with the SEC.

FORWARD-LOOKING STATEMENTS

Some of the information included in this prospectus, any prospectus supplement and the documents we incorporate by reference herein and therein contain forward-looking statements. These statements use forward-looking words such as “may,” “will,” “anticipate,” “believe,” “expect,” “project” or other words of similar meaning. These statements discuss goals, intentions and expectations as to future trends, plans, events, results of operations or financial condition or state other “forward-looking” information. A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statements. We believe we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that assumed facts or bases almost always vary from actual results, and the differences between assumed facts or bases and actual results can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the cautionary statements in this prospectus, any prospectus supplement and the documents we have incorporated by reference. These statements reflect our current views with respect to future events and are subject to various risks, uncertainties and assumptions including, but not limited, to the following:

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

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

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

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

• the relationship between natural gas and NGL prices;

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

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

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

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

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

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

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

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

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

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

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

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

• the price for which PVR can acquire coal reserves;

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

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

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

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

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

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

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

• unanticipated geological problems;

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

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

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

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

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

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

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

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

• labor relations and costs;

• accidents;

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

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

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

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

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

• coal handling joint venture operations;

• changes in financial market conditions; and

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

USE OF PROCEEDS

Unless we inform you otherwise in a prospectus supplement, we intend to use the net proceeds from the sale of securities we are offering for general corporate purposes. This may include, among other things, additions to working capital, repayment or refinancing of existing indebtedness or other corporate obligations, financing of capital expenditures and acquisitions and investment in existing and future projects.

RATIOS OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratio of earnings to fixed charges for each of the three months ended March 31, 2007 and 2006 and for each year in the five years ended December 31, 2006. The calculations include us and our subsidiaries.

	Three Months Ended March 31,		Year Ended December 31,
	2007	2006	2006	2005	2004	2003	2002
Ratio of earnings to fixed charges	2.8x	8.4x	6.3x	7.3x	7.6x	7.7x	8.3x

For purposes of calculating the ratio of earnings to fixed charges:

• “fixed charges” represent interest expense (including amounts capitalized), amortization of debt issuance costs and the portion of rental expense representing the interest factor; and

• “earnings” represent the aggregate of income from continuing operations (before adjustment for income taxes, extraordinary items, income or loss from equity investees and minority interest) plus fixed charges, amortization of capitalized interest and distributed income of equity investees, and less capitalized interest.

No ratio of combined fixed charges and preferred stock dividends is shown because we have no outstanding preferred stock. Therefore, if shown, such ratios would be identical to the ratios of earnings to fixed charges shown above.

DESCRIPTION OF DEBT SECURITIES

General

The debt securities issued using this prospectus will be:

• our general unsecured obligations;

• general unsecured obligations of the Subsidiary Guarantors if they are guaranteed by the Subsidiary Guarantors; and

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• either senior debt securities or subordinated debt securities.

The senior debt securities and the subordinated debt securities will be issued under separate indentures among Penn Virginia, as issuer, the Subsidiary Guarantors (if any), and Wells Fargo Bank, National Association (the “Trustee”). The Trustee for each series of debt securities will be identified in the applicable prospectus supplement. Senior debt securities will be issued under an indenture we call the senior indenture, and subordinated debt securities will be issued under an indenture we call the subordinated indenture. We have not restated these agreements in their entirety. We have filed the forms of the indentures as exhibits to the registration statement of which this prospectus is a part. We urge you to read the indentures, because they, and not this description, control your rights as holders of the debt securities.

We will prepare a prospectus supplement and either an indenture supplement or a resolution of our board of directors and accompanying officers’ certificate relating to any series of debt securities that we offer, which will include specific terms relating to some or all of the following:

• the form and title of the debt securities;

• whether the debt securities are senior debt securities or subordinated debt securities and, if subordinated debt securities, the terms of subordination;

• the total principal amount of the debt securities;

• the date or dates on which the debt securities of that series may be issued;

• the percentage of the principal amount at which the debt securities will be issued and any payments which will be due if the maturity of the debt securities is accelerated;

• if convertible into common stock, the terms on which the debt securities are convertible;

• any right we may have to defer payments of interest by extending the dates payments are due and whether interest on those deferred amounts will be payable;

• the dates on which the principal and premium, if any, of the debt securities will be payable;

• the interest rate which the debt securities will bear and the interest payment dates for the debt securities;

• any optional redemption provisions;

• any sinking fund or other provisions that would obligate us to repurchase or otherwise redeem the debt securities;

• whether the debt securities are entitled to the benefits of any guarantees by the Subsidiary Guarantors;

• any changes to or additions to the events of default or covenants contained in the applicable indenture;

• any affirmative or negative covenants relating to such series; and

• any other terms of the debt securities of that series.

This description of debt securities will be deemed modified, amended or supplemented by any description of any series of debt securities set forth in a prospectus supplement related to that series.

The prospectus supplement will also describe any material United States federal income tax consequences or other special considerations regarding the applicable series of debt securities, including those relating to:

• debt securities with respect to which payments of principal, premium or interest are determined with reference to an index or formula, including changes in prices of particular securities, currencies or commodities;

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• debt securities with respect to which principal, premium or interest is payable in a foreign or composite currency;

• debt securities that are issued at a discount below their stated principal amount, bearing no interest or interest at a rate that at the time of issuance is below market rates; and

• variable rate debt securities that are exchangeable for fixed rate debt securities.

At our option, we may make interest payments by check mailed to the registered holders of debt securities or, if so stated in the applicable prospectus supplement, at the option of a holder by wire transfer to an account designated by the holder.

Unless otherwise provided in the applicable prospectus supplement, fully registered securities may be transferred or exchanged at the office of the Trustee at which its corporate trust business is principally administered in the United States, subject to the limitations provided in the indenture, without the payment of any service charge, other than any applicable tax or governmental charge.

Senior Debt Securities

The senior debt securities will be unsecured senior obligations and will rank equally with all other senior unsecured and unsubordinated debt. However, the senior debt securities will be effectively subordinated in right of payment to all our secured indebtedness to the extent of the value of the assets securing such indebtedness.

Except as provided in the senior indenture or specified in any authorizing resolution and/or supplemental indenture relating to a series of senior debt securities to be issued, the senior indenture will not limit:

• the amount of additional indebtedness that may rank equally with the senior debt securities; or

• the amount of indebtedness, secured or otherwise, that may be incurred or preferred stock that may be issued by any of our subsidiaries.

