Connect Gas Pipeline 424B5 Prospectus supplement for primary offering

Filed Pursuant to Rule No. 424(b)(5)
Registration No. 333-166103

CALCULATION OF REGISTRATION FEE

Class of Securities Registered	Proposed Aggregate Offering Price	Amount of Registration Fee(1)
8 1/4% Senior Notes due 2018	$300,000,000	$21,390
Subsidiary Guarantees of 8 1/4% Senior Notes due 2018	(2)	(2)

⁽¹⁾ The registration fee is being paid on a deferred basis in reliance upon Rules 456(b) and 457(r) and includes $39,060 that is being offset pursuant to Rule 457(p) for fees paid with respect to the $700,000,000 aggregate initial offering price of securities that were previously registered pursuant to Registration Statement No. 333-162118, initially filed on September 24, 2009. Pursuant to Rule 457(p) under the Securities Act, such unutilized filing fee may be applied to the filing fee payable in connection with the filing of this prospectus supplement pursuant to Rule 424(b).

⁽²⁾ In accordance with Rule 457(n), no separate fee is payable with respect to the Subsidiary Guarantees.

PROSPECTUS SUPPLEMENT

(to Prospectus dated April 16, 2010)

Penn Virginia Resource Partners, L.P.

Penn Virginia Resource Finance Corporation

$300,000,000

8  ¹/4% Senior Notes due 2018

We are offering $300,000,000 of our 8 ¹/4% Senior Notes due 2018. Interest on the notes will accrue from April 27, 2010 and will be payable semiannually on April 15 and October 15 of each year, beginning on October 15, 2010. The notes will mature on April 15, 2018.

We may redeem the notes at any time on or after April 15, 2014 at the redemption prices set forth in this prospectus supplement. We may redeem the notes prior to April 15, 2014 at the “make-whole” redemption price set forth in this prospectus supplement. In addition, we may redeem up to 35% of the notes until April 15, 2013 with the proceeds of certain equity offerings at the redemption price set forth in this prospectus supplement. If we sell certain of our assets or experience specific kinds of changes of control, we must offer to purchase the notes at prices set forth in this prospectus supplement plus accrued and unpaid interest.

The notes are senior unsecured obligations of Penn Virginia Resource Partners, L.P. and Penn Virginia Resource Finance Corporation, our wholly owned subsidiary that has no material assets. The notes will be fully and unconditionally guaranteed on a senior unsecured basis by our existing and future domestic restricted subsidiaries, subject to certain exceptions. The notes and the guarantees will rank equally with our existing and future senior unsecured indebtedness and will be effectively subordinated to all of our and the guarantors’ existing and future secured indebtedness (to the extent of the assets securing such indebtedness), including indebtedness under our revolving credit facility, and senior in right of payment to all existing and future subordinated debt.

Investing in the notes involves risks. Please read “Risk Factors” beginning on page S-17 of this prospectus supplement.

	Per Note		Total
Price to public1	100	%	$	300,000,000
Underwriting discounts and commissions	2.50	%	$	7,500,000
Estimated proceeds, before expenses, to Penn Virginia Resource Partners, L.P.	97.50	%	$	292,500,000

¹Plus accrued interest, if any, from April 27, 2010, if settlement occurs after that date.

None of the Securities and Exchange Commission, any state securities commission or any other regulatory body has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

We expect delivery of the notes will be made to investors in book-entry form through The Depository Trust Company on or about April 27, 2010.

Joint Book-Running Managers

Wells Fargo Securities BofA Merrill Lynch J.P. Morgan RBC Capital Markets

Senior Co-Managers

BB&T Capital Markets BNP PARIBAS Mitsubishi UFJ Securities PNC Capital Markets LLC

Co-Managers

Barclays Capital BMO Capital Markets Capital One Southcoast Comerica Securities Credit Suisse

SOCIETE GENERALE TD Securities UBS Investment Bank US Bancorp

The date of this prospectus supplement is April 22, 2010.

The map below shows the general locations of our coal reserves and related infrastructure investments and our natural gas gathering and processing systems as of December 31, 2009, as well as the natural gas gathering and pipeline systems we have agreed to construct in the Marcellus Shale formation of north central Pennsylvania.

TABLE OF CONTENTS

Prospectus Supplement

	Page
About This Prospectus Supplement	S-ii
Terms Used in this Prospectus Supplement	S-iii
Forward-Looking Statements	S-iv
Prospectus Supplement Summary	S-1
Risk Factors	S-17
Use of Proceeds	S-38
Capitalization	S-39
Selected Historical Financial and Operating Data	S-40
Management’s Discussion and Analysis of Financial Condition and Results of Operations	S-44
Business	S-70
Management	S-104
Certain Relationships and Related Party Transactions	S-107
Description of Certain Indebtedness	S-110
Description of Notes	S-111
Certain United States Federal Income and Estate Tax Considerations	S-161
Underwriting (Conflicts of Interest)	S-166
Legal Matters	S-170
Experts	S-170
Available Information	S-170
Incorporation by Reference	S-170
Index to Financial Statements	F-1

Prospectus

	Page
About This Prospectus	1
Who We Are	1
Risk Factors	1
Where You Can Find More Information	2
Incorporation of Certain Documents by Reference	2
Forward-Looking Statements	3
Use of Proceeds	4
Ratio of Earnings to Fixed Charges	5
Description of Debt Securities	5
Description of the Common Units	14
Cash Distribution Policy	18
Material Provisions of Our Partnership Agreement	21
Material Income Tax Consequences	31
Plan of Distribution	50
Legal Matters	51
Experts	51

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ABOUT THIS PROSPECTUS SUPPLEMENT

This document is in two parts. The first part is this prospectus supplement, which describes the specific terms of the notes we are offering and certain other matters. The second part, the base prospectus dated April 16, 2010, provides more general information about the various securities that we may offer from time to time, some of which information may not apply to the notes we are offering hereby. Generally when we refer to this prospectus, we are referring to both this prospectus supplement and the base prospectus combined. You should read this prospectus supplement along with the accompanying base prospectus, the documents incorporated by reference herein and therein, as well as any free writing prospectus that is filed. If any of the information in this prospectus supplement is inconsistent with any of the information in the base prospectus or the documents incorporated by reference herein or therein, you should rely on the information in this prospectus supplement.

You should rely only on the information contained in this prospectus supplement, the accompanying base prospectus and the documents incorporated by reference herein and therein or that is contained in any free writing prospectus relating to the notes. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not making an offer of the notes in any jurisdiction where their offer or sale is not permitted. The information in this prospectus supplement, the base prospectus and the documents incorporated herein and therein by reference may only be accurate as of their respective dates. Our business, financial condition, results of operations and prospects may have changed since those dates.

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TERMS USED IN THIS PROSPECTUS SUPPLEMENT

Unless the context requires otherwise, references in this prospectus supplement to the term:

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

• “the Partnership,” “we,” “us” or “our” refer to Penn Virginia Resource Partners and its subsidiaries, except in “Prospectus Supplement Summary—The Offering” and “Description of Notes”;

• “Finance Co.” refers to Penn Virginia Resource Finance Corporation, a Delaware corporation and a wholly owned subsidiary of Penn Virginia Resource Partners;

• “Issuers” refer to Penn Virginia Resource Partners and Finance Co.;

• “PVR GP” or “our general partner” refers to Penn Virginia Resource GP LLC, a Delaware limited liability company;

• “Penn Virginia” or “PVA” refers to Penn Virginia Corporation, a Virginia corporation;

• “PVOG” refers to Penn Virginia Oil & Gas Corporation, a Virginia corporation, and its subsidiaries;

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

• “PVG GP” means PVG GP, LLC, a Delaware limited liability company and the general partner of PVG.

The following are certain abbreviations and terms commonly used in the coal and oil and gas industries that are used in this prospectus supplement:

• “Bbl” refers to a standard barrel of 42 U.S. gallons liquid volume;

• “Bcf” refers to one billion cubic feet;

• “Bcfe” refers to 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” refers to British thermal unit;

• “Mbf” refers to one thousand board feet;

• “Mcf” refers to one thousand cubic feet;

• “MMBtu” refers to one million British thermal units;

• “MMcf” refers to one million cubic feet;

• “MMcfd” refers to one million cubic feet per day;

• “NGLs” refers to natural gas liquids, such as ethane, propane, normal butane, isobutane and natural gasoline;

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• “probable coal reserves” refers to 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 coal reserves, is high enough to assume continuity between points of observation; and

• “proven coal reserves” refers to 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.

FORWARD-LOOKING STATEMENTS

Some of the information included in this prospectus supplement and the documents we incorporate by reference contains forward-looking statements. 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 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, NGLs and coal;

• our ability to access external sources of capital;

• any impairment writedowns of our assets;

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

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

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

• the extent to which the amount and quality of actual production of our coal differs from estimated recoverable coal reserves;

• our ability to generate sufficient cash from our businesses to maintain and pay the quarterly distribution to our general partner and our unitholders;

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

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• operating risks, including unanticipated geological problems, incidental to our coal and natural resource management or natural gas midstream business;

• our 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;

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

• the ability of our lessees to produce sufficient quantities of coal on an economic basis from our 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 lessees’ mining operations and related coal infrastructure projects and new processing plants in our natural gas midstream business;

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

• the timing of receipt and availability of necessary governmental permits by us or our 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 and permissible levels of mining runoff;

• uncertainties relating to the outcome of current and future litigation regarding mine permitting and the effects of recent regulatory guidance on permitting under the Clean Water Act;

• uncertainties regarding Penn Virginia Corporation’s continued equity interest in the holding company of our general partner and its future business relationship with us;

• 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);

• risks set forth in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 and in other reports we file with the Securities and Exchange Commission, or the SEC, that are incorporated by reference in this prospectus supplement; and

• other risks set forth in “Risk Factors.”

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 in the documents incorporated by reference herein. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus, including those described in the “Risk Factors” section of this prospectus. We will not update these statements unless the securities laws require us to do so.

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PROSPECTUS SUPPLEMENT SUMMARY

This summary highlights information contained elsewhere in this prospectus supplement and the accompanying base prospectus. It does not contain all of the information that you should consider before making an investment decision. You should carefully read this entire prospectus supplement, the accompanying base prospectus and the documents incorporated by reference to understand fully the terms of the notes. You should also read “Risk Factors” contained in this prospectus supplement for more information about important risks that you should consider before buying notes in this offering.

The notes will be jointly issued by Penn Virginia Resource Partners and Finance Co., a wholly owned subsidiary of Penn Virginia Resource Partners. Finance Co. has no material assets and was formed for the sole purpose of being a co-issuer of the notes.

Penn Virginia Resource Partners, L.P.

Penn Virginia Resource Partners, L.P. (NYSE: PVR) is a publicly traded Delaware limited partnership formed in 2001 by Penn Virginia Corporation (NYSE: PVA), or Penn Virginia, that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. Both in our current limited partnership form and in our previous corporate form, we have managed coal properties since 1882. We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream. In the year ended December 31, 2009, we generated operating income of $108.3 million and Adjusted EBITDA of $184.8 million. Please read “—Non-GAAP Financial Measures” for a reconciliation of Adjusted EBITDA to net income and cash flows from operating activities. In the year ended December 31, 2009, our coal and natural resource management segment contributed $87.5 million, or 81%, to operating income, and our natural gas midstream segment contributed $20.8 million, or 19%, to operating income.

Coal and Natural Resource Management Segment

Our coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. We do not operate any mines, and therefore, we do not have direct exposure to mine operating costs or risks or mine reclamation costs. Coal royalties accounted for 83% of our coal and natural resource management segment revenues in the year ended December 31, 2009. We also earn 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, which accounted for 17% of our coal and natural resource management segment revenues for the year ended December 31, 2009. We have relatively low maintenance capital expenditure requirements that are associated with our coal and natural resource management activities.

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As of December 31, 2009, we owned or controlled approximately 829 million tons of proven and probable coal reserves in Central and Northern Appalachia, the Illinois Basin and the San Juan Basin. The following table sets forth reserve information with respect to each of our regions:

	Proven and Probable Coal Reserves as of December 31, 2009
Region	Underground	Surface	Total	Steam	Metallurgical	Total
	(tons in millions)
Central Appalachia	443.6	160.3	603.9	514.7	89.2	603.9
Northern Appalachia	23.4	—	23.4	23.4	—	23.4
Illinois Basin	154.2	9.7	163.9	163.9	—	163.9
San Juan Basin	—	37.4	37.4	37.4	—	37.4
Total	621.2	207.4	828.6	739.4	89.2	828.6

In the year ended December 31, 2009, our lessees produced 34.3 million tons of coal from our properties and paid us coal royalties revenues of $120.4 million, for an average royalty per ton of $3.51 ($3.34 per ton net of coal royalties expense). The following table sets forth production data with respect to each of our regions:

	Production for the Year Ended December 31,
Region	2009	2008	2007
	(tons in millions)
Central Appalachia	18.3	19.6	18.8
Northern Appalachia	3.8	3.6	4.2
Illinois Basin	4.7	4.6	3.8
San Juan Basin	7.5	5.9	5.7
Total	34.3	33.7	32.5

Approximately 82% of our coal royalties revenues in 2009 were derived from coal mined on our properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. However, because our lessees generally sell their coal under long-term contracts (one to five years), payments from these operators are not directly subject to short-term fluctuations in commodity prices. The balance of our coal royalties revenues in 2009 was derived from coal mined on our properties under leases containing fixed royalty rates that escalate annually.

Natural Gas Midstream Segment

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2009, we owned and operated natural gas midstream assets located in Oklahoma and Texas, including six natural gas processing facilities having 400 MMcfd of total capacity and approximately 4,118 miles of natural gas gathering pipelines. Our 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

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west-central Texas. In addition, we own a 25% member interest in Thunder Creek Gas Services, LLC, or Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin.

The following table sets forth information regarding our natural gas midstream assets at and for the year ended December 31, 2009:

Asset	Type	Approximate Length (Miles)	Current Processing Capacity (MMcfd)	Average System Throughput (MMcfd)
Panhandle System	Gathering pipelines and processing facilities	1,681	260	224	(1)
Crossroads System	Gathering pipelines and processing facility	8	80	47
Crescent System	Gathering pipelines and processing facility	1,701	40	22
Hamlin System	Gathering pipelines and processing facility	516	20	8
Arkoma System	Gathering pipelines	78	—	13
North Texas Gas Gathering System	Gathering pipelines	134	—	18
Total		4,118	400	332

(1) Includes gas processed at other systems connected to the Panhandle System.

In addition, the Thunder Creek joint venture had gathering pipelines of approximately 558 miles in length and 375 MMcfd of average system throughput at and for the year ended December 31, 2009.

We have recently entered into an agreement with a subsidiary of Range Resources Corporation, or Range, to construct and operate gas gathering and pipeline compression facilities servicing Range’s Marcellus Shale natural gas production located primarily in Lycoming County, Pennsylvania. Our total capital investment in this system is anticipated to range from $170 to $200 million through 2015. We expect that the initial phase of gathering and compression facilities will become operational in the fourth quarter of 2010. Revenues from this contract will be 100% fee-based. Please read “—Recent Developments—PVR Midstream Agreement with Range Resources.”

Our 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. We also own 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.

Business Strategies

We intend to pursue the following business strategies:

• Expand our natural gas midstream operations by adding new production to existing systems and acquiring or building new gathering and processing assets. We continually

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seek new supplies of natural gas both to offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and by contracting for natural gas that has been released from competitors’ systems. During 2009, we acquired a 60 MMcfd processing plant and residue pipeline facilities in western Oklahoma. Additionally, we completed a 40 MMcfd processing plant expansion in our Panhandle system. In March 2010, we entered into an agreement with a subsidiary of Range to construct and operate gas gathering and compression facilities servicing Range’s gas production in the Marcellus Shale formation. Please read “—Recent Developments—PVR Midstream Agreement with Range Resources.”