Subordinated Debt Securities

Payment of the principal, interest and any premium on the subordinated debt securities will, to the extent set forth in the subordinated indenture with respect to each series of subordinated debt securities, be subordinated in right of payment to the prior payment in full of all of our senior debt, including the senior debt securities. The prospectus supplement relating to any subordinated debt securities will summarize the subordination provisions of the subordinated indenture applicable to that series including:

• the applicability and effect of such provisions upon any payment or distribution of our assets to creditors upon any liquidation, dissolution, winding-up, reorganization, assignment for the benefit of creditors or marshaling of assets or any bankruptcy, insolvency or similar proceedings;

• the applicability and effect of such provisions in the event of specified defaults with respect to any or certain senior debt, including the circumstances under which and the periods in which we will be prohibited from making payments on the subordinated debt securities; and

• the definition of senior debt applicable to the subordinated debt securities of that series.

The prospectus supplement will also describe as of a recent date the approximate amount of senior debt to which the subordinated debt securities of that series will be subordinated.

The failure to make any payment on any of the subordinated debt securities by reason of the subordination provisions of the subordinated indenture will not be construed as preventing the occurrence of an event of default with respect to the subordinated debt securities arising from the failure to make payment.

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The subordination provisions described above will not be applicable to payments in respect of the subordinated debt securities from a defeasance trust established in connection with any defeasance or covenant defeasance of the subordinated debt securities as described below under “Defeasance and Covenant Defeasance.”

The Subsidiary Guarantees

The payment obligations of Penn Virginia under any series of debt securities may be jointly and severally, fully and unconditionally guaranteed by any of the Subsidiary Guarantors. If a series of debt securities are so guaranteed, the Subsidiary Guarantors will execute a notation of guarantee as further evidence of their guarantee. The applicable prospectus supplement will describe the terms of any guarantee by the Subsidiary Guarantors.

The obligations of each Subsidiary Guarantor under its guarantee of the debt securities will be limited to the maximum amount that will not result in the obligations of the Subsidiary Guarantor under the guarantee constituting a fraudulent conveyance or fraudulent transfer under Federal or state law, after giving effect to:

• all other contingent and fixed liabilities of the Subsidiary Guarantor; and

• any collections from or payments made by or on behalf of any Subsidiary Guarantors in respect of the obligations of the Subsidiary Guarantor under its guarantee.

The guarantee of any Subsidiary Guarantor may be released under certain circumstances. If no default has occurred and is continuing under the applicable indenture, and to the extent not otherwise prohibited by the applicable indenture, a Subsidiary Guarantor will be unconditionally released and discharged from the guarantee:

• automatically upon any sale, exchange or transfer, to any person that is not an affiliate of Penn Virginia, of all of Penn Virginia’s direct or indirect limited liability company or other equity interests in the Subsidiary Guarantor;

• automatically upon the merger of the Subsidiary Guarantor into Penn Virginia or any other Subsidiary Guarantor or the liquidation and dissolution of the Subsidiary Guarantor; or

• following delivery of a written notice by us to the Trustee, upon the release of all guarantees by the Subsidiary Guarantor of any debt of Penn Virginia for borrowed money (or a guarantee of such debt), except for any series of debt securities.

Form, Exchange and Transfer

The debt securities of each series will be issuable only in fully registered form, without coupons. Unless otherwise indicated in the applicable prospectus supplement, the debt securities will be issued in denominations of $2,000 each or multiples of $1,000 in excess thereof.

At the option of the holder, subject to the terms of the applicable indenture and the limitations applicable to global securities, debt securities of each series will be exchangeable for other debt securities of the same series of any authorized denomination and of a like tenor and aggregate principal amount.

Subject to the terms of the applicable indenture and the limitations applicable to global securities, debt securities may be presented for exchange as provided above or for registration of transfer (duly endorsed or with the form of transfer endorsed thereon duly executed) at the office of the security registrar or at the office of any

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transfer agent designated by us for that purpose. No service charge will be made for any registration of transfer or exchange of debt securities, but we may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith. A transfer or an exchange will be effected upon the security registrar or the transfer agent, as the case may be, being satisfied with the documents of title and identity of the person making the request. The security registrar and any other transfer agent initially designated by us for any debt securities will be named in the applicable prospectus supplement. We may at any time designate additional transfer agents or rescind the designation of any transfer agent or approve a change in the office through which any transfer agent acts, except that we will be required to maintain a transfer agent in each place of payment for the debt securities of each series.

If the debt securities of any series (or of any series and specified tenor) are to be redeemed in part, we will not be required to:

• issue, register the transfer of or exchange any debt security of that series (or of that series and specified tenor, as the case may be) during a period beginning at the opening of business 15 days before the day of mailing of a notice of redemption of any such debt security that may be selected for redemption and ending at the close of business on the day of such mailing; or

• register the transfer of or exchange any debt security so selected for redemption, in whole or in part, except the unredeemed portion of any such debt security being redeemed in part.

Global Securities

Some or all of the debt securities of any series may be represented, in whole or in part, by one or more global certificates that will have an aggregate principal amount equal to that of the debt securities represented thereby. Each global security will be registered in the name of a depositary or a nominee thereof identified in the applicable prospectus supplement, will be deposited with such depositary or nominee or a custodian therefor and will bear a legend regarding the restrictions on exchanges and registration of transfer thereof referred to below and any such other matters as may be provided for pursuant to the applicable indenture.

Notwithstanding any provision of the applicable indenture or any debt security described herein, no global security may be exchanged in whole or in part for debt securities registered, and no transfer of a global security in whole or in part may be registered, in the name of any person other than the depositary for such global security or any nominee of such depositary unless:

• the depositary has notified us that it is unwilling or unable to continue as depositary for such global security or has ceased to be qualified to act as such as required by the applicable indenture;

• there shall have occurred and be continuing an event of default with respect to the debt securities represented by such global security; or

• there shall exist such circumstances, if any, in addition to or in lieu of those described above as may be described in the applicable prospectus supplement.

All debt securities issued in exchange for a global security or any portion thereof will be registered in such names as the depositary may direct.

As long as the depositary, or its nominee, is the registered holder of a global security, the depositary or such nominee, as the case may be, will be considered the sole owner and holder of the global security and the debt securities represented thereby for all purposes under the debt securities and the applicable indenture. Except in the limited circumstances referred to above, owners of beneficial interests in a global security will not be entitled to have that global security or any debt securities represented thereby registered in their names, will not receive or be entitled to receive physical delivery of certificated debt securities in exchange therefor and will not be considered to be the owners or holders of the global security or any debt securities represented thereby for any purpose under the debt securities or the applicable indenture. All payments of principal of and any premium and

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interest on a global security will be made to the depositary or its nominee, as the case may be, as the holder thereof. The laws of some jurisdictions require that certain purchasers of debt securities take physical delivery of such debt securities in definitive form. These laws may impair the ability to transfer beneficial interests in a global security.

Ownership of beneficial interests in a global security will be limited to institutions that have accounts with the depositary or its nominee (“participants”) and to persons that may hold beneficial interests through participants. In connection with the issuance of any global security, the depositary will credit, on its book-entry registration and transfer system, the respective principal amounts of debt securities represented by the global security to the accounts of its participants. Ownership of beneficial interests in a global security will be shown only on, and the transfer of those ownership interests will be effected only through, records maintained by the depositary (with respect to participants’ interests) or any such participant (with respect to interests of persons held by such participants on their behalf). Payments, transfers, exchanges and other matters relating to beneficial interests in a global security may be subject to various policies and procedures adopted by the depositary from time to time. None of us, the Trustees or our agents will have any responsibility or liability for any aspect of the depositary’s or any participant’s records relating to, or for payments made on account of, beneficial interests in a global security, or for maintaining, supervising or reviewing any records relating to such beneficial interests.

Payment and Paying Agents

Unless otherwise indicated in the applicable prospectus supplement, payment of interest on a debt security on any interest payment date will be made to the person in whose name such debt security (or one or more predecessor debt securities) is registered at the close of business on the regular record date for such interest.

Unless otherwise indicated in the applicable prospectus supplement, principal of and any premium and interest on the debt securities of a particular series will be payable at the office of such paying agent or paying agents as we may designate for such purpose from time to time, except that at our option payment of any interest may be made by check mailed to the address of the Person entitled thereto as such address appears in the security register. Unless otherwise indicated in the applicable prospectus supplement, the corporate trust office of the trustee under the senior indenture in the City of New York will be designated as sole paying agent for payments with respect to senior debt securities of each series and the corporate trust office of the trustee in the City of New York will be designated as the sole paying agent for payment with respect to subordinated debt securities of each series. Any other paying agents initially designated by us for the debt securities of a particular series will be named in the applicable prospectus supplement. We may at any time designate additional paying agents or rescind the designation of any paying agent or approve a change in the office through which any paying agent acts, except that we will be required to maintain a paying agent in each place of payment for the debt securities of a particular series.

All moneys paid by us to a paying agent for the payment of the principal of or any premium or interest on any debt security that remain unclaimed at the end of two years after such principal, premium or interest has become due and payable will be repaid to us, and the holder of such debt security thereafter may look only to us for payment thereof.

Consolidation, Merger and Sale of Assets

We may not consolidate with or merge into, or convey, transfer, sell or lease our properties and assets substantially as an entirety to, any person (a “successor Person”), and may not permit any person to merge into, or convey, transfer, sell or lease its properties and assets substantially as an entirety to, us, unless:

• the successor person (if any) is a corporation, partnership, trust or other entity organized and validly existing under the laws of any domestic jurisdiction and assumes our obligations on the debt securities and under the indentures;

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• immediately after giving effect to the transaction, no Event of Default, and no event that, after notice or lapse of time or both, would become an Event of Default, shall have occurred and be continuing; and

• certain other conditions, including any additional conditions with respect to any particular debt securities specified in the applicable prospectus supplement, are met.

Reports

So long as any debt securities are outstanding, we will:

• file with the Trustee, within 15 days after we file them with the SEC, copies of the annual reports and of the information, documents and other reports which we are required to file with the SEC pursuant to the Exchange Act; and

• if we are not required to file information with the SEC pursuant to the Exchange Act, file with the Trustee, within 15 days after we would have been required to file with the SEC, and provide holders of the debt securities with, annual reports and information, documents and other reports comparable to what we would have been required to file with the SEC had we been subject to the reporting requirements of the Exchange Act.

Events of Default

Unless otherwise specified in the prospectus supplement, each of the following will constitute an “Event of Default” under the applicable indenture with respect to debt securities of any series:

• failure to pay principal of or any premium on any debt security of that series when due, whether or not, in the case of subordinated debt securities, such payment is prohibited by the subordination provisions of the subordinated indenture;

• failure to pay any interest on any debt securities of that series when due, continued for 30 days, whether or not, in the case of subordinated debt securities, such payment is prohibited by the subordination provisions of the subordinated indenture;

• failure to deposit any sinking fund payment when due in respect of any debt security of that series, whether or not, in the case of subordinated debt securities, such deposit is prohibited by the subordination provisions of the subordinated indenture;

• failure by the issuer or, if the series of debt securities is guaranteed by a Subsidiary Guarantor, the Subsidiary Guarantor, to perform, or a breach of, any of the other covenants or warranties in such indenture (other than a covenant or warranty included in such indenture solely for the benefit of a series other than that series), continued for 60 days after written notice has been given by the trustee, or the holders of at least 25% in principal amount of the outstanding debt securities of that series, as provided in such indenture;

• certain events of bankruptcy, insolvency or reorganization affecting us or, if the series of debt securities is guaranteed, the Subsidiary Guarantors;

• if the series of debt securities is guaranteed by any Subsidiary Guarantors:

• any of the guarantees ceases to be in full force and effect, except as otherwise provided in the Indenture;

• any of the guarantees is declared null and void in a judicial proceeding; or

• any Subsidiary Guarantor denies or disaffirms its obligations under the Indenture or its guarantee; and

• any other Event of Default included in the applicable indenture or supplemental indenture.