• Continue to grow coal reserve holdings through acquisitions and investments in our existing market areas. We expect to continue to add to our coal reserve holdings in Central Appalachia and the Illinois Basin in the future, but may consider the acquisition of reserves outside of these basins if the market and quality of the reserves satisfy our criteria. We have historically operated in Central Appalachia, our largest area of coal reserves, but we view the Illinois Basin as a growth area, both because of its proximity to power plants and because we expect future environmental regulations will require the scrubbing of most coals, and not just the higher sulfur coal that is typically found in this basin. We will consider acquisitions of coal reserves that are long-lived and that are of sufficient size to yield significant production or serve as a platform for complementary acquisitions.

• Mitigate commodity price exposure in our natural gas midstream segment. Our natural gas midstream operations consist of a mix of fee-based and margin-based services that, together with our hedging activities, are expected to generate relatively stable cash flows. During the quarter ended December 31, 2009, approximately 19% of the system throughput volumes in our natural gas midstream segment were gathered or processed under fee-based contracts. Our Marcellus Shale project with Range, when operational, will generate fee-based revenues from a combination of firm reservation charges and additional fees based on delivered volumes. Under fee-based contracts, we are not exposed directly to commodity price risk. The remainder of our system throughput volumes were gathered or processed under gas purchase/keep-whole arrangements and percentage-of-proceeds arrangements that are subject to commodity price risk. However, we expect to manage our exposure to commodity price risk by entering into hedging transactions. Based upon volumes as of December 31, 2009 and after giving effect to additional hedging agreements we entered into on March 29, 2010, we have entered into hedging agreements covering approximately58% and 56% of our commodity price-sensitive volumes in 2010 and 2011. We generally target hedging 50% to 60% of our commodity price-sensitive volumes covering a two-year period.

• Expand in areas that complement our coal royalty business. Coal infrastructure and timber projects typically involve long-lived, fee-based assets that generally produce predictable cash flows. We own a number of coal infrastructure facilities. We also have an equity interest in a coal handling joint venture, which is expected to provide development opportunities for coal-related infrastructure projects. We also own or control approximately 243,000 acres of forestlands in Appalachia, which primarily produce various hardwoods.

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Competitive Strengths

We believe we are well positioned to execute our business strategies successfully because of the following competitive strengths:

• Strategically located natural gas midstream assets. Our natural gas midstream assets are primarily located in Oklahoma and the panhandle of Texas, where natural gas reserves are generally characterized as being moderately declining and long-lived, and east Texas, where we believe natural gas exploration, development and production activities present significant opportunities to generate additional system throughput volumes. We expect that in the fourth quarter of 2010, we will put into operation the initial phase of gathering and compression facilities in the Marcellus Shale formation. Please read “—Recent Developments—PVR Midstream Agreement with Range Resources.” We believe that the Marcellus Shale is one of the most prolific natural gas formations in the United States and that our facilities in Lycoming County, Pennsylvania, once fully operational, will have substantial throughput volumes. We believe that our presence in these regions provides us with a competitive advantage in capturing new supplies of natural gas.

• High quality, diverse and strategically located coal reserves. Our coal reserves cover a range of sulfur and heat content and consist of both steam coal and metallurgical coal that are marketable to a diverse customer base. We believe that our higher sulfur Illinois Basin and Northern Appalachian coal will benefit from the ongoing installation of scrubbers at the power plants supplied by our coal. Our Appalachian coal reserves also include metallurgical grade coal, which commands a market premium compared to other grades of coal. In addition, our coal reserves are primarily located on or near major coal hauling railroads and inland waterways that serve Central Appalachia and the Illinois Basin. We believe that this geographic location of our coal reserves gives our lessees a transportation cost advantage to their domestic customers. We also believe that our Appalachian coal reserves are well situated to capitalize on the current favorable export market given their geographical proximity to East Coast ports, which provide access to transoceanic shipments.

• Coal royalty structure that maintains stable and predictable coal-related cash flows and limits exposure to coal mining operational and regulatory costs. Our coal leases, which are generally 10 to 15 years in duration, provide either for royalty rates equal to the higher of a fixed minimum rate or a percentage of the gross sales price received by our lessees for the coal they produce from our reserves or for a fixed royalty rate. This structure allows our earnings and cash flow to be stable and predictable in periods of low coal prices, while enabling us to benefit during periods of high coal prices. We also indirectly benefit from the long-term fixed price coal sales contracts our lessees have with their end users, which we believe are typically one to five years in duration, because the royalty rates our lessees pay to us will be fixed during the terms of those contracts. In addition, because we do not operate any mines, we do not directly bear any operational or regulatory costs, such as environmental or occupational health and safety costs and liabilities.

• Broad range of services and long-term contracts and relationships with active natural gas producers. Our natural gas supply strategy for our natural gas midstream segment is to establish long-term, integrated and comprehensive midstream services to our natural gas producers. We provide natural gas gathering, compression, dehydration, treating, processing and marketing and NGL fractionation services to natural gas producers. We

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believe our ability to provide this broad range of services gives us an advantage in competing for new supplies of natural gas because we can provide all of the services producers require to connect their natural gas quickly and efficiently. We have long-term contracts with many of the most active producers in the areas served by our natural gas midstream assets.

• Experienced coal mine operator lessees that have long-term relationships with a diverse group of major customers. We lease our coal reserves principally to lessees that we believe have substantial experience as coal mine operators, established reputations in the industry and strong relationships with a diverse group of major electric utilities, independent power producers and other commercial and industrial customers.

• Well positioned to pursue acquisition and expansion opportunities. We have a proven track record of successfully growing our business through organic growth projects and acquisitions of coal and natural resource properties and natural gas midstream assets. Since our initial public offering in October 2001, we have completed numerous accretive acquisitions with an aggregate purchase price of approximately $1.1 billion and expended approximately $188.9 million on expansion projects. We intend to use all of the net proceeds from this offering to repay a portion of the borrowings outstanding under our revolving credit facility, or Revolver, which will increase our borrowing capacity and provide us with greater flexibility to fund organic growth projects and pursue potential acquisitions as they arise.

• Senior management team with substantial industry experience. In connection with Penn Virginia’s ongoing reduction of its limited partner interest in PVG, our general partner has a new chief executive officer and chief financial officer who are not officers of Penn Virginia. William H. Shea, Jr., our new Chief Executive Officer, and Robert B. Wallace, our new Executive Vice President and Chief Financial Officer, bring to their new positions substantial industry experience, including from their prior service in such roles at Buckeye GP LLC, the general partner of a major midstream publicly traded partnership, Buckeye Partners, L.P. (NYSE: BPL). Please read “Management—Our Executive Officers and Directors.” At the same time, our operational management remains unchanged to provide continuity. Our Co-Presidents and Chief Operating Officers of our coal and midstream business segments will continue to operate their respective businesses. Members of our executive management team and the heads of our principal business segments have, on average, 30 years of experience in the industries in which we operate.

Recent Developments

Certain Estimated Unaudited Financial Measures for the Three Months Ended March 31, 2010

Our consolidated financial statements for the three months ended March 31, 2010 are not yet available. Based on preliminary information, we currently estimate that for the three months ended March 31, 2010, our operating income will be between $26.5 million and $28.5 million and our depreciation, depletion and amortization will be between $17.5 million and $18.0 million. The foregoing estimates are based on preliminary information relating to the first quarter of 2010. We caution that we have not completed our normal quarter-end closing and review processes for the first quarter of 2010, and that actual results could differ materially from the foregoing estimates.

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PVR Midstream Agreement with Range Resources

On March 10, 2010, a subsidiary of the operating company for our natural gas midstream segment, PVR Midstream LLC, or PVR Midstream, entered into an agreement with a subsidiary of Range to construct and operate gas gathering pipelines and compression facilities servicing Range’s Marcellus Shale natural gas production primarily in Lycoming County, Pennsylvania.

PVR Midstream and Range have agreed to an area of mutual interest, or AMI, that covers parts of Lycoming, Tioga and Bradford Counties in north central Pennsylvania, in which Range currently holds a substantial acreage position. Within this AMI, PVR Midstream will construct approximately 16 miles of 24- and 30-inch gathering trunklines, smaller-diameter field gathering lines and compression facilities required to gather Range’s production from the AMI. The gathering system is expected to have over 700 MMcfd of throughput capacity, and the initial phase is expected to become operational in the fourth quarter of 2010. The agreement provides Range significant firm gathering capacity in the system, and PVR Midstream will be compensated for the gathering and compression services provided to Range through a combination of firm reservation charges and additional fees based on delivered volumes, with no direct commodity exposure. Excess capacity on the system and the location within a core area of Marcellus Shale development may provide opportunities for PVR Midstream to develop additional revenues by providing gathering and compression services to other third-party producers in the area.

PVR Midstream’s total capital investment in this system is anticipated to range from $170 to $200 million and is expected to be expended between 2010 and 2015, with $35 to $40 million planned for 2010.

PVR Midstream Agreement to Construct Gas Gathering and Compression Facilities

On March 1, 2010, PVR Midstream entered into an agreement to construct and operate gas gathering pipelines and compression facilities servicing a private firm’s Marcellus Shale natural gas production in Wyoming County, Pennsylvania. Pursuant to the terms of the agreement, PVR Midstream will construct a 12-inch gathering pipeline and compression facilities with 25 MMcfd of throughput capacity and the potential for additional system extensions. PVR Midstream’s 2010 capital investment in this system is anticipated to range from $6 to $7 million, with potential future system extensions costing up to $10 million.

Sale by Penn Virginia of PVG Limited Partner Interests

On March 31, 2010, a subsidiary of Penn Virginia sold 10,000,000 common units of PVG that it beneficially owned in an underwritten public offering. PVG is the sole member of Penn Virginia Resource GP, LLC, our general partner, or PVR GP. As a result of this sale, Penn Virginia, which previously had beneficially owned 51.4% of the outstanding common units of PVG, now beneficially owns25.8% of PVG’s outstanding common units. This sale followed an earlier offering by a subsidiary of Penn Virginia in the third quarter of 2009, that reduced Penn Virginia’s beneficial ownership in PVG’s common units from 77.0% to 51.4%.

Changes in Our Governance

In connection with Penn Virginia’s reduction of its limited partner interest in PVG, we implemented certain changes in our partnership’s governance as a result of which the right to elect half the members of our general partner’s board of directors was given to our unaffiliated limited

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partners. On March 31, 2010, PVG and the Partnership entered into the Fifth Amended and Restated Limited Liability Company Agreement of PVR GP (as so amended, the “PVR GP LLC Agreement”), and PVR GP entered into Amendment No. 2 to the Third Amended and Restated Agreement of Limited Partnership of PVR (as amended, the “PVR Partnership Agreement”). Pursuant to the PVR GP LLC Agreement, the number of directors constituting the board of directors of PVR GP is six, consisting of three Class A directors and three Class B directors. The limited partners of PVR, other than PVG GP, PVG and their respective affiliates have the right to nominate and vote in the election of the three Class A directors to the board of directors of PVR GP. PVG has a right to appoint the three Class B directors to the board of directors of PVR GP. In the event of a tie vote, the board of directors of PVR GP has delegated to Penn Virginia the right to break the tie. This right is subject to termination under certain circumstances.

Changes in Our Management

In connection with Penn Virginia’s reduction of its limited partner interest in PVG, we implemented certain changes in management, as a result of which certain executive officers of Penn Virginia resigned as executive officers and directors of our general partner and were replaced in such positions by persons who are not executive officers of Penn Virginia. On March 8, 2010, A. James Dearlove resigned from his position as Chief Executive Officer of PVR GP, and on March 9, 2010, he resigned from his position as President and Chief Executive Officer of PVG GP. On March 8, 2010, the board of directors of PVR GP appointed William H. Shea, Jr. to the position of Chief Executive Officer of PVR GP, and on March 9, 2010 the board of directors of PVG GP appointed Mr. Shea to the positions of President and Chief Executive Officer of the PVG GP. Please read “Management—Our Executive Officers and Directors” for biographical information regarding Mr. Shea. On March 23, 2010, Frank A. Pici resigned from his position as Vice President and Chief Financial Officer of PVR GP, and his position as Vice President and Chief Financial Officer of PVG GP. On March 23, 2010, the board of directors of PVR GP appointed Robert B. Wallace to the position of Executive Vice President and Chief Financial Officer of PVR GP, and the board of directors of PVG appointed Mr. Wallace to the position of Executive Vice President and Chief Financial Officer of PVG GP. Please read “Management—Our Executive Officers and Directors” for biographical information regarding Mr. Wallace. On March 31, 2010, A. James Dearlove, Frank A. Pici and Nancy M. Snyder each resigned from their positions as directors on the board of directors of PVR GP. On March 31, 2010, Mr. Shea was appointed as a director on the board of directors of PVR GP and on the board of directors of PVG GP.

Prospective Matters

From time to time we engage in discussions with potential sellers regarding the possible purchase of coal or other natural resources properties or natural gas midstream assets. These potential acquisition opportunities consist of smaller acquisitions as well as larger acquisitions that could have a material impact on our capital structure and operating results. We cannot predict the likelihood of completing, or the timing of, any such acquisition.

Principal Executive Offices

Our principal executive offices are located at Four Radnor Corporate Center, Suite 200, 100 Matsonford Road, Radnor, Pennsylvania 19087. Our telephone number is (610) 687-8900.

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Summary Partnership Structure

Our general partner is Penn Virginia Resource GP, LLC, which is a wholly owned subsidiary of PVG. Penn Virginia beneficially owns an approximate 25.8% limited partner interest in PVG, as well as the non-economic general partner interest in PVG. PVG owns an approximate 37.1% limited partner interest in us, as well as 100% of our general partner, which owns a 2% general partner interest in us and all of our incentive distribution rights.

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our subsidiaries through PVR Finco LLC, which is the borrower under our Revolver. The following diagram depicts our and our affiliates’ simplified organizational and ownership structure as of April 12, 2010:

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The Offering

The following summary contains basic information about the notes and is not intended to be complete. For a more complete understanding of the notes, please refer to the section entitled “Description of Notes” beginning on pageS-111 in this prospectus supplement.

Issuers Penn Virginia Resource Partners, L.P. and Penn Virginia Resource Finance Corporation.

Penn Virginia Resource Finance Corporation is our wholly owned direct subsidiary that was incorporated in Delaware for the purpose of serving as a co-issuer of the notes. Penn Virginia Resource Finance Corporation has no material assets and does not conduct any operations. As a result, you should not expect Penn Virginia Resource Finance Corporation to participate in servicing the interest and principal obligations on the notes.

Securities Offered $300,000,000 aggregate principal amount of 8 ¹/4% Senior Notes due 2018.

Maturity April 15, 2018.

Interest Interest on the notes will accrue at a rate per annum equal to 8 ¹/4%.

Interest Payment Dates April 15 and October 15 of each year, beginning October 15, 2010.

Guarantees The notes will be fully and unconditionally guaranteed on a senior basis by our existing and future domestic restricted subsidiaries, subject to certain exceptions.

Ranking The notes and the related guarantees will be the unsecured senior obligations of us, Penn Virginia Resource Finance Corporation and the guarantors. Accordingly, they will rank:

• effectively subordinated to all of our, Penn Virginia Resource Finance Corporation’s and the guarantors’ existing and future secured debt, including debt under our Revolver, to the extent of the value of the assets securing such debt;

• structurally subordinated to all existing and future indebtedness and obligations of any of our present and future subsidiaries that do not guarantee the notes;

• equal in right of payment with our, Penn Virginia Resource Finance Corporation’s and the guarantors’ existing and future unsecured senior debt; and

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• senior to all of our, Penn Virginia Resource Finance Corporation’s and the guarantors’ existing and future debt that expressly provides that it is subordinated to the notes or the respective guarantees.

As of December 31, 2009, after giving effect to this offering and the application of the net proceeds therefrom, we would have had $628.1 million of debt outstanding, $328.1 million of which would have been secured indebtedness, and we would have had $470.3 million of remaining borrowing capacity under our Revolver (net of $1.6 million of outstanding letters of credit). As of December 31, 2009, our non-guarantor subsidiaries had no indebtedness outstanding. Please read “Capitalization.”

Optional Redemption Beginning on April 15, 2014, we may redeem some or all of the notes at the redemption prices listed under “Description of Notes—Optional Redemption” plus accrued and unpaid interest on the notes to the date of redemption.