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If an Event of Default (other than an Event of Default described in the fifth bullet above) with respect to the debt securities of any series at the time outstanding shall occur and be continuing, either the applicable Trustee or the holders of at least 25% in aggregate principal amount of the outstanding debt securities of that series by notice as provided in the indenture may declare the principal amount of the debt securities of that series (or, in the case of any debt security that is an original issue discount debt security or the principal amount of which is not then determinable, such portion of the principal amount of such debt security, or such other amount in lieu of such principal amount, as may be specified in the terms of such debt security) to be due and payable immediately. If an Event of Default described in the fifth bullet above with respect to the debt securities of any series at the time outstanding shall occur, the principal amount of all the debt securities of that series (or, in the case of any such original issue discount security or other debt security, such specified amount) will automatically, and without any action by the applicable Trustee or any holder, become immediately due and payable. After any such acceleration, but before a judgment or decree based on acceleration, the holders of a majority in aggregate principal amount of the outstanding debt securities of that series may, under certain circumstances, rescind and annul such acceleration if all Events of Default, other than the non-payment of accelerated principal (or other specified amount), have been cured or waived as provided in the applicable indenture. For information as to waiver of defaults, we refer you to “—Amendments and Waivers.”

Subject to the provisions of the indentures relating to the duties of the Trustees in case an Event of Default shall occur and be continuing, each Trustee will be under no obligation to exercise any of its rights or powers under the applicable indenture at the request or direction of any of the holders, unless such holders shall have offered to such Trustee reasonable indemnity. Subject to such provisions for the indemnification of the Trustees, the holders of a majority in aggregate principal amount of the outstanding debt securities of any series will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or exercising any trust or power conferred on the Trustee with respect to the debt securities of that series.

No holder of a debt security of any series will have any right to institute any proceeding with respect to the applicable indenture, or for the appointment of a receiver or a trustee, or for any other remedy thereunder, unless:

• such holder has previously given to the Trustee under the applicable indenture written notice of a continuing Event of Default with respect to the debt securities of that series;

• the holders of at least 25% in aggregate principal amount of the outstanding debt securities of that series have made written request, and such holder or holders have offered reasonable indemnity, to the Trustee to institute such proceeding as trustee; and

• the Trustee has failed to institute such proceeding, and has not received from the holders of a majority in aggregate principal amount of the outstanding debt securities of that series a direction inconsistent with such request, within 60 days after such notice, request and offer.

However, such limitations do not apply to a suit instituted by a holder of a debt security for the enforcement of payment of the principal of or any premium or interest on such debt security on or after the applicable due date specified in such debt security.

We will be required to furnish to each Trustee annually a statement by certain of our officers as to whether or not we, to our knowledge, are in default in the performance or observance of any of the terms, provisions and conditions of the applicable indenture and, if so, specifying all such known defaults.

Amendments and Waivers

We may amend the indentures without the consent of any holder of debt securities to:

• cure any ambiguity, defect or inconsistency;

• make any change in respect of any other series of debt securities issued under the indenture that is not applicable to such series;

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• provide for the assumption by a successor of our obligations under the indenture;

• add Subsidiary Guarantors with respect to the debt securities;

• secure the debt securities;

• add covenants for the protection of the holders or surrender any right or power conferred upon us or any Subsidiary Guarantors;

• make any change that does not adversely affect the rights of any holder;

• add or appoint a successor or separate Trustee;

• comply with any requirements of the SEC in connection with the qualification of the indenture under the Trust Indenture Act; or

• establish the form or terms of debt securities of any series to be issued under the indenture.

In addition, we may amend the indenture if the holders of a majority in principal amount of all outstanding debt securities of each series that would be affected under the indenture consent to it. We may not, however, without the consent of each holder of any outstanding debt securities that would be affected, amend the indenture to:

• change the stated maturity of the principal of, or any installment of principal of or interest on, any debt security;

• reduce the principal amount of, or any premium or interest on, any debt security;

• reduce the amount of principal of an original issue discount security or any other debt security payable upon acceleration of the maturity thereof;

• change the place or currency of payment of principal of, or any premium or interest on, any debt security;

• impair the right to institute suit for the enforcement of any payment on or with respect to any debt security;

• in the case of subordinated debt securities, modify the subordination provisions in a manner adverse to the holders of the subordinated debt securities;

• if applicable, make any change that adversely affects the right to convert any debt security or decrease the conversion rate or increase the conversion price;

• reduce the percentage in principal amount of outstanding debt securities of any series, the consent of whose holders is required for modification or amendment of the indenture;

• reduce the percentage in principal amount of outstanding debt securities of any series necessary for waiver of compliance with certain provisions of the indenture or for waiver of certain defaults;

• modify such provisions with respect to modification and waiver;

• release a Subsidiary Guarantor or modify such Subsidiary Guarantor’s guarantee in any manner adverse to the holders; or

• following the making of an offer to purchase debt securities pursuant to a covenant in the indenture, modify the provisions of the indenture with respect to such offer to purchase in a manner adverse to the holders.

The holders of a majority in principal amount of the outstanding debt securities of any series may waive compliance by us or a Subsidiary Guarantor with certain restrictive provisions of the applicable indenture. The holders of a majority in principal amount of the outstanding debt securities of any series may waive any past

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default under the applicable indenture, except a default in the payment of principal, premium or interest and certain covenants and provisions of the applicable indenture that cannot be amended without the consent of the holder of each outstanding debt security of such series affected.

Defeasance and Covenant Defeasance

If and to the extent indicated in the applicable prospectus supplement, we may elect, at our option at any time, to have the provisions of the indenture, relating to defeasance and discharge of indebtedness relating to defeasance of certain restrictive covenants applied to the debt securities of any series, or to any specified part of a series.

Defeasance and Discharge. The indentures provide that, upon our exercise of our option (if any), we will be discharged from all our obligations, and, if such debt securities are subordinated debt securities, the provisions of the subordinated indenture relating to subordination will cease to be effective, with respect to such debt securities (except for certain obligations to exchange or register the transfer of debt securities, to replace stolen, lost or mutilated debt securities, to maintain paying agencies and to hold moneys for payment in trust) upon the deposit in trust for the benefit of the holders of such debt securities of money or U.S. Government obligations, or both, that, through the payment of principal and interest in respect thereof in accordance with their terms, will provide money in an amount sufficient to pay the principal of and any premium and interest on such debt securities on the respective stated maturities in accordance with the terms of the applicable indenture and such debt securities. Such defeasance or discharge may occur only if, among other things:

• we have delivered to the applicable Trustee an opinion of counsel to the effect that we have received from, or there has been published by, the United States Internal Revenue Service a ruling, or there has been a change in tax law, in either case to the effect that holders of such debt securities will not recognize gain or loss for federal income tax purposes as a result of such deposit, defeasance and discharge and will be subject to federal income tax on the same amount, in the same manner and at the same times as would have been the case if such deposit, defeasance and discharge were not to occur;

• no Event of Default or event that with the passing of time or the giving of notice, or both, shall constitute an Event of Default shall have occurred or be continuing;

• such deposit, defeasance and discharge will not result in a breach or violation of, or constitute a default under, any agreement or instrument to which we are a party or by which we are bound; and

• in the case of subordinated debt securities, at the time of such deposit, no default in the payment of all or a portion of principal of (or premium, if any) or interest on or other obligations in respect of any senior debt of Penn Virginia shall have occurred and be continuing and no other Event of Default with respect to any of our Senior Debt shall have occurred and be continuing permitting, after notice or the lapse of time, or both, the acceleration thereof.

If we exercise this defeasance option, any guarantee will terminate with respect to that series of debt securities.

Defeasance of Certain Covenants. The indentures provide that, upon our exercise of our option (if any), we may omit to comply with certain restrictive covenants, including those that may be described in the applicable prospectus supplement, the occurrence of certain Events of Default, which are described above in the fourth bullet (with respect to such restrictive covenants), in the fifth bullet (with respect only to a Subsidiary Guarantor (if any)) and in the sixth bullet under “— Events of Default” and any that may be described in the applicable prospectus supplement, will not be deemed to either be or result in an Event of Default and, if such debt securities are subordinated debt securities, the provisions of the subordinated indenture relating to subordination will cease to be effective, in each case with respect to such debt securities. In order to exercise such option, we must deposit, in trust for the benefit of the holders of such debt securities, money or U.S. Government

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obligations, or both, that, through the payment of principal and interest in respect thereof in accordance with their terms, will provide money in an amount sufficient to pay the principal of and any premium and interest on such debt securities on the respective stated maturities in accordance with the terms of the applicable indenture and such debt securities. Such covenant defeasance may occur only if we have delivered to the applicable Trustee an opinion of counsel that in effect says that holders of such debt securities will not recognize gain or loss for federal income tax purposes as a result of such deposit and defeasance of certain obligations and will be subject to federal income tax on the same amount, in the same manner and at the same times as would have been the case if such deposit and defeasance were not to occur and the requirements set forth in the second through fourth bullets above are satisfied. If we exercise this option with respect to any debt securities and such debt securities were declared due and payable because of the occurrence of any Event of Default, the amount of money and U.S. Government obligations so deposited in trust would be sufficient to pay amounts due on such debt securities at the time of their respective stated maturities, but may not be sufficient to pay amounts due on such debt securities upon any acceleration resulting from such Event of Default. In such case, we would remain liable for such payments.

Notices

Notices to holders of debt securities will be given by mail to the addresses of such holders as they may appear in the security register.

Title

We, the Trustees and any agent of us or a Trustee may treat the person in whose name a debt security is registered as the absolute owner of the debt security (whether or not such debt security may be overdue) for the purpose of making payment and for all other purposes.

Governing Law

The indentures and the debt securities will be governed by, and construed in accordance with, the law of the State of New York.

DESCRIPTION OF CAPITAL STOCK

As of June 12, 2007, our authorized capital stock was 64,100,000 shares. Those shares consisted of 100,000 shares of preferred stock, none of which were outstanding, and 64,000,000 shares of common stock, par value $0.01 per share, of which 18,794,596 shares were outstanding.

Common Stock

Listing

Our outstanding shares of common stock are listed on the New York Stock Exchange (the “NYSE”) under the symbol “PVA.” Any additional common stock we issue also will be listed on the NYSE.

Dividends

Subject to the rights of any series of preferred stock that we may issue, the holders of common stock may receive dividends when declared by our board of directors. Dividends may be paid in cash, stock or other form out of legally available funds.

Fully Paid

All outstanding shares of common stock are fully paid and non-assessable. Any additional common stock we issue will also be fully paid and non-assessable.

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Preferred Share Purchase Rights

Pursuant to our Shareholder Rights Plan, each share of common stock includes a preferred share purchase right, as more fully described below under “—Anti-Takeover Provisions—Shareholder Rights Plan.”

Voting Rights

Subject to any special voting rights of any series of preferred stock that we may issue in the future, the holders of common stock may vote one vote for each share held in the election of directors and on all other matters voted upon by our shareholders. Directors are elected by a plurality of the votes cast by the shares entitled to vote. Holders of common stock may not cumulate their votes in the elections of directors. All other matters to be voted on by shareholders must be approved by a majority of the votes cast on the matter. Certain significant transactions defined in our articles of incorporation may also require the affirmative vote of 90% of the voting power of all outstanding shares entitled to vote in the election of directors. See “— Anti-Takeover Provisions—Certain Provisions in Our Articles of Incorporation—Fair Price Provisions” below.

Other Rights

We will notify common shareholders of any shareholders’ meetings according to applicable law. If we liquidate, dissolve or wind-up our business, either voluntarily or not, common shareholders will share equally in the assets remaining after we pay our creditors and preferred shareholders. The holders of common stock have no preemptive rights to purchase our shares of stock. Shares of common stock are not subject to any redemption or sinking fund provisions and are not convertible into any of our other securities.

Preferred Stock

The following description of the terms of the preferred stock sets forth certain general terms and provisions of our authorized preferred stock. If we offer preferred stock, a description will be filed with the SEC and the specific designations and rights will be described in the prospectus supplement, including the following terms:

• the series, the number of shares offered and the liquidation value of the preferred stock;

• the price at which the preferred stock will be issued;

• the dividend rate, the dates on which the dividends will be payable and other terms relating to the payment of dividends on the preferred stock;

• the liquidation preference of the preferred stock;

• the voting rights of the preferred stock;

• whether the preferred stock is redeemable or subject to a sinking fund, and the terms of any such redemption or sinking fund;

• whether the preferred stock is convertible or exchangeable for any other securities, and the terms of any such conversion; and

• any additional rights, preferences, qualifications, limitations and restrictions of the preferred stock.

The description of the terms of the preferred stock to be set forth in an applicable prospectus supplement will not be complete and will be subject to and qualified in its entirety by reference to the articles of amendment relating to the applicable series of preferred stock. The registration statement of which this prospectus forms a part will include the articles of amendment as an exhibit or incorporate it by reference.