Before April 15, 2014, we may redeem some or all of the notes at the “make-whole” redemption price set forth under “Description of Notes—Optional Redemption” plus accrued and unpaid interest on the notes to the date of redemption.

At any time prior to April 15, 2013 we may redeem up to 35% of the notes from the proceeds of certain sales of our equity securities at 108.250% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption. We may make that redemption only if, after the redemption, at least 65% of the aggregate principal amount of the notes remains outstanding and the redemption occurs within 60 days of the closing of the equity offering. Please read “Description of Notes—Optional Redemption.”

Change of Control Upon the occurrence of a change of control (as described under “Description of Notes—Repurchase at the Option of Holders—Change of Control”), we must offer to repurchase the notes at 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of repurchase.

Covenants The indenture governing the notes contains certain covenants limiting our ability and the ability of our restricted subsidiaries to, under certain circumstances:

• prepay subordinated indebtedness, pay distributions, redeem stock or make certain other restricted payments;

• make certain restricted investments;

• incur indebtedness;

• create liens on our assets to secure debt;

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• restrict dividends, distributions or other payments from subsidiaries to us;

• enter into transactions with affiliates;

• designate subsidiaries as unrestricted subsidiaries;

• sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries;

• use the proceeds of permitted sales of assets;

• effect a consolidation or merger; and

• change our line of business.

These covenants are subject to important exceptions and qualifications as described 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.

Use of Proceeds We will use all of the net proceeds of this offering to reduce outstanding indebtedness under our Revolver. Please read “Use of Proceeds” and “Underwriting—Conflicts of Interest.”

Risk Factors Please read “Risk Factors” beginning on pageS-17 and the other information in this prospectus supplement, the base prospectus and the documents incorporated by reference herein and therein for a discussion of factors you should carefully consider before making an investment in the notes.

Conflicts of Interest Affiliates of each of the underwriters, excluding Credit Suisse Securities (USA) LLC, are lenders or agents under our Revolver. As a result, this offering is being conducted in accordance with the applicable requirements of Financial Industry Regulatory Authority, or FINRA, Rule 5110 regarding the underwriting of securities of a company with a member that has a conflict of interest within the meaning of those rules. Credit Suisse Securities (USA) LLC has agreed to act as the qualified independent underwriter with respect to this offering. See “Underwriting — Conflicts of Interest.”

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Summary Historical Financial and Operating Data

The following tables present historical financial and operating data for the periods and the dates indicated. Our summary historical financial data as of and for the years ended December 31, 2009, 2008 and 2007 have been derived from our audited consolidated financial statements and the notes thereto.

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 “Selected Historical Financial and Operating Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Year Ended December 31,
	2009			2008			2007
	(in thousands, except per unit data)
Income Statement Data:
Revenues:
Natural gas midstream	$	504,789		$	720,002		$	433,174
Coal royalties		120,435			122,834			94,140
Coal services		7,332			7,355			7,252
Other		24,148			31,389			14,879
Total revenues		656,704			881,580			549,445
Expenses:
Cost of midstream gas purchased		406,583			612,530			343,293
Operating		35,111			32,677			20,964
Taxes other than income		4,794			4,258			3,036
General and administrative		30,168			26,906			22,915
Impairments		1,511			31,801			—
Depreciation, depletion and amortization		70,235			58,166			41,512
Total expenses		548,402			766,338			431,720
Operating income		108,302			115,242			117,725
Other income (expense):
Interest expense		(24,653	)		(24,672	)		(17,338	)
Other gain/(loss)		1,280			(2,907	)		1,804
Derivatives gain/(loss)		(19,714	)		16,837			(45,568	)
Net income	$	65,215		$	104,500		$	56,623
General partner’s interest in net income	$	24,962		$	23,715		$	14,224
Limited partners’ interest in net income	$	40,253		$	80,785		$	42,399
Basic and diluted net income per limited partner unit	$	0.76		$	1.63		$	0.92
Weighted average number of units outstanding, basic and diluted		51,799			49,495			46,103

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	Year Ended December 31,
	2009			2008			2007
	(in thousands, except ratios and operating data)
Balance Sheet Data (at period-end):
Net property, plant and equipment	$	900,844		$	895,119		$	731,282
Total assets		1,208,060			1,218,819			931,279
Total debt		620,100			568,100			411,714
Total liabilities		731,553			688,137			560,003
Partners’ capital		476,507			530,682			371,276
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	159,972		$	139,176		$	127,824
Investing activities		(79,530	)		(331,030	)		(224,182	)
Financing activities		(81,267	)		181,808			104,448
Distributions paid per limited partner unit	$	1.880		$	1.820		$	1.660
Other Financial Data:
Adjusted EBITDA(1)	$	184,777		$	169,092		$	147,572
Ratio of total debt to adjusted EBITDA(1)		3.4x			3.4x			2.8x
Ratio of earnings to fixed charges(2)		3.3x			4.9x			3.8x
Expansion capital expenditures	$	36,863		$	59,385		$	38,771
Other capital expenditures		8,584			14,700			9,851
Acquisitions		29,581			286,492			176,918
Operating Data:
System throughput volumes (MMcfd)		332			270			186
Gross processing margin ($/Mcf)	$	0.81		$	1.09		$	1.33
Coal owned or controlled (millions of tons)		829			827			818
Coal produced by lessees (millions of tons)		34.3			33.7			32.5
Average royalty revenues per ton ($/ton)	$	3.51		$	3.65		$	2.89
Average royalty revenues per ton by area ($/ton):
Central Appalachia	$	4.65		$	4.78		$	3.66
Northern Appalachia	$	1.83		$	1.84		$	1.53
Illinois Basin	$	2.63		$	2.28		$	1.97
San Juan Basin	$	2.12		$	2.06		$	2.00

(1) Adjusted EBITDA is a non-GAAP financial measure. Please see “—Non-GAAP Financial Measures” for a reconciliation of Adjusted EBITDA to net income and cash flows from operating activities.

(2) For purposes of determining the ratio of earnings to fixed charges, earnings are defined as the aggregate of income from continuing operations (before adjustment for equity earnings), fixed charges and distributions from equity investment, less capitalized interest. Fixed charges consist of interest expense (including amounts capitalized), amortization of debt costs and the portion of rental expense representing the interest factor. After giving effect to the issuance and sale of the notes in this offering and the application of the net proceeds therefrom to repay a portion of the borrowings outstanding under our Revolver as described under “Use of Proceeds,” our ratio of earnings to fixed charges would have been 2.1x for the year ended December 31, 2009.

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Non-GAAP Financial Measures

We include in this prospectus supplement the non-GAAP financial measures EBITDA and Adjusted EBITDA and provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP.

We define EBITDA as net income plus interest expense, provision for income taxes and depreciation, depletion and amortization, or DD&A, expenses. Adjusted EBITDA represents EBITDA plus impairments, plus an adjustment for equity earnings, net of distributions received, plus derivative losses (gains) included in net income, plus cash settlements of derivatives.

EBITDA and Adjusted EBITDA are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others to assess:

• the financial performance of our assets without regard to financing methods, capital structure, historical cost basis or the non-cash effects of derivative transactions;

• the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness, including the notes;

• our operating performance and return on capital as compared to those of other companies, without regard to financing methods or capital structure; and

• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDA and Adjusted EBITDA are also financial measurements that are reported to our banks and are used to compute our financial covenants under our Revolver. We have calculated Adjusted EBITDA herein in the same manner as the measure in such financial covenants in our Revolver defined as “EBITDA.” See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financial Condition—Covenant Compliance.” EBITDA and Adjusted EBITDA should not be considered alternatives to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Our EBITDA and Adjusted EBITDA may not be comparable to EBITDA, Adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate EBITDA and Adjusted EBITDA in the same manner as we do. EBITDA and Adjusted EBITDA have limitations as analytical tools, and you should not consider them in isolation from, or as a substitute for analysis of, our financial information prepared in accordance with GAAP. Some of these limitations are:

• they do not reflect cash outlays for capital expenditures or future contractual commitments;

• they do not reflect changes in, or cash requirements for, working capital;

• they do not reflect interest expense or the cash requirements necessary to service interest, or principal payments, on indebtedness;

• they do not reflect income tax expense or the cash necessary to pay income taxes;

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• they do not reflect available liquidity to Penn Virginia Resource Partners; and

• other entities, including entities in our industry, may not use such measures or may calculate such measures differently than as presented in this prospectus supplement, limiting their usefulness as comparative measures.

The following table presents a reconciliation of the non-GAAP financial measures of EBITDA and Adjusted EBITDA to the GAAP financial measures of net income and cash flows from operating activities on a historical basis for each of the periods indicated.

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Reconciliation of net income to Adjusted EBITDA:
Net income	$	65,215		$	104,500		$	56,623
Depreciation, depletion and amortization		70,235			58,166			41,512
Interest expense		24,653			24,672			17,338
EBITDA		160,103			187,338			115,473
Impairments		1,511			31,801			—
Equity earnings, net of distributions received		(2,537	)		(224	)		(285	)
Derivative losses (gains)		22,700			(11,357	)		50,163
Cash settlements of derivatives		3,000			(38,466	)		(17,779	)
Adjusted EBITDA	$	184,777		$	169,092		$	147,572
Reconciliation of cash flows from operating activities to Adjusted EBITDA:
Cash flows from operating activities	$	159,972		$	139,176		$	127,824
Changes in operating assets and liabilities		5,308			6,529			2,243
Non-cash interest expense		(4,391	)		(2,693	)		(678	)
Interest expense		24,653			24,672			17,338
Equity earnings, net of distributions received		2,537			224			285
Derivative gains (losses)		(22,700	)		11,357			(50,163	)
Cash settlements of derivatives		(3,000	)		38,466			17,779
Impairments		(1,511	)		(31,801	)		—
Other		(765	)		1,408			845
EBITDA		160,103			187,338			115,473
Impairments		1,511			31,801			—
Equity earnings, net of distributions received		(2,537	)		(224	)		(285	)
Derivative losses (gains)		22,700			(11,357	)		50,163
Cash settlements of derivatives		3,000			(38,466	)		(17,779	)
Adjusted EBITDA	$	184,777		$	169,092		$	147,572

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RISK FACTORS

This offering involves a high degree of risk. Before deciding to invest in the notes, you should consider carefully the risks and uncertainties described below with all of the other information included or incorporated by reference in this prospectus supplement, including the risk factors contained in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009. While these are the risks and uncertainties we believe are most important for you to consider, you should know that they are not the only risks or uncertainties facing us or which may adversely affect our business. If any of these risks actually occur, our business, financial condition or results of operations could be materially adversely affected.

Risks Related to Our Coal and Natural Resource Management Business

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

We depend on our lessees to effectively manage their operations on our properties. Our 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 our 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 us and could have a material adverse effect on our business, results of operations or financial condition.

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

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

• the inability to acquire necessary permits;

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• 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 our reserves could reduce our coal royalties revenues and could have a material adverse effect on our business, results of operations or financial condition. In addition, our coal royalties revenues are based upon sales of coal by our lessees to their customers. If our 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 our cash flow to be adversely affected and could have a material adverse effect on our business, results of operations or financial condition.

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

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

We depend on a limited number of primary operators for a significant portion of our coal royalties revenues and the loss of or reduction in production from any of our major lessees would reduce our coal royalties revenues.

We depend on a limited number of primary operators for a significant portion of our coal royalties revenues. In the year ended December 31, 2009, five primary operators, each with multiple leases, accounted for 61% of our coal royalties revenues and 11% of our total consolidated revenues. If any of these operators enters bankruptcy, decides to cease operations or significantly reduces its production, our coal royalties revenues would be reduced.

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A failure on the part of our lessees to make coal royalty payments could give us the right to terminate the lease, repossess the property or obtain liquidation damages and/or enforce payment obligations under the lease. If we repossessed any of our properties, we would seek to find a replacement lessee. We may not be able to find a replacement lessee and, if we find a replacement lessee, we 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 we enter 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 us 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.

Our coal business will be adversely affected if we are unable to replace or increase our coal reserves through acquisitions.

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

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

We do not control our lessees’ business operations. Our lessees’ customer supply contracts do not generally require our lessees to satisfy their obligations to their customers with coal mined from our reserves. Several factors may influence a lessee’s decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the lessee’s lease with us, mining conditions, transportation costs and availability and customer coal quality specifications. If a lessee satisfies its obligations to its customers with coal from properties we do not own or lease, production under our lease will decrease, and we 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 our properties.

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

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Our 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 our lessees to supply coal to their customers. Our lessees’ transportation providers may face difficulties in the future and impair the ability of our lessees to supply coal to their customers, thereby resulting in decreased coal royalties revenues to us.

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

One of our lessees has one mine operated by unionized employees. This mine was our third largest mine on the basis of coal production for the year ended December 31, 2009. All of our lessees could become increasingly unionized in the future. If some or all of our lessees’ non-unionized operations were to become unionized, it could adversely affect their productivity and increase the risk of work stoppages. In addition, our lessees’ operations may be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our lessees’ operations. Any further unionization of our lessees’ employees could adversely affect the stability of production from our coal reserves and reduce our coal royalties revenues.

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

Our estimates of our coal reserves may vary substantially from the actual amounts of coal our lessees may be able to economically recover. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our 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

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

Actual production, revenues and expenditures with respect to our 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 us.

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

According to the U.S. Department of Energy, domestic electric power generation accounted for approximately 89% 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. We believe that most

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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. Please read “Business—Government Regulation and Environmental Matters—Coal and Natural Resource Management Segment—Air Emissions.”

Extensive environmental laws and regulations affecting electric power generators could have corresponding effects on the ability of our lessees to sell the coal they produce and thereby reduce our 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 our 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 our lessees produce and thereby reducing our coal royalties revenues. Please read “Business—Government Regulation and Environmental Matters—Coal and Natural Resource Management Segment—Air Emissions.”

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 our 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 the last several years to reduce greenhouse gas emissions in the United States and further proposals or amendments are likely to be offered in the future. In anticipation of the endangerment finding of the Environmental Protection Agency, or the EPA, regarding greenhouse gas emissions (which was finalized in December 2009), the agency proposed two sets of rules regarding possible future regulation of greenhouse gas emissions under the CAA. 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. Also, in 2009, the EPA announced that it will consider whether to reclassify byproducts of coal combustion as hazardous waste. It is not possible to determine with certainty the potential permitting requirements or performance standards that may be imposed on the disposal of coal combustion byproducts, or CCB, by future regulations or lawsuits. 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. Please read “Business—Governmental Regulation and Environmental Matters—Coal and Natural Resource Management Segment—Air Emissions.”

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

Mine operators, including our lessees, must obtain numerous permits and approvals that impose strict conditions and obligations relating to various environmental and safety matters in

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connection with coal mining. The permitting rules are complex and can change over time. For example, on March 26, 2010, the EPA announced a proposal to exercise its Section 404(c) “veto” power with regard to the Spruce No. 1 Surface Mine in West Virginia, which was previously permitted in 2007. This would be the first time the EPA’s Section 404(c) “veto” power would be applied to a previously permitted project. Moreover, on April 1, 2010, the EPA issued interim final guidance substantially revising the environmental review of Section 402 and Section 404 permits by state and federal agencies. As an example of the significance of this guidance, the EPA also published on April 1, 2010 a proposed determination to prohibit, restrict or deny a permit issued under Section 404 to Mingo Logan Coal Company for the discharge of dredged fill in connection with the construction of carious fills and sedimentation ponds. Of course, this guidance has just been issued and it remains to be seen how it will be applied by the EPA and whether it will be subject to judicial challenge by affected states or private parties. These initiatives have extended the time required to obtain permits for coal mining and we anticipate further delays in obtaining permits and that the costs associated with obtaining and complying with those permits will increase substantially. It is possible that some projects may not be able to obtain these permits because of the manner in which these rules are being interpreted and applied. Limitations on our 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 our coal royalties revenues. Please read “Business—Government Regulation and Environmental Matters—Coal and Natural Resource Management Segment—Mining Permits and Approvals.”

Uncertainty over the precise parameters of the Clean Water Act’s regulatory scope and a recent federal district court decision and recently enacted EPA guidance may adversely impact our 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, our lessees often need to obtain government approvals, including Section 404 of the Clean Water Act, or the CWA, permits to construct valley fills and sediment control ponds. Ongoing uncertainty over which waters are subject to the CWA may adversely impact our 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 our lessees for the Republic No. 2 Mine and enjoined our 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 and the application of the new EPA guidance may lead to rulings invalidating other permits, additional challenges to various permits and additional delays and costs in applying for and obtaining new permits, and may result in many of such permits becoming unavailable, all of which could ultimately have an adverse effect on our coal royalties revenues. Please read “Business—Government Regulation and Environmental Matters—Coal and Natural Resource Management Segment—Clean Water Act,” for more information about the litigation described above.

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

Our 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. Our lessees are required to prepare and present to

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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. 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. Moreover, workplace accidents, such as the April 5, 2010, Upper Big Branch Mine, West Virginia incident, may result in more stringent enforcement as well as the development of new laws and regulations. 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 our lessees’ mining operations, either through direct impacts such as new requirements impacting our 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 our coal royalties revenues. Please read “Business—Government Regulation and Environmental Matters—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, we do not believe violations by our 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. Our lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their operations. If our 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, our coal royalties revenues, could be adversely affected.

Risks Related to Our Natural Gas Midstream Business

The success of our natural gas midstream business depends upon our ability to find and contract for new sources of natural gas supply.

In order to maintain or increase system throughput levels on our gathering systems and asset utilization rates at our processing plants, we must contract for new natural gas supplies. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include the level of drilling activity creating new gas supply near our gathering systems, our success in contracting for existing natural gas supplies that are not committed to other systems and our ability to expand and increase the capacity of our systems. We 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. We have no control over the level of drilling activity in our areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, we have 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.

Our natural gas midstream assets, including our gathering systems and processing plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. Our cash flows associated with these systems will decline unless we are able to secure new supplies

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of natural gas by connecting additional production to these systems. A material decrease in natural gas production in our areas of operation, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas we handle, which would reduce our revenues and operating income. In addition, our future growth will depend, in part, upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our currently connected supplies.

We typically do not obtain independent evaluations of natural gas reserves dedicated to our gathering systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate.

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

The NGL products we produce, including ethane, propane, normal butane, isobutane and natural gasoline, have a variety of applications, including as heating fuels, petrochemical 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 we handle or reduce the fees we charge for our services. Any reduced demand for our NGL products could adversely affect demand for the services we provide as well as NGL prices, which would negatively impact our results of operations and financial condition.

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

We are subject to significant risks due to fluctuations in natural gas commodity prices. During 2009, we generated a majority of our gross margin from two types of contractual arrangements under which our margin is exposed to increases and decreases in the price of natural gas and NGLs—gas purchase/keep-whole and percentage-of-proceeds arrangements. Please read “Business—Contracts—Natural Gas Midstream Segment.”

Virtually all of the system throughput volumes in our Crescent System and Hamlin System are processed under percentage-of-proceeds arrangements. The system throughput volumes in our Panhandle System are processed primarily under either percentage-of proceeds or gas purchase/keep-whole arrangements. Under both types of arrangements, we provide gathering and processing services for natural gas received. Under percentage-of-proceeds arrangements, we generally sell the NGLs produced from the processing operations and the remaining residue gas at market prices and remit to the producers an agreed upon percentage of the proceeds based on either an index price or the price actually received for the gas and NGLs. Under these arrangements, revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the

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price of natural gas or NGLs could have a material adverse effect on our business, results of operations or financial condition. Under gas purchase/keep-whole arrangements, we generally buy natural gas from producers based upon an index price and then sell 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 our business, results of operations or financial condition.

In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. The markets and prices for residue gas and NGLs depend upon factors beyond our 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 state of the global economy, including financial and credit markets, and its impact 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;

• 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 our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing the risks of being unable to effectively integrate these new operations.

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing operations. Readily available access to debt and equity capital and credit availability has been and continues to be critical factors in our ability to grow. The current state of the global economy, including financial markets, and the consequential adverse effect on credit availability is adversely impacting our access to new capital and credit availability. Depending on the longevity and ultimate severity of this downturn, our ability to make acquisitions may be significantly adversely affected. In the event we complete acquisitions, we may encounter difficulties integrating these acquisitions with our 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, we 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 our cash distributions to our unitholders, and because of the capital used to complete such acquisitions, or the debt incurred, our results of operations may change significantly.

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

One of the ways we may grow our 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 our control and require the expenditure of significant amounts of capital. Our access to such capital is currently adversely impacted by the state of the global economy, including financial and credit markets. If we do undertake these projects, they may not be completed on schedule, or at all, or at the anticipated cost. Moreover, our 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 our estimates. Generally, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we 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, including the facilities we are constructing in the Marcellus Shale formation in north central Pennsylvania under our contract with Range, may not be able to attract enough natural gas to achieve our expected investment return, which could have a material adverse effect on our business, results of operations or financial condition.

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

The construction of additions to our existing gathering assets may require us to obtain new rights-of-way before constructing new pipelines. We may be unable to obtain rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us 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 our cash flows could be reduced.

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

We are subject to risk of loss resulting from nonpayment or nonperformance by our natural gas midstream customers. We depend on a limited number of customers for a significant portion of our natural gas midstream revenues. In 2009, 21%, 15% and 10% of our natural gas midstream segment revenues and 17%, 11% and 8% of our total consolidated revenues resulted from three of our natural gas midstream customers, Conoco, Inc., Tenaska Marketing Ventures and ONEOK Energy Marketing. Any nonpayment or nonperformance by our natural gas midstream segment customers would reduce our cash flows.

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

We are 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 our natural gas midstream facilities. Similarly, if additional shippers begin transporting

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volumes of residue gas and NGLs on interconnecting pipelines, our allocations in these pipelines could be reduced. Any reduction in volumes gathered and processed in our facilities could adversely affect our revenues and cash flows.

Natural gas derivative transactions may limit our potential gains and involve other risks.

In order to manage our exposure to price risks in the marketing of our natural gas and NGLs, we periodically enter into condensate, natural gas and NGL 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. However, in connection with acquisitions, sometimes our hedges are for longer periods. These hedging transactions may limit our 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, we have entered into derivative transactions related to only a portion of our condensate, natural gas and NGL volumes. As a result, we will continue to have direct commodity price risk with respect to the unhedged portion of these volumes. In trying to maintain an appropriate balance, we 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 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 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 we engage 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 us to engage in a derivative transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge transaction.

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

Our 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;

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• 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 our related operations. Our 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 our business, results of operations or financial condition. We are not fully insured against all risks incident to our natural gas midstream business. We do not have property insurance on all of our underground pipeline systems that would cover damage to the pipelines. We are 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 our business, results of operations or financial condition.

Federal, state or local regulatory measures could adversely affect our natural gas midstream business.

We own and operate an 11-mile interstate natural gas pipeline that, pursuant to the Natural Gas Act, or NGA, is subject to the jurisdiction of the Federal Energy Regulatory Commission, or the FERC. The FERC has granted us 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 we will have to comply with the filing requirements if our 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.

Our 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 our gathering business and the market for our services. For a more detailed discussion of how regulatory measures affect our natural gas gathering business, please read “Business—Government Regulation and Environmental Matters—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.

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

Many of the operations and activities of our 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 our facilities and the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or the prior owners of our natural gas midstream business or locations to which we or they have sent wastes for disposal. These laws and regulations can restrict or impact our business activities in many ways, including restricting the manner in which we dispose 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

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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 our natural gas midstream business due to our handling of natural gas and other petroleum products, air emissions related to our natural gas midstream operations, historical industry operations, waste disposal practices and the use by the prior owners of our natural gas midstream business of natural gas flow meters containing mercury. For example, an accidental release from one of our pipelines or processing facilities could subject us 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 possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may incur material environmental costs and liabilities. Insurance may not provide sufficient coverage in the event an environmental claim is made. Please read “Business—Government Regulation and Environmental Matters—Natural Gas Midstream Segment.”

Federal and/or state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the exploitation of the Marcellus Shale formation, which may adversely affect the supply of natural gas to our planned Marcellus Shale system.

The United States Congress is currently considering legislation to amend the Safe Drinking Water Act to eliminate an existing exemption for hydraulic fracturing activities. Similar legislation is under consideration in various states, including New York, and state environmental agencies may impose new requirements on these practices under existing laws. Hydraulic fracturing involves the injection of water, sand and additives under pressure into rock formation to stimulate natural gas production. Range and other producers who are active in the Marcellus Shale formation use hydraulic fracturing to produce commercial quantities of natural gas and oil from shale formations such as the Marcellus Shale. Depending on the legislation that may ultimately be enacted or the regulations that may be adopted at the federal and/or state levels, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements, which could include public review and possibly even rights to challenge permitting. Individually or collectively, such new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing. In this case, the ability of such producers to supply our planned Marcellus Shale system with natural gas may be diminished, which could, in turn, adversely affect our revenues and our ability to service the notes.

Risks Related to the Notes Offering

We distribute all of our available cash to our unitholders and are not required to accumulate cash for the purpose of meeting our future obligations to our noteholders, which may limit the cash available to make payments on the notes.

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Subject to the limitations on restricted payments contained in our Revolver and the indenture governing the notes, we distribute all of our “available cash” each quarter to our limited partners and our general partner. “Available cash” is defined in our partnership agreement, and it generally means, for each fiscal quarter:

• all cash on hand at the end of the quarter;

• less the amount of cash that our general partner determines in its reasonable discretion is necessary or appropriate to:

— provide for the proper conduct of our business;

— comply with applicable law, any of our debt instruments, or other agreements; or

— provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

• plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our Revolver and in all cases are used solely for working capital purposes or to pay distributions to partners.

As a result, we do not expect to accumulate significant amounts of cash. Depending on the timing and amount of our cash distributions, these distributions could significantly reduce the cash available to us in subsequent periods to make payments on the notes.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

We are a holding company, and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than our interest in our operating subsidiaries. As a result, our ability to make required payments on the notes depends on the performance of our operating subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, our Revolver and applicable state partnership laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount at maturity of the notes, or to repurchase the notes upon the occurrence of a change of control, we may be required to adopt one or more alternatives, such as a refinancing of the notes or a sale of assets. We may not be able to refinance the notes or sell assets on acceptable terms, or at all.

Our substantial debt could adversely affect our financial condition and prevent us from fulfilling our obligations under the notes.

We currently have, and following this offering will continue to have, a substantial amount of indebtedness. As of December 31, 2009, after giving effect to this offering and the application of the net proceeds therefrom, we would have had total debt of approximately $628.1 million, which consisted of $300.0 million of notes offered hereby and $328.1 million of borrowings under our Revolver, and we would have had $470.3 million of remaining borrowing capacity under our Revolver (net of $1.6 million of outstanding letters of credit). Please read “Capitalization.” In addition, the $292.0 million used to repay borrowings under our Revolver with the net proceeds from this offering may be reborrowed by us and we may also incur additional indebtedness in the future. Specifically,

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our high level of debt could have important consequences to the holders of the notes, including the following:

• making it more difficult for us to satisfy our obligations with respect to the notes and our other debt;

• limiting our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions or other general corporate requirements;

• requiring a substantial portion of our cash flows to be dedicated to debt service payments instead of other purposes;

• increasing our vulnerability to general adverse economic and industry conditions;

• limiting our flexibility in planning for and reacting to changes in the industries in which we compete;

• placing us at a disadvantage compared to other, less leveraged competitors; and

• increasing our cost of borrowing.

Despite our and our subsidiaries’ current level of indebtedness, we may still be able to incur substantially more indebtedness. This could further exacerbate the risks associated with our substantial indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of the indenture governing the notes offered hereby do not prohibit us or our subsidiaries from doing so. If we incur any additional indebtedness that ranks equally with the notes and the guarantees, the holders of that indebtedness will be entitled to share ratably with the holders of the notes offered hereby and the related guarantees in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us. This may have the effect of reducing the amount of proceeds paid to you. If new indebtedness is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

We may be unable to service our indebtedness, including the notes.

Our ability to make scheduled payments on and to refinance our indebtedness, including the notes and our Revolver, which matures in December 2011, depends on and is subject to our financial and operating performance, which in turn is affected by general and regional economic, financial, competitive, business and other factors beyond our control, including the availability of financing in the banking and capital markets. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us in an amount sufficient to enable us to service our debt, including the notes, to refinance our debt or to fund our other liquidity needs. If we are unable to meet our debt obligations or to fund our other liquidity needs, we will need to restructure or refinance all or a portion of our debt, including the notes, which could cause us to default on our debt obligations and impair our liquidity. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants which could further restrict our business operations.

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The notes and the guarantees will be unsecured and effectively subordinated to our and the guarantors’ existing and future secured indebtedness.

The notes and the guarantees will be general unsecured obligations ranking effectively junior in right of payment to all of our existing and future secured indebtedness and that of each guarantor (to the extent of the value of the assets securing such indebtedness). Additionally, the indenture governing the notes permits us to incur additional secured indebtedness in the future. As of December 31, 2009, after giving effect to this offering and the application of the net proceeds therefrom, we would have had $628.1 million of debt outstanding, $328.1 million of which would have been secured indebtedness under our Revolver, and we would have had $470.3 million of remaining borrowing capacity under our Revolver (net of $1.6 million of outstanding letters of credit). In the event that we or a guarantor is declared bankrupt, becomes insolvent or is liquidated or reorganized, any indebtedness that ranks ahead of the notes and the guarantees will be entitled to be paid in full from our assets or the assets of the guarantor, as applicable, before any payment may be made with respect to the notes or the affected guarantees. Holders of the notes will participate ratably with all holders of our unsecured indebtedness that is deemed to be of the same class as the notes, and potentially with all of our other general creditors, based upon the respective amounts owed to each holder or creditor, in our remaining assets. In any of the foregoing events or in the event of the liquidation, dissolution, reorganization, bankruptcy or similar proceeding of the business of a non-guarantor subsidiary, as described below, we cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of the notes may receive less, ratably, than holders of secured indebtedness.

The notes will be structurally subordinated to all liabilities of our non-guarantor subsidiaries.

The notes are structurally subordinated to the indebtedness and other liabilities of our subsidiaries that are not guaranteeing the notes. These non-guarantor subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due pursuant to the notes, or to make any funds available therefor, whether by loans, distributions or other payments. Any right that we or the subsidiary guarantors have to receive any assets of any of the non-guarantor subsidiaries upon the liquidation or reorganization of those subsidiaries, and the consequent rights of holders of notes to realize proceeds from the sale of any of those subsidiaries’ assets, will be effectively subordinated to the claims of those subsidiaries’ creditors, including trade creditors and holders of preferred equity interests of those subsidiaries. Accordingly, in the event of a bankruptcy, liquidation or reorganization of any of our non-guarantor subsidiaries, these non-guarantor subsidiaries will pay the holders of their debts, holders of preferred equity interests and their trade creditors before they will be able to distribute any of their assets to us.

Our Revolver and the indenture governing the notes impose significant operating and financial restrictions on us and our subsidiaries, which may prevent us from capitalizing on business opportunities.

Our Revolver and the indenture governing the notes impose significant operating and financial restrictions on us. Our ability to borrow under our Revolver is subject to compliance with certain financial covenants, including leverage and interest coverage ratios. These restrictions will limit our ability, among other things, to:

• incur additional indebtedness or enter into sale and leaseback obligations;

• make certain distributions or repurchase our equity interests;

• make certain capital expenditures;

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• make certain investments or other restricted payments;

• place restrictions on the ability of subsidiaries to pay dividends or make other payments to us;

• engage in transactions with affiliates;

• sell certain assets or merge with or into other companies;

• guarantee indebtedness; and

• create liens.