Our board of directors can, without approval of shareholders, issue one or more series of preferred stock. Subject to the provisions of our articles of incorporation and limitations prescribed by law, our board of directors may adopt an amendment to our articles of incorporation describing the number of shares of each series and the rights, preferences and limitations of each series, including the dividend rights, voting rights, conversion rights,

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redemption rights and any liquidation preferences of any wholly unissued series of preferred stock, the number of shares constituting each series and the terms and conditions of issue.

Undesignated preferred stock may enable our board of directors to render more difficult or to discourage an attempt to obtain control of us by means of a tender offer, proxy contest, merger or otherwise, and to thereby protect the continuity of our management. The issuance of shares of preferred stock may adversely affect the rights of the holders of our common stock. For example, any preferred stock issued may rank prior to our common stock as to dividend rights, liquidation preference or both, may have full or limited voting rights and may be convertible into shares of common stock. As a result, the issuance of shares of preferred stock may discourage bids for our common stock or may otherwise adversely affect the market price of our common stock or any existing preferred stock.

The preferred stock will, when issued, be fully paid and non-assessable.

Anti-Takeover Provisions

Certain provisions in our articles of incorporation and by-laws, as well as certain provisions of Virginia law, may make more difficult or discourage a takeover of our business.

Certain Provisions of Our Articles of Incorporation

Shareholder Action by Unanimous Consent. Under Virginia law, any action that could be taken by shareholders at a meeting may be taken, instead, without a meeting and without notice if a consent in writing is signed by all the shareholders entitled to vote on the action.

Blank Check Preferred Stock. Our articles of incorporation authorize the issuance of blank check preferred stock. As described above under “Preferred Stock,” the board of directors can set the voting rights, redemption rights, conversion rights and other rights relating to such preferred stock and could issue such stock in either private or public transactions. In some circumstances, the blank check preferred stock could be issued and have the effect of preventing a merger, tender offer or other takeover attempt that the board of directors opposes.

Fair Price Provisions. Our articles of incorporation contain certain “fair price” provisions. These provisions state that any person who acquires 10% or more of our voting stock cannot engage in a significant transaction with us that is not approved by our continuing directors or the holders of 90% of our stock unless our shareholders receive a price at least equal to that determined by a formula set forth in our articles of incorporation. In addition, if the acquiror paid cash to acquire his original interests, he must pay cash in the subsequent significant transaction. Under these provisions, continuing directors are directors who were on the board prior to the acquiror’s 10% or more acquisition or were subsequently recommended by such original directors.

Election and Removal of Directors

Our directors are elected for one-year terms and can be removed, with or without cause, if the number of votes cast for removal at a shareholder meeting called for that purpose constitutes a majority of the votes entitled to be cast at an election of directors. Our by-laws currently provide that the total number of directors is eight, but the number of directors may be increased or decreased by amendment of the by-laws. Vacancies in the board may be filled by shareholders or by the board. Special meetings of shareholders may be called only by a majority of our board of directors or by our chief executive officer. Our by-laws require that advance notice of nominees for election as directors be made by a shareholder, and that shareholder proposals be given to our corporate secretary, together with certain specified information, not less than 90 days nor more than 180 days before the anniversary of the immediately preceding annual meeting of shareholders.

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Virginia Anti-Takeover Statutes and Other Virginia Laws

Control Share Acquisition Statute. As permitted by Virginia law, we have opted out of the Virginia anti-takeover law regulating “control share acquisitions.” Under that Virginia statute, shares acquired in an acquisition that would cause an acquiror’s voting strength to meet or exceed any of three thresholds (20%, 33 ¹/3% or 50%) have no voting rights unless those rights are granted by a majority vote of all outstanding shares other than those held by the acquiror or any officer or employee director of the corporation. An acquiring person that owns five percent or more of the corporation’s voting stock may require that a special meeting of the shareholders be held, to consider the grant of voting rights to the shares acquired in the control share acquisition. This regulation was designed to deter certain takeovers of Virginia public corporations.

Affiliated Transactions. Under the Virginia anti-takeover law regulating affiliated transactions, material acquisition transactions between a Virginia corporation and any holder of more than 10% of any class of its outstanding voting shares are required to be approved by the holders of at least two-thirds of the remaining voting shares. Affiliated transactions subject to this approval requirement include mergers, share exchanges, material dispositions of corporate assets not in the ordinary course of business, any dissolution of the corporation proposed by or on behalf of a 10% holder or any reclassification, including reverse stock splits, recapitalization or merger of the corporation with its subsidiaries, that increases the percentage of voting shares owned beneficially by a 10% holder by more than five percent. For three years following the time that a shareholder becomes an interested shareholder, a Virginia corporation cannot engage in an affiliated transaction with the interested shareholder without approval of two-thirds of the disinterested voting shares and a majority of the disinterested directors. A disinterested director is a director who was a director on the date on which an interested shareholder became an interested shareholder or was recommended for election or elected by a majority of the disinterested directors then on the board. After three years, the approval of the disinterested directors is no longer required. The provisions of this statute do not apply if a majority of disinterested directors approve the acquisition of shares making a person an interested shareholder. Virginia law permits corporations to opt out of the affiliated transactions provisions. We have not opted out.

Director Standards of Conduct. Under Virginia law, directors must discharge their duties in accordance with their good faith business judgment of the best interests of the corporation. Directors may rely on the advice or acts of others, including officers, employees, attorneys, accountants and board committees if they have a good faith belief in their competence. Virginia law provides that, in determining the best interests of the corporation, a director may consider the possibility that those interests may best be served by the continued independence of the corporation.

Shareholder Rights Plan

Our board of directors has adopted a shareholder rights plan (the “Rights Plan”) pursuant to which each outstanding share of our common stock has associated with it a right (a “Right”). Each Right entitles the registered holder under the circumstances described below to purchase from us one one-thousandth of a share of our Series A Junior Participating Preferred Stock (the “Preferred Shares”) at a price of $100.00 (the “Purchase Price”), subject to adjustment. The following is a summary of certain terms of the Rights Plan. The Rights Plan is an exhibit to the registration statement of which this prospectus is a part and this summary is qualified by reference to the specific terms of the Rights Plan.

Until the Distribution Date, the Rights will be evidenced by the certificates representing shares of common stock outstanding, and no separate certificates for the Rights will be distributed. The Rights will separate from the common stock and the Distribution Date will occur upon the earlier of

• ten calendar days following the public announcement that a person or group of affiliated or associated persons has become an Acquiring Person; or

• ten business days or such later date as may be determined by a majority of Continuing Directors after the commencement of, or first public announcement of an intention to commence, a tender offer or exchange offer that would result in a person or group beneficially owning 15% or more of our common stock.

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With certain exceptions described in the Rights Agreement, a person or group becomes an Acquiring Person when such person or group acquires or obtains the right to acquire beneficial ownership of 15% or more of the then outstanding shares of our common stock, or 10% or more of those shares if our board of directors, in accordance with its good faith business judgment of our best interests, declares the acquiror an Adverse Person under guidelines set forth in the Rights Agreement. The board of directors may declare any person to be an Adverse Person after it determines:

• that this person, together with all this person’s affiliates and associates, has become the beneficial owner of at least 10% of our common stock, and

• that this ownership is reasonably likely to cause us to repurchase the common stock owned by this person or cause us to take action that would provide this person with short-term gain to the detriment of our long-term interests or is causing or reasonably likely to cause a material adverse impact on our business, financial position or prospects.

Under the Rights Plan, a Continuing Director is any member of our board of directors who is not an Acquiring Person or an affiliate or associate or representative of an Acquiring Person, and was a member of the board prior to February 21, 1998, or any person who subsequently becomes a member of the board who, while a member of the board, is not an Acquiring Person, or an affiliate or associate or representative of an Acquiring Person, if the member’s nomination for election or election to the board is recommended or approved by a majority of the Continuing Directors of which there must be at least a majority then in office.

The Rights are not exercisable until the Distribution Date and will expire at the close of business on February 11, 2008, unless earlier redeemed or exchanged as described below.

As soon as practicable after the Distribution Date, separate certificates evidencing the Rights will be mailed to holders of record of our common stock as of the close of business on the Distribution Date, and thereafter, the separate Rights certificates alone will represent the Rights. Except as otherwise provided by the Rights Agreement or determined by our board of directors, only shares of common stock issued prior to the Distribution Date will be issued with Rights.

In the event that a person becomes an Acquiring Person, each holder of a Right, other than any Acquiring Person, whose Rights will become null and void, will thereafter have the right to receive, upon exercise, shares of our common stock, or in certain circumstances, cash, property or other securities, having a value equal to two times the Purchase Price of the Right.

After a person or group has become an Acquiring Person, in the event that:

• we consolidate or merge with any other person, and we are not the surviving corporation,

• any person engages in a share exchange, consolidation or merger with us where our common stock is exchanged for securities, cash or property of the other person and we are the surviving corporation,

• we are a party to a statutory share exchange with any other person after which we are a subsidiary of any other person or

• 50% or more of our assets or earning power is sold or transferred,

proper provision will be made so that each holder of a Right, other than any Acquiring Person, whose Rights will become null and void, will thereafter have the right to receive, upon exercise, common stock of the acquiring company having a value equal to two times the Purchase Price of the Right. The events described in this paragraph are called “Triggering Events” in the Rights Plan.

The Purchase Price payable, and the number of shares of common stock or other securities, cash or property issuable, upon exercise of the Rights are subject to customary adjustments from time to time to prevent dilution

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in the event of certain changes in our shares. With certain exceptions, no adjustment in the Purchase Price will be required until cumulative adjustments amount to an increase or decrease of at least 1% in the Purchase Price.

At any time before there is an Acquiring Person, our board of directors may redeem the Rights in whole, but not in part, at a price of $.001 per Right. If redemption takes place after an Adverse Change of Control, at least a majority of the members of the board of directors must be Continuing Directors and redemption must be approved by a majority of Continuing Directors. The redemption of the Rights may be made effective at the time, on the basis, and with the conditions as our board of directors in its sole discretion may establish. Immediately upon the action of our board of directors ordering the redemption of the Rights, the right to exercise the Rights will terminate and the only right of the holders of Rights will be to receive the redemption price.

Under the Rights Plan, an Adverse Change of Control occurs if a change resulting from a proxy or consent solicitation in any of our directors in office at the commencement of the solicitation, if any person who is or was a participant in such solicitation has stated, or if upon the commencement of such solicitation, a majority of our board of directors has determined in good faith, that person has taken or intends to take, or may consider taking, any action that would result in that person becoming an Acquiring Person or that would cause the occurrence of a Triggering Event.

At any time after a person becomes an Acquiring Person, but before the Acquiring Person owns 50% or more of our common stock, our board of directors provided that at least a majority of the members are Continuing Directors and the exchange is authorized by a majority of Continuing Directors, may exchange the then outstanding and exercisable Rights, other than those owned by an Acquiring Person, for shares of common stock, each Right being exchangeable for one share of common stock, subject to adjustment.

Until a Right is exercised, the holder thereof, as such, will have no rights as a shareholder, including, without limitation, the right to vote or to receive dividends.

The terms of the Rights may be amended by our board of directors without the consent of the holders of the Rights. However, if an amendment takes place after an Adverse Change of Control, at least a majority of the members must be Continuing Directors and the amendment must be approved by a majority of Continuing Directors.

The Rights have certain anti-takeover effects. The Rights will cause substantial dilution to a person or group that attempts to acquire us without conditioning the offer on a substantial number of Rights being acquired. Accordingly, the existence of the Rights may deter certain acquirers from making takeover proposals or tender offers.

Indemnification of Officers and Directors

Virginia law permits, and our by-laws provide for, the indemnification of our directors and officers with respect to certain liabilities and expenses imposed upon them in connection with any civil, criminal or other proceeding by reason of having been a director or officer of Penn Virginia. This indemnification does not apply to willful misconduct or a knowing violation of the criminal law. We have been informed that in the opinion of the Securities and Exchange Commission indemnification for liability under the Securities Act of 1933 is against public policy and is unenforceable.

Transfer Agent and Registrar

Our transfer agent and registrar of the common stock, as well as the rights agent under our Rights Plan, is American Stock Transfer & Trust Company.

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DESCRIPTION OF DEPOSITARY SHARES

We may offer depositary shares (either separately or together with other securities) representing fractional interests in our preferred stock of any series. In connection with the issuance of any depositary shares, we will enter into a deposit agreement with a bank or trust company, as depositary, which will be named in the applicable prospectus supplement. Depositary shares will be evidenced by depositary receipts issued pursuant to the related deposit agreement. Immediately following our issuance of the preferred stock related to the depositary shares, we will deposit the preferred stock with the relevant preferred stock depositary and will cause the preferred stock depositary to issue, on our behalf, the related depositary receipts. Subject to the terms of the deposit agreement, each owner of a depositary receipt will be entitled, in proportion to the fraction of a share of preferred stock represented by the related depositary share, to all the rights, preferences and privileges of, and will be subject to all of the limitations and restrictions on, the preferred stock represented by the depositary receipt (including, if applicable, dividend, voting, conversion, exchange redemption and liquidation rights).