Please read “Description of Certain Indebtedness.” As a result of these covenants and restrictions, we will be limited in how we conduct our business and we may be unable to raise additional debt or equity financing to compete effectively or to take advantage of new business opportunities. The terms of any future indebtedness we may incur could include more restrictive covenants. We cannot assure you that we will be able to maintain compliance with these covenants in the future and, if we fail to do so, that we will be able to obtain waivers from the lenders and/or amend the covenants. A breach of any of these covenants or other provisions in our debt agreements could result in an event of default, which if not cured or waived, could result in such debt becoming immediately due and payable. This, in turn, could cause our other debt to become due and payable as a result of cross-acceleration provisions contained in the agreements governing such other debt. In the event that some or all of our debt is accelerated and becomes immediately due and payable or we are unable to refinance our Revolver at its maturity, we may not have the funds to repay, or the ability to refinance, such debt.

Federal and state statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from subsidiary guarantors.

Under the federal bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee of the notes could be voided, or claims in respect of a guarantee could be subordinated to all other debts of that subsidiary guarantor, if, among other things, the subsidiary guarantor, at the time it incurred the debt evidenced by its guarantee:

• received less than reasonably equivalent value or fair consideration for the incurrence of such guarantee;

• was insolvent or rendered insolvent by reason of such incurrence;

• was engaged in a business or transaction for which the subsidiary guarantor’s remaining assets constituted unreasonably small capital; or

• intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they mature.

In addition, any payment by that subsidiary guarantor pursuant to its guarantee could be voided and required to be returned to the subsidiary guarantor, or to a fund for the benefit of our creditors or the creditors of the guarantor.

The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a subsidiary guarantor would be considered insolvent if:

• the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;

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• if the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

• it could not pay its debts as they become due.

On the basis of historical financial information, recent operating history and other factors, we believe that each subsidiary guarantor, after giving effect to its guarantee of the notes, will not be insolvent, will not have unreasonably small capital for the business in which it is engaged and will not have incurred debts beyond its ability to pay such debts as they mature. We cannot assure you, however, as to what standard a court would apply in making these determinations or that a court would agree with our conclusions in this regard.

We may not have the funds necessary to finance the repurchase of the notes in connection with a change of control offer required by the indenture.

Upon the occurrence of specific kinds of change of control events, the indenture governing the notes requires us to make an offer to repurchase all outstanding notes at 101% of the principal amount thereof, plus accrued and unpaid interest (and additional interest, if any) to the date of repurchase. However, it is possible that we will not have sufficient funds, or the ability to raise sufficient funds, at the time of the change of control to make the required repurchase of the notes. In addition, restrictions under our Revolver may not allow us to repurchase the notes upon a change of control. If we could not refinance our Revolver or otherwise obtain a waiver from the holders of such debt, we would be prohibited from repurchasing the notes, which would constitute an event of default under the indenture. In addition, certain important corporate events, such as leveraged recapitalizations that would increase the level of our indebtedness, would not constitute a “Change of Control” under the indenture. Because the definition of change of control under our Revolver differs from that under the indenture governing the notes, there may be a change of control and resulting default under our Revolver at a time when no change of control has occurred under the indenture governing the notes. Please read “Description of Notes—Repurchase at the Option of Holders—Change of Control.”

There is no assurance that any active trading market will develop for the notes.

There is no established public market for the notes. Although the underwriters have advised us that they intend to make a market in the notes, they are not obligated to do so, and they may discontinue their market-making activities at anytime without notice. Therefore, we cannot assure you that an active market for the notes will develop or, if developed, that such a market will continue. In addition, subsequent to their initial issuance, the notes may trade at a discount from their initial offering price, depending upon prevailing interest rates, the market for similar notes, our performance and other factors.

We do not intend to apply for listing of the notes on any securities exchange or stock market. The liquidity of any market for the notes will depend on a number of factors, including:

• the number of holders of notes;

• our operating performance and financial condition;

• the market for similar securities;

• the interest of securities dealers in making a market in the notes; and

• prevailing interest rates.

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Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of these securities. We cannot assure you that the market for the notes will be free from similar disruptions. Any such disruptions could have an adverse effect on holders of the notes.

Our general partner will not have any liability for the notes.

The indenture governing the notes provides that our general partner will have no liability for our obligations under the notes. Accordingly, if we and the subsidiary guarantors are unable to make payments on the notes, you will not be able to recover against our general partner.

Risks Related to Our Structure

Our tax treatment depends on our status as a partnership for federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available to service our debt would be substantially reduced.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, if our view is incorrect, or if there is a change in our business (or a change in current law), we could be treated as a corporation for federal income tax purposes or otherwise subject to taxation as an entity.

If we were treated as a corporation for federal income tax purposes for any taxable year for which the statute of limitations remains open or for any future taxable year, we would pay federal income tax on our taxable income for such years at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flow and could materially and adversely affect our ability to make payments on our debt, including on the notes.

The tax treatment of publicly traded partnerships could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Specifically, the present federal income tax treatment of publicly traded partnerships, including us, may be modified by administrative, legislative or judicial interpretation at any time. For example, at the federal level, legislation was proposed in 2007 that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation, as proposed, would not apply to us, it could be amended prior to enactment in a manner that does apply to us. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact our ability to make payment on the notes.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are subject to an entity-level tax on the portion of our income that is generated in Texas. Specifically, the Texas margin tax is imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of such a tax on us by Texas and other states will reduce the cash available for payments on the notes.

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As a result of Penn Virginia’s reduction and possible future divestiture of its remaining partner interests in PVG, our business relationships with Penn Virginia may change.

As a result of the sale by a subsidiary of Penn Virginia in a public offering on March 31, 2010, Penn Virginia reduced its beneficial ownership in PVG, which owns the entire equity interest in our general partner, from a majority to approximately25.8% of PVG’s common units. Penn Virginia may sell all or part of its remaining partner interests in PVG without PVG’s or our consent or the consent of PVG’s or our unitholders.

As a result of Penn Virginia’s reduction and possible future divestiture of its partner interests in PVG, our business relationships with Penn Virginia may change. We may in the future collaborate less frequently than in the past with Penn Virginia on acquisitions and other transactions that have been mutually beneficial to our respective companies. We may in the future not be in a position to rely on Penn Virginia’s management team and corporate infrastructure as we have in the past. As a result, we may have less access than in the past to Penn Virginia’s energy industry expertise and relationships and corporate support services. These changes could affect our strategic and operational objectives, our results of operations and cash available for distribution.

Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner has limited fiduciary duties to us and our unitholders, which may permit it to favor its own interests to the detriment of us and our unitholders.

Penn Virginia and its affiliates, including PVG, own an approximate 37% limited partner interest in us. PVG owns our general partner. Penn Virginia owns an approximate25.8% limited partner interest and the non-economic general partner interest in PVG. Conflicts of interest may arise between our general partner and its affiliates (including Penn Virginia and PVG), on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

• Our general partner is allowed to take into account the interests of parties other than us, such as Penn Virginia and PVG, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.

• Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available to be distributed to our unitholders.

• Our general partner controls the enforcement of obligations owed to us by it and its affiliates.

• Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

• Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

• Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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The fiduciary duties of our general partner’s officers and directors may conflict with those of PVG’s general partner, and our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to us.

Our general partner’s officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our unitholders and the owner of our general partner, PVG. However, PVG’s general partner has fiduciary duties to manage the business of PVG in a manner beneficial to PVG and its unitholders, including Penn Virginia. Consequently, the directors of our general partner may encounter situations in which their fiduciary obligations to us on the one hand, and PVG, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

In addition, our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to unitholders. By purchasing our units, our unitholders are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

We may face conflicts of interest in the allocation of administrative time among Penn Virginia’s business, PVG’s business and our business.

Our general partner shares administrative personnel with Penn Virginia and PVG’s general partner to operate Penn Virginia’s business, PVG’s business and our business. While our chief executive officer and chief financial officer are no longer executives of Penn Virginia, our Vice President, Chief Administrative Officer and General Counsel is an executive officer of Penn Virginia, and certain other officers and employees of Penn Virginia continue to provide services to our general partner. These officers and employees face conflicts regarding the allocation of their time, which may adversely affect our results of operations, cash flows and financial condition. We may in the future enter into a transition services agreement with Penn Virginia regarding the allocation of administrative time and support services. We cannot provide any assurance that any such agreement will be on terms as favorable to us as our existing arrangements.

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $292.0 million from this offering, after deducting the underwriters’ discounts and commissions and estimated offering expenses.

We intend to use all of the net proceeds from this offering to repay a portion of the borrowings outstanding under our Revolver. Affiliates of each of the underwriters, excluding the qualified independent underwriter, are lenders or agents under our Revolver and, accordingly, will receive a substantial portion of the net proceeds from this offering. Please read “Underwriting —Conflicts of Interest.” We may reborrow any amounts repaid under our Revolver.

The amount of borrowings outstanding under our Revolver is $616.1 million as ofApril 12, 2010. In 2009, we had net borrowings of $52.0 million under the Revolver. The proceeds of these borrowings were used primarily for expansion capital projects and the acquisition of our interest in the Sweetwater, Oklahoma gas processing plant.

Our Revolver matures on December 11, 2011. The interest rate under the Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 1.25% if we select the base rate borrowing option under the Revolver or at a rate derived from the London Interbank Offered Rate, or LIBOR, plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the Revolver during 2009 was approximately 2.7%.

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CAPITALIZATION

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

• an historical basis; and

• an as adjusted basis to give effect to this offering and the application of the net proceeds therefrom as set forth in “Use of Proceeds.”

The actual information in the table is derived from, and you should read the information below in conjunction with, our historical financial statements and our pro forma financial statements and the accompanying notes thereto 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.”

	As of December 31, 2009
	Historical			As Adjusted
				(unaudited)
	(in thousands)
Cash and cash equivalents	$	8,659		$	8,659
Long-term debt:
Revolving credit facility(1)	$	620,100		$	328,100
8 1/4% senior notes due 2018		—			300,000
Total debt		620,100			628,100
Less: Current maturities		—			—
Total long-term debt		620,100			628,100
Partners’ capital:
Common units, 51,798,895 issued and outstanding		471,068			471,068
General partner interest		6,834			6,834
Accumulated other comprehensive income		(1,395	)		(1,395	)
Total partners’ capital		476,507			476,507
Total capitalization	$	1,096,607		$	1,104,607

(1) As of April 12, 2010, after giving effect to this offering and the application of the net proceeds therefrom as set forth in “Use of Proceeds,” we would have had outstanding borrowings of approximately $324.1 million under our Revolver, and we would have had $470.3 million of remaining borrowing capacity under our Revolver (net of $1.6 million of outstanding letters of credit).

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

The following tables present historical financial and operating data for the periods and the dates indicated. Our selected historical financial data as of and for the years ended December 31, 2009, 2008, 2007, 2006 and 2005 have been derived from our audited consolidated financial statements and the notes thereto.

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.”

	Year Ended December 31,
	2009			2008			2007			2006			2005
	(audited)
	(in thousands, except per unit data)
Income Statement Data:
Revenues:
Natural gas midstream	$	504,789		$	720,002		$	433,174		$	402,715		$	348,657
Coal royalties		120,435			122,834			94,140			98,163			82,725
Coal services		7,332			7,355			7,252			5,864			5,230
Other		24,148			31,389			14,879			11,149			9,736
Total revenues		656,704			881,580			549,445			517,891			446,348
Expenses:
Cost of midstream gas purchased		406,583			612,530			343,293			334,594			303,912
Operating		35,111			32,677			20,964			20,003			15,102
Taxes other than income		4,794			4,258			3,036			2,354			2,397
General and administrative		30,168			26,906			22,915			20,627			16,219
Impairments		1,511			31,801			—			—			—
Depreciation, depletion and amortization		70,235			58,166			41,512			37,493			30,628
Total expenses		548,402			766,338			431,720			415,071			368,258
Operating income		108,302			115,242			117,725			102,820			78,090
Other income (expense):
Interest expense		(24,653	)		(24,672	)		(17,338	)		(18,821	)		(14,054	)
Other gain/(loss)		1,280			(2,907	)		1,804			1,189			1,149
Derivatives gain/(loss)		(19,714	)		16,837			(45,568	)		(11,260	)		(14,024	)
Net income	$	65,215		$	104,500		$	56,623		$	73,928		$	51,161
General partner’s interest in net income	$	24,962		$	23,715		$	14,224		$	7,194		$	2,518
Limited partners’ interest in net income	$	40,253		$	80,785		$	42,399		$	66,734		$	48,643
Basic and diluted net income per limited partner unit	$	0.76		$	1.63		$	0.92		$	1.59		$	1.21
Weighted average number of units outstanding, basic and diluted		51,799			49,495			46,103			42,014			40,302
Balance Sheet Data (at period-end):
Net property, plant and equipment	$	900,844		$	895,119		$	731,282		$	556,513		$	458,782
Total assets		1,208,060			1,218,819			931,279			714,023			657,879
Total debt		620,100			568,100			411,714			218,046			254,954
Total liabilities		731,553			688,137			560,003			311,843			373,920
Partners’ capital		476,507			530,682			371,276			402,180			283,959
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	159,972		$	139,176		$	127,824		$	107,344		$	93,712
Investing activities		(79,530	)		(331,030	)		(224,182	)		(129,676	)		(303,621	)
Financing activities		(81,267	)		181,808			104,448			10,579			212,105
Distributions paid per limited partner unit		1.8800			1.8200			1.6600			1.4750			1.2413

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	Year Ended December 31,
	2009		2008		2007		2006		2005
	(audited)
	(in thousands, except ratios and operating data)
Other Financial Data:
Adjusted EBITDA(1)	$	184,777	$	169,092	$	147,572	$	125,336	$	105,396
Ratio of total debt to adjusted EBITDA(1)		3.4x		3.4x		2.8x		1.7x		2.4x
Ratio of earnings to fixed charges(2)		3.3x		4.9x		3.8x		4.8x		4.7x
Expansion capital expenditures	$	36,863	$	59,385	$	38,771	$	30,497	$	8,981
Other capital expenditures		8,584		14,700		9,851		9,514		4,615
Acquisitions		29,581		286,492		176,918		89,808		291,316
Operating Data:
System throughput volumes (MMcfd)		332		270		186		170		144
Gross processing margin ($/Mcf)	$	0.81	$	1.09	$	1.33	$	1.10	$	1.02
Coal owned or controlled (millions of tons)		829		827		818		765		689
Coal produced by lessees (millions of tons)		34.3		33.7		32.5		32.8		30.2
Average royalty revenues per ton ($/ton)	$	3.51	$	3.65	$	2.89	$	2.99	$	2.74
Average royalty revenues per ton by area ($/ton):
Central Appalachia	$	4.65	$	4.78	$	3.66	$	3.80	$	3.40
Northern Appalachia	$	1.83	$	1.84	$	1.53	$	1.46	$	1.41
Illinois Basin	$	2.63	$	2.28	$	1.97	$	1.88	$	1.87
San Juan Basin	$	2.12	$	2.06	$	2.00	$	1.88	$	1.74

(1) Adjusted EBITDA is a non-GAAP financial measure. Please see “—Non-GAAP Financial Measures” for a reconciliation of Adjusted EBITDA to net income and cash flows from operating activities.

(2) For purposes of determining the ratio of earnings to fixed charges, earnings are defined as the aggregate of income from continuing operations (before adjustment for equity earnings), fixed charges and distributions from equity investment, less capitalized interest. Fixed charges consist of interest expense (including amounts capitalized), amortization of debt costs and the portion of rental expense representing the interest factor. After giving effect to the issuance and sale of the notes in this offering and the application of the net proceeds therefrom to repay a portion of the borrowings outstanding under our Revolver, our ratio of earnings to fixed charges would have been 2.1x for the year ended December 31, 2009.

Non-GAAP Financial Measures

We include in this prospectus supplement the non-GAAP financial measures EBITDA and Adjusted EBITDA and provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP.

We define EBITDA as net income plus interest expense, provision for income taxes and DD&A expenses. Adjusted EBITDA represents EBITDA plus impairments, plus an adjustment for equity earnings, net of distributions received, plus derivative losses (gains) included in net income, plus cash settlements of derivatives.

EBITDA and Adjusted EBITDA are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others to assess:

• the financial performance of our assets without regard to financing methods, capital structure, historical cost basis or the effects of derivative transactions;

• the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness, including the notes;

• our operating performance and return on capital as compared to those of other companies, without regard to financing methods or capital structure; and

• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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EBITDA and Adjusted EBITDA are also financial measurements that are reported to our banks and are used to compute our financial covenants under our credit facilities. We have calculated Adjusted EBITDA herein in the same manner as the measure in such financial covenants in our Revolver defined as “EBITDA.” See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financial Condition—Covenant Compliance.” EBITDA and Adjusted EBITDA should not be considered alternatives to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Our EBITDA and Adjusted EBITDA may not be comparable to EBITDA, Adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate EBITDA and Adjusted EBITDA in the same manner as we do. EBITDA and Adjusted EBITDA have limitations as analytical tools, and you should not consider them in isolation from, or as a substitute for analysis of, our financial information prepared in accordance with GAAP. Some of these limitations are:

• they do not reflect cash outlays for capital expenditures or future contractual commitments;

• they do not reflect changes in, or cash requirements for, working capital;

• they do not reflect interest expense or the cash requirements necessary to service interest, or principal payments, on indebtedness;

• they do not reflect income tax expense or the cash necessary to pay income taxes;

• they do not reflect available liquidity to Penn Virginia Resource Partners; and

• other companies, including companies in our industry, may not use such measures or may calculate such measures differently than as presented in this prospectus supplement, limiting their usefulness as comparative measures.

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The following table presents a reconciliation of the non-GAAP financial measures of EBITDA and Adjusted EBITDA to the GAAP financial measures of net income and cash flows from operating activities on a historical basis for each of the periods indicated.

	Year Ended December 31,
	2009			2008			2007			2006			2005
	(in thousands)
Reconciliation of net income to Adjusted EBITDA:
Net income	$	65,215		$	104,500		$	56,623		$	73,928		$	51,161
Depreciation, depletion and amortization		70,235			58,166			41,512			37,493			30,628
Interest expense		24,653			24,672			17,338			18,821			14,054
EBITDA		160,103			187,338			115,473			130,242			95,843
Impairments		1,511			31,801			—			—			—
Equity earnings, net of distributions received		(2,537	)		(224	)		(285	)		1,317			1,269
Derivative losses (gains)		22,700			(11,357	)		50,163			13,213			13,036
Cash settlements of derivatives		3,000			(38,466	)		(17,779	)		(19,436	)		(4,752	)
Adjusted EBITDA	$	184,777		$	169,092		$	147,572		$	125,336		$	105,396
Reconciliation of cash flows from operating activities to Adjusted EBITDA:
Cash flows from operating activities	$	159,972		$	139,176		$	127,824		$	107,344		$	93,712
Changes in operating assets and liabilities		5,308			6,529			2,243			(60	)		(635	)
Non-cash interest expense		(4,391	)		(2,693	)		(678	)		(769	)		(1,735	)
Interest expense		24,653			24,672			17,338			18,821			14,054
Equity earnings, net of distributions received		2,537			224			285			(1,317	)		(1,269	)
Derivative gains (losses)		(22,700	)		11,357			(50,163	)		(13,213	)		(13,036	)
Cash settlements of derivatives		(3,000	)		38,466			17,779			19,436			4,752
Impairments		(1,511	)		(31,801	)		—			—			—
Other		(765	)		1,408			845			—			—
EBITDA		160,103			187,338			115,473			130,242			95,843
Impairments		1,511			31,801			—			—			—
Equity earnings, net of distributions received		(2,537	)		(224	)		(285	)		1,317			1,269
Derivative losses (gains)		22,700			(11,357	)		50,163			13,213			13,036
Cash settlements of derivatives		3,000			(38,466	)		(17,779	)		(19,436	)		(4,752	)
Adjusted EBITDA	$	184,777		$	169,092		$	147,572		$	125,336		$	105,396

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this prospectus supplement. All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated.

Overview of Business

We are a publicly traded Delaware limited partnership formed by Penn Virginia in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. Both in our current limited partnership form and in our previous corporate form, we have managed coal properties since 1882. We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream. In 2009, our coal and natural resource management segment contributed $87.5 million, or 81%, to operating income, and our natural gas midstream segment contributed $20.8 million, or 19%, to operating income.

As of December 31, 2009, we owned or controlled approximately 829 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. We enter into long-term leases with experienced, third-party mine operators, providing them the right to mine our coal reserves in exchange for royalty payments. We actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We do not operate any mines. In 2009, our lessees produced 34.3 million tons of coal from our properties and paid us coal royalties revenues of $120.4 million, for an average royalty per ton of $3.51. Approximately 82% of our coal royalties revenues in 2009 were derived from coal mined on our 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 our coal royalties revenues for the respective periods was derived from coal mined on our properties under leases containing fixed royalty rates that escalate annually.

Coal royalties are impacted by several factors that we 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 our lessees or their customers’ ability to use coal and which may require us, our lessees or our lessees’ customers to change operations significantly or incur substantial costs. Please read “Risk Factors.”

To a lesser extent, coal prices also impact coal royalties revenues. Generally, as coal prices change over an extended period of time, our average royalty per ton may change as the majority of our lessees pay royalties based on the gross sales prices of the coal mined. However, most of our lessees’ coal is sold under contracts with a duration of one year or more; therefore, the underlying prices for our royalties are less susceptible to short-term volatility in coal prices and prices change primarily as our lessees’ long-term contracts are renegotiated.

We also earn 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.

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2009, we owned and operated natural gas midstream

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assets located in Oklahoma and Texas, including six natural gas processing facilities having 400 MMcfd of total capacity and approximately 4,118 miles of natural gas gathering pipelines. Our 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, we own a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. We also own 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 2009, system throughput volumes at our gas processing plants and gathering systems, including gathering-only volumes, were 121.3 Bcf, or approximately 332 MMcfd. In 2009, 21%, 15% and 10% of our natural gas midstream segment revenues and 17%, 11% and 8% of our total consolidated revenues related to three of our natural gas midstream customers, Conoco, Inc., Tenaska Marketing Ventures and ONEOK Energy Marketing.

We continually seek new supplies of natural gas to both offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our 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 2009, our natural gas midstream segment made aggregate capital expenditures of $72.8 million, primarily related to our acquisition of the Sweetwater plant, expansion of the Spearman plant and other expansion related projects in the panhandle of Texas and Oklahoma. For a more detailed discussion of our acquisitions and investments, please read “—Acquisitions and Investments.”

Key Developments

2009 Commodity Prices

The 2009 average commodity prices for coal, timber, natural gas, crude oil and NGLs declined from 2008 levels. NGLs refer to ethane, propane, isobutane, normal butane and pentane. The pricing of these commodities directly and indirectly drives our earnings.

Coal royalties, which accounted for 83% of the 2009 coal and natural resource management segment revenues, were slightly lower as compared to 2008. We continue to benefit from long-term contract prices our lessees previously negotiated with their customers. However, the state of the global economy, including financial and credit markets, has reduced worldwide demand for coal with resultant price declines. Depending on the longevity and ultimate severity of the deterioration, demand for coal may continue to decline, which could adversely affect production and pricing for coal mined by our lessees.

Revenues, profitability and the future rate of growth of our 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 demand. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. Our derivative financial instruments include costless collars and swaps. Based upon current volumes, we have entered into hedging arrangements covering approximately 58% and 37% of our commodity-sensitive volumes in 2010 and 2011. We generally target hedging 50% to 60% of our commodity-sensitive volumes covering a two-year period.

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Acquisitions and Investments

In July 2009, we completed an acquisition of gas processing and residue pipeline facilities in western Oklahoma from Atlas Pipeline Partners, L.P. for approximately $22.6 million in cash. Funding for the acquisition was provided by borrowings under our Revolver. The acquired assets included a 60 MMcfd processing plant within Atlas’ 180 MMcfd Sweetwater facility. Additionally, we completed a 40 MMcfd processing plant expansion in our Spearman complex that was put into service on July 31, 2009. The acquired and expanded processing facilities increased our processing capacity in the Panhandle System to 260 MMcfd and overall processing capacity to 400 MMcfd. The increased processing capacity has allowed the natural gas midstream segment to process gas volumes that were being bypassed due to processing capacity constraints in the Panhandle System and has alleviated pipeline pressure-related volume constraints in the eastern portion of the Panhandle System.

In July 2008, we 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 natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin. We 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 our Revolver, 2,009,995 PVG common units (which we purchased from two subsidiaries of Penn Virginia for $61.8 million) and 542,610 of our newly issued 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 our election.

In April 2008, we 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 our Revolver.

In May 2008, we acquired fee ownership of approximately 29 million tons of coal reserves and approximately 56 MMbf 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 our Revolver.

PVR Midstream Agreement with Range Resources

On March 10, 2010, PVR Midstream entered into an agreement with a subsidiary of Range to construct and operate gas gathering pipelines and compression facilities servicing Range’s Marcellus Shale natural gas production primarily in Lycoming County, Pennsylvania.

PVR Midstream and Range have agreed to an area of mutual interest, or AMI, that covers parts of Lycoming, Tioga and Bradford Counties in north central Pennsylvania, in which Range currently holds a substantial acreage position. Within this AMI, PVR Midstream will construct approximately 16 miles of 24- and 30-inch gathering trunklines, smaller-diameter field gathering lines and compression facilities required to gather Range’s production from the AMI. The gathering system is expected to have over 700 MMcfd of throughput capacity, and the initial phase is expected to become operational in the fourth quarter of 2010. The agreement provides Range significant firm gathering capacity in the system, and PVR Midstream will be compensated for the gathering and compression services provided to Range through a combination of volumetric fees, with no direct

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commodity exposure. Excess capacity on the system and the location within a core area of Marcellus Shale development may provide opportunities for PVR Midstream to develop additional revenue by providing gathering and compression services to area producers.

PVR Midstream’s total capital investment in this system is anticipated to range from $170 to $200 million and is expected to be expended between 2010 and 2015, with $35 to $40 million planned for 2010.

PVR Midstream Agreement to Construct Gas Gathering and Compression Facilities

On March 1, 2010, PVR Midstream entered into an agreement to construct and operate gas gathering pipelines and compression facilities servicing a private firm’s Marcellus Shale natural gas production in Wyoming County, Pennsylvania. Pursuant to the terms of the agreement, PVR Midstream will construct a 12-inch gathering pipeline and compression facilities with 25 MMcf per day of throughput capacity and the potential for additional system extensions. PVR Midstream’s 2010 capital investment in this system is anticipated to range from $6 to $7 million, with potential future system extensions costing up to $10 million.

Liquidity and Capital Resources

Cash Flows

On an ongoing basis, we generally 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 distributions to unitholders 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 2010 working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled debt payments and distributions. However, our ability to meet these requirements in the future will depend upon our 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 our control.

The following table summarizes our statements of cash flows for the periods presented:

	For the Year Ended December 31,
	2009			2008			2007
Cash flows from operating activities:
Net income contribution	$	65,215		$	104,500		$	56,623
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		100,065			41,205			73,444
Net changes in operating assets and liabilities		(5,308	)		(6,529	)		(2,243	)
Net cash provided by operating activities		159,972			139,176			127,824
Net cash used in investing activities		(79,530	)		(331,030	)		(224,182	)
Net cash provided by (used in) financing activities		(81,267	)		181,808			104,448
Net increase (decrease) in cash and cash equivalents	$	(825	)	$	(10,046	)	$	8,090

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Cash Flows From Operating Activities

The overall increase in net cash provided by operating activities in 2009 as compared to 2008 was driven by an increase in the natural gas midstream segment’s gross margin, adjusted for the cash impact of midstream derivatives and impairments. We received a net $10.6 million in midstream derivative settlements in 2009 compared to paying a net $37.2 million in 2008. The difference in net derivative settlements relates to decreased commodity pricing and the expiration of older commodity derivatives. This increase was partially offset by a decrease in operating income, before DD&A expenses and impairments from the coal and natural resource management segment primarily due to decreases in coal royalties, oil and gas royalties and other revenue.

The overall increase in net cash provided by operating activities in 2008 as compared to 2007 was primarily attributable to increased cash received from the sales of residue gas and NGLs, which was primarily due to increased system throughput volume; increased coal royalties received, which was primarily due to 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 our September 2007 forestland acquisition. These increases were partially offset by increased cash outflows from our natural gas midstream commodity derivative settlements.

Cash Flows From Investing Activities

Net cash used in investing activities were primarily for capital expenditures. The following table sets forth our capital expenditures programs, by segment, for the periods presented:

	Year Ended December 31,
	2009		2008
Coal and natural resource management
Acquisitions	$	2,067	$	27,075
Expansion capital expenditures		—		—
Other property and equipment expenditures		185		195
Total		2,252		27,270
Natural gas midstream
Acquisitions		27,514		259,417
Expansion capital expenditures		36,863		59,385
Other property and equipment expenditures		8,399		14,505
Total		72,776		333,307
Total capital expenditures	$	75,028	$	360,577

Our 2009 capital expenditures consisted primarily of a natural gas midstream plant acquisition, and expansion capital used to increase our natural gas processing capacity and operational footprint in our Panhandle System.

Our 2008 capital expenditures were primarily discretionary in nature and included our 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 MMbf of hardwood timber in western Virginia and eastern Kentucky. Our natural gas midstream segment also incurred approximately $14.5 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas.

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Cash Flows From Financing Activities

During 2009, we had net borrowings of $52.0 million under our Revolver. These borrowings were used to fund our capital expenditure program. During 2008, we had net borrowings of $156.0 million primarily attributable to our Revolver offset by the repayments of $63.3 million under the Senior Unsecured Notes due 2013. In 2008 we also received net proceeds of $141.1 million from the sale of our common units in a public offering, 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 our general partner to maintain its 2% general partner interest. This increase in outstanding common units also increased distributions paid to our partners.

In January 2010 we declared a $0.47 ($1.88 on an annualized basis) per unit quarterly distribution for the three months ended December 31, 2009 paid on February 12, 2010 to unitholders of record at the close of business on February 2, 2010.

Sources of Liquidity

Long-Term Debt

Revolver.As of December 31, 2009, net of outstanding borrowings of $620.1 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $178.3 million on our Revolver. In March 2009, we increased the size of our Revolver from $700.0 million to $800.0 million and secured our Revolver with substantially all of our assets. Our Revolver matures in December 2011 and is available to us 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 2009, we incurred commitment fees of $0.5 million on the unused portion of our Revolver. The interest rate under our Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 1.25% if we select the base rate borrowing option under our Revolver or at a rate derived from LIBOR plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under our Revolver during 2009 was approximately 2.7%. We do not have a public credit rating for our Revolver. Please read “—Financial Condition.”

Interest Rate Swaps.We have entered into interest rate swaps, or the Interest Rate Swaps, to establish fixed rates on a portion of the outstanding borrowings under our Revolver. The following table sets forth the Interest Rate Swap positions at December 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 Interest Rate Swaps extend one year past the maturity of the current Revolver. After considering the applicable margin of 2.25% in effect as of December 31, 2009 the total interest rate on the $310 million portion of our Revolver borrowings covered by the Interest Rate Swaps was 5.79% as of December 31, 2009.

Unit Offering

In 2008, we completed the sale of 5.15 million common units representing limited partner interests in a registered public offering and received $138.2 million in net proceeds. We received total contributions of $2.9 million from our general partner to maintain its 2% general partner interest in us. The net sales proceeds were used to repay a portion of our borrowings under our Revolver.

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Financial Condition

Covenant Compliance

The terms of our Revolver require us to maintain compliance with certain financial covenants. These covenants are as follows:

• Total debt to consolidated EBITDA may not exceed 5.25 to 1.0. EBITDA, which is a non-GAAP measure, is generally defined in our Revolver as our net income plus interest expense, DD&A expenses, non-cash hedging activity, cash settlements of derivatives and impairments.

• Consolidated EBITDA to interest expense may not be less than 2.5 to 1.0.

As of December 31, 2009, we were in compliance with all of our Revolver’s covenants. The following table summarizes the actual results of our covenant compliance for the period ended December 31, 2009:

Description of Covenant	Covenant	Actual Results
Debt to EBITDA	5.25	3.36
EBITDA to interest expense	2.50	7.50

In the event that we would be in default of our covenants under our Revolver, 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 prohibits us from making distributions to our partners if any potential default, or event of default, as defined in our Revolver, occurs or would result from the distributions.