DESCRIPTION OF WARRANTS

We may issue warrants for the purchase of debt securities, preferred stock or common stock. Warrants may be issued independently or together with, or as a unit including, debt securities, preferred stock or common stock offered by any prospectus supplement and may be attached to or separate from any of the other offered securities. Each warrant will entitle the holder to purchase the principal amount of debt securities or number of shares of preferred stock or common stock, as the case may be, at the exercise price and in the manner specified in the prospectus supplement relating to those warrants. Warrants will be issued under one or more warrant agreements to be entered into between us and a bank or trust company, as warrant agent. The warrant agent will act solely as our agent in connection with the warrants and will not assume any obligation or relationship of agency or trust for or with any holders or beneficial owners of warrants. We will file the warrant agreement, and any unit agreement, with the SEC in connection with any offering of warrants.

The prospectus supplement relating to a particular issuance of warrants will describe the terms of the warrants, including the following:

• the title of the warrants;

• the offering price for the warrants, if any;

• the aggregate number of the warrants;

• the designation and terms of the securities purchasable upon exercise of the warrants;

• if applicable, the designation and terms of the securities with which the warrants are issued and the number of such warrants issued with each security;

• if applicable, the date from and after which the warrants and any securities issued with the warrants will be separately transferable;

• the principal amount of debt securities purchasable upon exercise of a warrant, if a debt warrant, and the price at which the principal amount of securities may be purchased upon exercise, which price may be payable in cash, securities, or other property;

• the date on which the right to exercise the warrants commences and the date on which the right expires;

• if applicable, the number of shares of common stock or preferred stock purchasable upon exercise of a warrant and the price at which the shares may be purchased upon exercise;

• if applicable, the minimum or maximum amount of the warrants that may be exercised at any one time;

• if applicable, a discussion of material United States federal income tax considerations;

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• whether the debt warrants represented by the warrant certificates or debt securities that may be issued upon exercise of the warrants will be issued in registered or bearer form;

• information with respect to book-entry procedures, if any;

• the currency or currency units in which the offering price, if any, and the exercise price are payable;

• the antidilution provisions of the warrants, if any;

• the redemption or call provisions, if any, applicable to the warrants; and

• any additional terms of the warrants, including terms, procedures, and limitations relating to the exchange and exercise of the warrants.

PLAN OF DISTRIBUTION

We may sell the securities pursuant to this prospectus:

• through agents;

• through underwriters or dealers; or

• directly to one or more purchasers, including existing shareholders in a rights offering.

By Agents

Securities offered by us pursuant to this prospectus may be sold through agents designated by us. Unless otherwise indicated in the prospectus supplement, any such agent is acting on a best efforts basis for the period of its appointment.

By Underwriters

If underwriters are used in the sale, the offered securities will be acquired by the underwriters for their own account. The underwriters may resell the securities in one or more transactions, including negotiated transactions, at a fixed public offering price or at varying prices determined at the time of sale. The obligations of the underwriters to purchase the securities will be subject to certain conditions. Unless otherwise indicated in the prospectus supplement, the underwriters must purchase all the securities of the series offered by a prospectus supplement if any of the securities are purchased. Any initial public offering price and any discounts or concessions allowed or re-allowed or paid to dealers may be changed from time to time.

Direct Sales; Rights Offerings

Securities offered by us pursuant to this prospectus may also be sold directly by us. In this case, no underwriters or agents would be involved. We may sell offered securities upon the exercise of rights that may be issued to our securityholders. We may sell the securities directly to institutional investors or others who may be deemed to be underwriters within the meaning of the Securities Act with respect to any sale of those securities.

Delayed Delivery Arrangements

We may authorize agents, underwriters or dealers to solicit offers by certain institutional investors to purchase offered securities providing for payment and delivery on a future date specified in the prospectus supplement. Institutional investors to which such offers may be made, when authorized, include commercial and savings banks, insurance companies, pension funds, investment companies, education and charitable institutions and such other institutions as may be approved by us. The obligations of any such purchasers under such delayed delivery and payment arrangements will be subject to the condition that the purchase of the offered securities will not at the time of delivery be prohibited under applicable law. The underwriters and such agents will not have any responsibility with respect to the validity or performance of such contracts.

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General Information

Underwriters, dealers and agents that participate in the distribution of the offered securities may be underwriters as defined in the Securities Act, and any discounts or commissions received by them from us and any profit on the resale of the offered securities by them may be treated as underwriting discounts and commissions under the Securities Act. Any underwriters or agents will be identified and their compensation described in the applicable prospectus supplement.

The securities (other than common stock) offered by this prospectus and any prospectus supplement, when first issued, will have no established trading market. Any underwriters or agents to or through whom such securities are sold by us for public offering and sale may make a market in such securities, but such underwriters or agents will not be obligated to do so and may discontinue any market making at any time without notice. We cannot assure you as to the liquidity of the trading market for any such securities.

We may have agreements with the underwriters, dealers and agents to indemnify them against certain civil liabilities, including liabilities under the Securities Act, or to contribute with respect to payments that the underwriters, dealers or agents may be required to make.

Underwriters, dealers and agents may engage in transactions with, or perform services for, us or our subsidiaries in the ordinary course of their businesses.

LEGAL MATTERS

Our counsel, Vinson & Elkins L.L.P., New York, New York, will pass upon certain legal matters in connection with the offered securities. Certain legal matters relating to Virginia law will be passed upon for us by Hunton & Williams LLP. Any underwriters will be advised about other issues relating to any offering by their own legal counsel.

EXPERTS

The consolidated financial statements of Penn Virginia Corporation as of and for each of the years in the three-year period ended December 31, 2006, and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006 have been incorporated by reference herein in reliance upon the reports of KPMG LLP, independent registered public accounting firm, and upon the authority of said firm as experts in accounting and auditing. The audit report covering the December 31, 2006 consolidated financial statements refers to a change in accounting for share-based payments and postretirement plans.

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