In addition, our Revolver contains various 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.

Future Capital Needs and Commitments

After giving effect to this offering, we believe that our remaining borrowing capacity of $470.3 million will be sufficient for our 2010 capital needs and commitments. Our short-term cash requirements for operating expenses and quarterly distributions to PVG, as the owner of our general partner, and unitholders are expected to be funded through operating cash flows. In 2010, we anticipate making capital expenditures, excluding acquisitions, of approximately $105.0 million, including anticipated capital expenditures in connection with the construction of facilities under our agreement with a subsidiary of Range. The majority of the 2010 capital expenditures are expected to be incurred in the natural gas midstream segment. We intend to fund these capital expenditures with a combination of operating cash flows and borrowings under our Revolver. Long- term cash requirements for acquisitions and other capital expenditures are expected to be funded by operating cash flows, borrowings under our Revolver and the issuances of additional debt and equity securities if available under commercially acceptable terms.

Part of our long-term strategy is to increase cash available for distribution to our unitholders by making acquisitions and other capital expenditures. Our ability to make these acquisitions and other capital expenditures in the future will depend largely on the availability of debt financing and on our

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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 our financial condition and credit rating.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2009:

	Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Revolver	$	620,100	$	—	$	620,100	$	—	$	—
Asset retirement obligations(1)		2,014		—		369		—		1,645
Interest expense(2)		30,034		15,440		14,594		—		—
Derivatives(3)		15,536		11,251		4,285		—		—
Natural gas midstream activities(4)		32,320		13,103		10,202		7,354		1,661
Rental commitments(5)		24,480		4,243		6,430		5,864		7,943
Total contractual obligations(6)	$	724,484	$	44,037	$	655,980	$	13,218	$	11,249

(1) The undiscounted balance was approximately $7.7 million at December 31, 2009.

(2) Represents estimated interest payments that will be due under our Revolver.

(3) Represents estimated payments we will make resulting from our commodity derivatives as well as the Interest Rate Swaps.

(4) Commitments for natural gas midstream activities relate to firm transportation agreements.

(5) Primarily relates to equipment and building leases and leases of coal reserve-based properties which we sublease, or intend to sublease, to third parties.

(6) Total contractual obligations do not include anticipated 2010 capital expenditures.

Part of the purchase price for the Lone Star acquisition includes contingent payments of approximately $55.0 million. These contingency payments will be made by us if certain revenue targets are met before June 30, 2013. Because the outcome of these contingent payments is not determinable beyond a reasonable doubt, we have not accrued them as a liability. Rather, once the revenue targets are met, the contingent payments will be recorded as an additional cost of the Lone Star acquisition.

Other than our employment agreements with Messrs. Shea and Wallace, we do not have employment agreements with our executive officers and do not have any other employees. Our compensation obligations with respect to our executive officers can be significantly different from one year to another and are based on variables such as our performance for the given year.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2009, the material off-balance sheet arrangements and transactions that we have entered into included operating lease arrangements, firm transportation agreements, and letters of credit, all of which are customary in our business. Please read “—Contractual Obligations” above for more detail related to the value of off-balance sheet arrangements. 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,

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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

Consolidated Review

The following table presents our summary consolidated operating results for the periods presented:

	Year Ended December 31,
	2009			2008			2007
Revenues	$	656,704		$	881,580		$	549,445
Expenses		548,402			766,338			431,720
Operating income		108,302			115,242			117,725
Other income (expense)		(43,087	)		(10,742	)		(61,102	)
Net income	$	65,215		$	104,500		$	56,623

The following table presents certain summary financial information relating to our segments for the periods presented:

	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
For the Year Ended December 31, 2009:
Revenues	$	144,600	$	512,104	$	656,704
Cost of midstream gas purchased		—		406,583		406,583
Operating costs and expenses		24,231		45,842		70,073
Impairments		1,511		—		1,511
Depreciation, depletion and amortization		31,330		38,905		70,235
Operating income	$	87,528	$	20,774	$	108,302
For the Year Ended December 31, 2008:
Revenues	$	153,327	$	728,253	$	881,580
Cost of midstream gas purchased		—		612,530		612,530
Operating costs and expenses		26,226		37,615		63,841
Impairments		—		31,801		31,801
Depreciation, depletion and amortization		30,805		27,361		58,166
Operating income	$	96,296	$	18,946	$	115,242
For the Year Ended December 31, 2007:
Revenues	$	111,639	$	437,806	$	549,445
Cost of midstream gas purchased		—		343,293		343,293
Operating costs and expenses		20,138		26,777		46,915
Depreciation, depletion and amortization		22,690		18,822		41,512
Operating income	$	68,811	$	48,914	$	117,725

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Coal and Natural Resource Management Segment

Year Ended December 31, 2009 Compared With Year Ended December 31, 2008

The following table sets forth a summary of certain financial and other data for our coal and natural resource management segment and the percentage change for the periods presented:

	Year Ended December 31,						Favorable (Unfavorable)			% Change
	2009			2008
Financial Highlights
Revenues
Coal royalties	$	120,435		$	122,834		$	(2,399	)	(2	%)
Coal services		7,332			7,355			(23	)	(0	%)
Timber		5,726			6,943			(1,217	)	(18	%)
Oil and gas royalty		2,471			5,989			(3,518	)	(59	%)
Other		8,636			10,206			(1,570	)	(15	%)
Total revenues		144,600			153,327			(8,727	)	(6	%)
Expenses
Coal royalties		5,768			9,534			3,766		40	%
Other operating		2,892			2,406			(486	)	(20	%)
Taxes other than income		1,704			1,680			(24	)	(1	%)
General and administrative		13,867			12,606			(1,261	)	(10	%)
Impairments		1,511			—			(1,511	)		—
Depreciation, depletion and amortization		31,330			30,805			(525	)	(2	%)
Total expenses		57,072			57,031			(41	)	(0	%)
Operating income	$	87,528		$	96,296		$	(8,768	)	(9	%)
Other Data
Coal royalty tons by region
Central Appalachia		18,319			19,587			(1,268	)	(6	%)
Northern Appalachia		3,786			3,578			208		6	%
Illinois Basin		4,724			4,584			140		3	%
San Juan Basin		7,501			5,941			1,560		26	%
Total		34,330			33,690			640		2	%
Coal royalties revenues by region
Central Appalachia	$	85,183		$	93,577			(8,394	)	(9	%)
Northern Appalachia		6,931			6,568			363		6	%
Illinois Basin		12,420			10,451			1,969		19	%
San Juan Basin		15,901			12,238			3,663		30	%
	$	120,435		$	122,834			(2,399	)	(2	%)
Less coal royalties expenses(1)		(5,768	)		(9,534	)		3,766		(40	%)
Net coal royalties revenues	$	114,667		$	113,300		$	1,367		1	%
Coal royalties per ton by region ($/ton)
Central Appalachia	$	4.65		$	4.78			(0.13	)	(3	%)
Northern Appalachia		1.83			1.84			(0.01	)	(1	%)
Illinois Basin		2.63			2.28			0.35		15	%
San Juan Basin		2.12			2.06			0.06		3	%
	$	3.51		$	3.65		$	(0.14	)	(4	%)
Less coal royalties expenses(1)		(0.17	)		(0.28	)		0.11		(39	%)
Net coal royalties revenues	$	3.34		$	3.37		$	(0.03	)	(1	%)

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

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Revenues

Coal royalties revenues decreased slightly due to the decrease in the average coal royalty received per ton. This decrease was due to an overall shift in production mix to lower royalty lessees, primarily to fixed rate leases in the San Juan Basin from the higher royalty Central Appalachian region.

Coal production by our lessees increased slightly due to higher production in the San Juan Basin resulting from the start up of a second mine and improved mining conditions. This increase was partially offset by a decline in production in the Central Appalachian region which was due to a reduction in longwall mining activity and a depressed coal market.

Timber revenues decreased due to lower sales prices resulting from weakened market conditions for furniture-grade wood products. The average price received for timber decreased 27% from $287 per Mbf in 2008 to $209 per Mbf in 2009.

The oil and gas royalty revenues decrease was primarily attributable to lower natural gas prices in 2009. Realized prices received for natural gas decreased 57% from $10.63 per Mcf in 2008 to $4.55 per Mcf in 2009.

Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fees, decreased due to lower wheelage income from a decline in coal production in certain areas. In addition, in 2008, a $0.8 million gain on the settlement of unmined coal was recognized.

Expenses

Coal royalties expenses decreased due to a decline in mining activity by our lessees from subleased properties in the Central Appalachian region where our coal royalties expense is primarily incurred. Mining activity on our subleased property fluctuates between periods due to the proximity of our property boundaries and other mineral owners.

General and administrative expenses increased as a result of an uncollectible account receivable resulting from a lessee bankruptcy and increased staffing and related benefit costs.

The $1.5 million impairment expense in 2009 was the result of a reduction in the value of an intangible asset. We test long-lived assets for impairment if a triggering event occurs and the impairment was triggered by a wheelage contract being rejected in bankruptcy. As a result of the impairment, the fair value of the contract has been reduced to zero.

DD&A expenses increased slightly due to higher depletion expense resulting from the increase in coal mined from our properties by our lessees. On a per ton basis, DD&A remained constant at $0.91 per ton for both periods.

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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 our coal and natural resource management segment and the percentage change for the periods presented:

	Year Ended December 31,						Favorable (Unfavorable)			% Change
	2008			2007
Financial Highlights
Revenues
Coal royalties	$	122,834		$	94,140		$	28,694		30	%
Coal services		7,355			7,252			103		1	%
Timber		6,943			1,711			5,232		306	%
Oil and gas royalty		5,989			1,864			4,125		221	%
Other		10,206			6,672			3,534		53	%
Total revenues		153,327			111,639			41,688		37	%
Expenses
Coal royalties		9,534			5,540			(3,994	)	(72	%)
Other operating		2,406			2,531			125		5	%
Taxes other than income		1,680			1,110			(570	)	(51	%)
General and administrative		12,606			10,957			(1,649	)	(15	%)
Depreciation, depletion and amortization		30,805			22,690			(8,115	)	(36	%)
Total expenses		57,031			42,828			(14,203	)	(33	%)
Operating income	$	96,296		$	68,811		$	27,485		40	%
Other Data
Coal royalty tons by region
Central Appalachia		19,587			18,827			760		4	%
Northern Appalachia		3,578			4,194			(616	)	(15	%)
Illinois Basin		4,584			3,779			805		21	%
San Juan Basin		5,941			5,728			213		4	%
Total		33,690			32,528			1,162		4	%
Coal royalties revenues by region
Central Appalachia	$	93,577		$	68,815		$	24,762		36	%
Northern Appalachia		6,568			6,434			134		2	%
Illinois Basin		10,451			7,432			3,019		41	%
San Juan Basin		12,238			11,459			779		7	%
	$	122,834		$	94,140		$	28,694		30	%
Less coal royalties expenses(1)		(9,534	)		(5,540	)		(3,994	)	72	%
Net coal royalties revenues	$	113,300		$	88,600		$	24,700		28	%
Coal royalties per ton by region ($/ton)
Central Appalachia	$	4.78		$	3.66		$	1.12		31	%
Northern Appalachia		1.84			1.53			0.31		20	%
Illinois Basin		2.28			1.97			0.31		16	%
San Juan Basin		2.06			2.00			0.06		3	%
	$	3.65		$	2.89		$	0.76		26	%
Less coal royalties expenses(1)		(0.28	)		(0.17	)		(0.11	)	65	%
Net coal royalties revenues	$	3.37		$	2.72		$	0.65		24	%

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

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Revenues

Coal royalties revenues increased as a result of higher coal prices and additional tons being mined by our lessees. Coal royalty tons increased primarily due to higher production in the Central Appalachia and Illinois Basin regions, partially offset by a production decline in the Northern Appalachian region. The Central Appalachian region increase was the result of longwall mining and the timing of additional mining equipment added to our properties during 2008. The Illinois Basin region increase was primarily due to a full year of production in 2008 on coal reserves which were acquired in June 2007. The Northern Appalachian region decrease was a result of adverse longwall mining conditions.

Coal prices were higher on average due to international coal shortages on both the metallurgical and steam markets, which not only drove increases in export metallurgical pricing, but also allowed some higher thermal capacity steam coal to crossover into the metallurgical market; consequently, this caused the domestic steam coal markets to tighten and resulted in higher domestic pricing. Our coal royalties revenues are dependent on the prevailing coal prices received by our lessees, which are affected by numerous factors that are generally beyond our control. Coal prices are generally determined by national and regional supply and demand.

Timber revenues increased due to increased harvesting from our September 2007 forestland acquisition. The average price received for timber increased 20% from $240 per Mbf in 2007 to $287 per Mbf in 2008.

The oil and gas royalty revenues increase was primarily due to the increased royalties resulting from our October 2007 oil and gas royalty interest acquisition. Realized prices received for natural gas increased 31% from $8.11 per Mcf in 2007 to $10.63 per Mcf in 2008.

Other revenues increased primarily due to increased coal transportation, or wheelage, fees attributable to greater production, increased forfeiture income and the recognition of a $0.8 million gain on the settlement of unmined coal.

Expenses

Coal royalties expenses increased due to additional mining by our lessees from subleased properties in the Central Appalachian region.

Taxes other than income increased primarily due to increased severance taxes resulting from our September 2007 forestland acquisition and October 2007 oil and gas royalty interest acquisition.

General and administrative expenses increased primarily due to increased staffing and related benefit costs.

DD&A expenses increased due to increased depletion resulting from our September 2007 forestland acquisition, October 2007 oil and gas royalty interest acquisition and May 2008 coal reserves and forestland acquisition. A discussion of our DD&A methodologies is provided in the Critical Accounting Estimates that follows.

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Natural Gas Midstream Segment

Year Ended December 31, 2009 Compared With Year Ended December 31, 2008

The following table sets forth a summary of certain financial and other data for our natural gas midstream segment and the percentage change for the periods presented:

	Year Ended December 31,					Favorable (Unfavorable)			% Change
	2009		2008
Financial Highlights
Revenues
Residue gas	$	289,427	$	452,535		$	(163,108	)	(36	%)
Natural gas liquids		182,794		229,765			(46,971	)	(20	%)
Condensate		17,010		26,009			(8,999	)	(35	%)
Gathering, processing and transportation fees		15,558		11,693			3,865		33	%
Total natural gas midstream revenues(1)		504,789		720,002			(215,213	)	(30	%)
Equity earnings in equity investment		5,548		2,408			3,140		130	%
Producer services		1,767		5,843			(4,076	)	(70	%)
Total revenues		512,104		728,253			(216,149	)	(30	%)
Expenses
Cost of midstream gas purchased(1)		406,583		612,530			205,947		34	%
Operating		26,451		20,737			(5,714	)	(28	%)
Taxes other than income		3,090		2,578			(512	)	(20	%)
General and administrative		16,301		14,300			(2,001	)	(14	%)
Impairments		—		31,801			31,801		100	%
Depreciation and amortization		38,905		27,361			(11,544	)	(42	%)
Total operating expenses		491,330		709,307			217,977		31	%
Operating income	$	20,774	$	18,946		$	1,828		10	%
Operating Statistics
System throughput volumes (MMcf)		121,335		98,683			22,652		23	%
Daily throughput volumes (MMcfd)		332		270			62		23	%
Gross margin	$	98,206	$	107,472		$	(9,266	)	(9	%)
Cash impact of derivatives		10,566		(31,709	)		42,275		133	%
Gross margin, adjusted for impact of derivatives	$	108,772	$	75,763		$	33,009		44	%
Gross margin ($/Mcf)	$	0.81	$	1.09		$	(0.28	)	(26	%)
Cash impact of derivatives ($/Mcf)		0.09		(0.32	)		0.41		128	%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.90	$	0.77		$	0.13		17	%

(1) In 2009 and 2008, we recorded $72.5 million and $127.9 million of natural gas midstream revenue and $72.5 million 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. We take title to the gas prior to transporting it to third parties. These transactions do not impact the gross margin.

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Gross Margin

Gross margin is the difference between our natural gas midstream revenues and our 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 our 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.

The gross margin decrease was a result of lower commodity pricing and lower fractionation spreads, or frac spreads, partially offset by increased system throughput volumes and increased natural gas processing capacity. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis.

Drilling activities by producers central to our natural gas gathering and processing plants were at reduced levels from the previous year due to lower natural gas prices. However, the 2009 system throughput volumes benefited from the results of drilling activity in 2008 and the first part of 2009. The expansion and acquisition activity, especially in the Panhandle System, has alleviated pipeline pressures and allowed us to move all of our gas in this region to our processing plants. As noted above, in July 2009 we completed an acquisition of gas processing and residue pipeline facilities in western Oklahoma. The acquired assets included the 60 MMcfd Sweetwater plant. Additionally, we completed a 40 MMcfd processing plant expansion in our Spearman complex that was put into service on July 31, 2009. The acquired and expanded processing facilities increased our processing capacity in the Panhandle System to 260 MMcfd and overall processing capacity to 400 MMcfd. The increased processing capacity has allowed us to process natural gas volumes that were being bypassed due to processing capacity constraints in the Panhandle System and has alleviated pipeline pressure-related volume constraints in the eastern portion of the Panhandle.

During 2009, we 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. Please read “Business—Contracts—Natural Gas Midstream Segment,” for discussion of the types of contracts utilized by the natural gas midstream segment. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. Please read Note 6 to our consolidated financial statements included elsewhere in this prospectus supplement for a description of our derivatives program. On a per Mcf basis, adjusted for the impact of our commodity derivative instruments, our gross margin increased in 2009 by $0.13, or 17%. This favorable impact of commodity derivatives is a result of overall lower commodity prices during 2009 and the expiration of older derivative instruments.

Revenues Other Than Gross Margin

Equity earnings in equity investment increased due to a full year of results in 2009 compared with a partial year in 2008. In April 2008, we acquired a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. In addition, revenues from the joint venture have grown in 2009 due to mainline volume increases in the Powder River Basin.

Producer services revenues decreased due to a negative relative change in the natural gas indices on which our purchases and sales of natural gas are based and a decrease in marketing fees resulting from lower commodity prices.

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Expenses

Operating expenses increased due to prior and current years’ acquisitions, expansion projects, compressor rentals and labor costs. Increased costs for compressor rentals and labor costs were incurred due to expanding our footprint in the Panhandle System.

Taxes other than income increased due to higher property taxes. The increase in property taxes was a result of acquisitions and plant expansions.

General and administrative expenses increased due to increased staffing and related benefit costs. The increase was primarily attributable to labor costs resulting from the 2008 acquisitions and plant expansions. We incurred a full year of salaries and benefits in 2009 compared with a partial year in 2008.

Impairment expense in 2008 was the result of a reduction in the value of goodwill. 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 our market capitalization, reduced to zero all goodwill recorded in conjunction with acquisitions made by our natural gas midstream segment in 2008 and prior years.

Depreciation and amortization expenses increased primarily due to acquisitions, capital expansions on the Spearman and Sweetwater plants and new well connections in existing areas of operation.

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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 our natural gas midstream segment and the percentage change for the periods presented:

	Year Ended December 31,						Favorable (Unfavorable)			% Change
	2008			2007
Financial Highlights
Revenues
Residue gas	$	452,535		$	242,129		$	210,406		87	%
Natural gas liquids		229,765			172,144			57,621		33	%
Condensate		26,009			13,889			12,120		87	%
Gathering, processing and transportation fees		11,693			5,012			6,681		133	%
Total natural gas midstream revenues(1)		720,002			433,174			286,828		66	%
Equity earnings in equity investment		2,408			—			2,408		—
Producer services		5,843			4,632			1,211		26	%
Total revenues		728,253			437,806			290,447		66	%
Expenses
Cost of midstream gas purchased(1)		612,530			343,293			(269,237	)	(78	%)
Operating		20,737			12,893			(7,844	)	(61	%)
Taxes other than income		2,578			1,926			(652	)	(34	%)
General and administrative		14,300			11,958			(2,342	)	(20	%)
Impairments		31,801			—			(31,801	)	—
Depreciation and amortization		27,361			18,822			(8,539	)	(45	%)
Total operating expenses		709,307			388,892			(320,415	)	(82	%)
Operating income	$	18,946		$	48,914		$	(29,968	)	(61	%)
Operating Statistics
System throughput volumes (MMcf)		98,683			67,810			30,873		46	%
Daily throughput volumes (MMcfd)		270			186			84		45	%
Gross margin	$	107,472		$	89,881		$	17,591		20	%
Cash impact of derivatives		(31,709	)		(13,184	)		(18,525	)	(141	%)
Gross margin, adjusted for impact of derivatives	$	75,763		$	76,697		$	(934	)	(1	%)
Gross margin ($/Mcf)	$	1.09		$	1.33		$	(0.24	)	(18	%)
Cash impact of derivatives ($/Mcf)		(0.32	)		(0.19	)		(0.13	)	(68	%)
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.77		$	1.14		$	(0.37	)	(32	%)

(1) In 2008, we 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. We take title to the gas prior to transporting it to third parties. These transactions do not impact the gross margin.

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Gross Margin

Gross margin is the difference between our natural gas midstream revenues and our 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 our 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.

The gross margin increase was a result of higher commodity pricing, increased system throughput volume production and higher frac spreads during 2008 compared to 2007.

The system throughput volumes increase 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 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.

During 2008, we 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. Please read “Business—Contracts—Natural Gas Midstream Segment,” for discussion of the types of contracts utilized by the natural gas midstream segment. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. Please read Note 6 to our consolidated financial statements included elsewhere in this prospectus supplement for a description of our derivatives program. On a per Mcf basis, adjusted for the impact of our commodity derivative instruments for which we discontinued hedge accounting in 2006, our gross margin decreased by $0.37, or 32%. 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 system throughput volumes. However, margins decreased towards the end of 2008 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 per Mcf basis decreased in 2008 due to an increase in fee-based system throughput volumes. These increased volumes are associated with our 2008 expansions and acquisitions.

Revenues Other Than Gross Margin

Equity earnings in equity investment increased due to our April 2008 acquisition of a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. We acquired the member interest in April 2008.

Producer services revenues increased due to an increase in agent fees for the marketing of Penn Virginia’s and third parties’ natural gas production. Agent fees increased primarily due to increases in Penn Virginia’s natural gas production as well as increases in the price of natural gas.

Expenses

Operating expenses increased due to expenses related to our 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 labor costs.

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Taxes other than income decreased due to higher property taxes. The increase in property taxes was a result of acquisitions and plant expansions.

General and administrative expenses increased due to increased staffing and related benefit costs. The increase in personnel was primarily attributable to acquisitions, plant expansions and well connects in established areas of operation.

Impairment expense in 2008 was the result of a reduction in the value of goodwill. 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 loss, which was triggered by fourth quarter declines in oil and gas spot and futures prices and a decline in our market capitalization, reduced to zero all goodwill recorded in conjunction with acquisitions made by our natural gas midstream segment in 2008 and prior years.

Depreciation and amortization expenses increased primarily due to capital expansions on the Spearman and Crossroads plants and acquisitions.

Other

Our other results consist of interest expense and derivative gains and losses. The following table sets forth a summary of certain financial data for our other results for the periods presented:

	Year Ended December 31,
	2009			2008			2007
Operating income	$	108,302		$	115,242		$	117,725
Other income (expense)
Interest expense		(24,653	)		(24,672	)		(17,338	)
Other		1,280			(2,907	)		1,804
Derivatives		(19,714	)		16,837			(45,568	)
Net income	$	65,215		$	104,500		$	56,623

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

	Year Ended December 31,
Source	2009			2008			2007
Interest on borrowings	$	21,523		$	23,641		$	18,861
Capitalized interest(1)		(226	)		(675	)		(786	)
Interest rate swaps		3,356			1,706			(737	)
Total interest expense	$	24,653		$	24,672		$	17,338

(1) Capitalized interest was primarily related to the construction of our natural gas gathering facilities.

Our consolidated interest expense remained relatively constant at $24.7 million for the years ended December 31, 2009 and 2008. Even though interest rates decreased during 2009, this decrease was offset in part by the higher level of outstanding borrowings during 2009 as compared to 2008. There were also higher levels of debt issuance costs expensed in 2009 related to the March 2009 increase in the size of our Revolver from $700.0 million to $800.0 million. The increase in interest expense in 2008 compared to 2007 is primarily due to the increase in our average debt balance.

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The interest capitalized in all three years related to construction of the Spearman and Crossroads plants.

In connection with the Interest Rate Swaps, we recognized $3.4 million in net hedging losses in interest expense in 2009. The increase over prior years relates to the decrease in LIBOR rates during 2009 relative to the fixed interest rates of the Interest Rate Swaps.

Derivatives. Our results of operations and operating cash flows were impacted by changes in market prices for NGLs, crude oil and natural gas prices, as well as the Interest Rate Swaps.

Commodity markets are volatile, and as a result, our hedging activity results can vary significantly. Our results of operations are affected by the volatility of changes in fair value, which fluctuate with changes in NGL, crude oil and natural gas prices. We determine the fair values of our 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.

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 the derivatives line item on our Consolidated Statements of Income.

Our derivative activity for the periods presented is summarized below:

	Year Ended December 31,
	2009			2008			2007
Interest Rate Swap unrealized derivative gain	$	3,260		$	—		$	—
Interest Rate Swap realized derivative loss		(7,566	)		—			—
Natural gas midstream commodity unrealized derivative gain (loss)		(25,974	)		55,303			(27,789	)
Natural gas midstream commodity realized derivative gain (loss)		10,566			(38,466	)		(17,779	)
Total derivative gain (loss)	$	(19,714	)	$	16,837		$	(45,568	)

Environmental Matters

Our operations and those of our 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 our 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 us against any and all future environmental liabilities. We regularly visit our coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Our management believes that our operations and those of our lessees comply with existing laws and regulations and does not expect any material impact on our financial condition or results of operations.

As of December 31, 2009 and 2008, our environmental liabilities were $1.0 million and $1.2 million, which represents our best estimate of the liabilities as of those dates, related to our coal and natural resource management and natural gas midstream businesses. We have 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 our operations, see “Business—Government Regulation and Environmental Matters.”

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Critical Accounting 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.

Coal Royalties Revenues

We recognize coal royalties revenues on the basis of tons of coal sold by our lessees and the corresponding revenues from those sales. Since we do not operate any coal mines, we do 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

Our gross margin is the difference between our natural gas midstream revenues and our 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 our gas processing plants. We recognize revenues from the sale of NGLs and residue gas when we sell the NGLs and residue gas produced at our gas processing plants. We recognize gathering and transportation revenues based 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, 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.

Depreciation, Depletion and Amortization

We compute depreciation and amortization of property, plant and equipment using the straight-line balance method over the estimated useful life of each asset.

Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by our own geologists and outside consultants. Our 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, we carry out core-hole drilling activities on our 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. We

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deplete timber using a methodology consistent with the units-of-production method, but that is based on the quantity of timber harvested. We determine 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 we retire or sell an asset, we remove its cost and related accumulated depreciation and amortization from our consolidated balance sheets. Upon sale, 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.

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, customer relationships and rights-of-way, and are combined with property, plant and equipment and are reviewed for impairment. Please read Note 10 to our consolidated financial statements included elsewhere in this prospectus supplement for a more detailed description of our intangible assets.

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 of acceptable credit risks, take the form of collars and swaps. All derivative financial instruments are recognized in our consolidated financial statements at fair value. 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 the board of directors of our general partner.

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 the derivatives line item on our consolidated statements of income. At December 31, 2009, a $1.4 million loss remained in accumulated other comprehensive income related to the Interest Rate Swaps. The $1.4 million loss will be recognized in interest expense as the Interest Rate Swaps settle.

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. Please read Note 6 to our consolidated financial statements included elsewhere in this prospectus supplement for a further description of our derivatives program.

Impairment of Goodwill

Goodwill has been allocated to our natural gas midstream segment and recorded in connection with acquisitions and business combinations. This goodwill 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

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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.

We tested goodwill for impairment during the fourth quarter of 2008 and recorded a goodwill impairment loss of $31.8 million. The impairment loss, which was triggered by fourth quarter declines in oil and gas spot and futures prices and a decline in our market capitalization, reduced to zero all goodwill recorded in conjunction with acquisitions made by the natural gas midstream segment in 2008 and prior years. This loss was recorded in the impairment line on our consolidated statements of income. Our goodwill balance remained at zero at December 31, 2009. Please read Note 9 to our consolidated financial statements included elsewhere in this prospectus supplement for a description of goodwill and the related impairment loss.

Equity Investments

We use the equity method of accounting to account for our 25% member interest in Thunder Creek, as well as our investment in a 50% member interest in a coal handling joint venture, recording the initial investment at cost. Subsequently, the carrying amount of the investment is increased to reflect our share of income of the investee and capital contributions, and is reduced to reflect our share of losses of the investee or distributions received from the investee as the joint ventures report them. Our share of earnings or losses from Thunder Creek is included in other revenues on the consolidated statements of income, and our share of earnings and losses from the coal handling joint venture is included in coal services on the consolidated statements of income. Other revenues and coal services revenues also include amortization of the amount of the equity investments that exceed our portion of the underlying equity in net assets (the inside/outside basis). We record this amortization over the life of the contracts acquired in the Thunder Creek acquisition and the life of the coal services contracts acquired in the acquisition of the coal handling joint venture.

New Accounting Standards

Please read Note 2 to our consolidated financial statements included elsewhere in this prospectus supplement for a description of recent accounting standards.

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 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 state of the global economy, including financial and credit markets.

We have completed a number of acquisitions in recent years. Please read Note 3 to our consolidated financial statements included elsewhere in this prospectus supplement for a

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description of our 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. 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 that we could record a significant impairment loss on our consolidated statements of income.

Price Risk

Our price risk management program permits the utilization of derivative financial instruments (such as futures, forwards, option contracts and swaps) to seek to mitigate the price risks associated with fluctuations in natural gas, NGL and crude oil prices as they relate to our 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.

At December 31, 2009, we reported a net commodity derivative liability related to the natural gas midstream segment of $3.2 million that is with six counterparties and is substantially concentrated with three of those counterparties. This concentration 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. We neither paid nor received collateral with respect to our derivative positions. No significant uncertainties related to the collectability of amounts owed to us exist with regard to these counterparties.

In 2009, we reported a net derivative loss of $19.7 million. Some of our commodity derivative financial instruments initially qualified as cash flow hedges, and changes in the effective portion of fair value from these contracts were deferred in accumulated comprehensive income until the hedged transactions settled. When we discontinued hedge accounting for commodity derivatives in 2006, a net loss remained in accumulated other comprehensive income. As the hedged transactions settled in 2007 and 2008, we recognized these deferred changes in fair value in revenues and cost of gas purchased in our consolidated statements of income. As of December 31, 2008, no net losses remained in accumulated other comprehensive income related to our natural gas midstream commodity derivatives.

Because we no longer use 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.

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The following table lists our commodity derivative agreements and their fair values as of December 31, 2009:

	Average Volume Per Day		Swap Price		Weighted Average Price				Fair Value at December 31, 2009
					Put		Call
									(in thousands)
Crude Oil Collar	(barrels	)				($ per barrel)
First Quarter 2010 through Fourth Quarter 2010	750				$	70.00	$	81.25	$	(1,329	)
First Quarter 2010 through Fourth Quarter 2010	1,000				$	68.00	$	80.00		(2,171	)
First Quarter 2011 through Fourth Quarter 2011	400				$	75.00	$	98.50		18
Natural Gas Purchase Swap	(MMBtu	)		($ per MMBtu)
First Quarter 2010 through Fourth Quarter 2010	5,000		$	5.815						(41	)
First Quarter 2011 through Fourth Quarter 2011	3,000		$	6.430						(99	)
NGL – Natural Gasoline Collar	(gallons	)				($ per gallon)
First Quarter 2011 through Fourth Quarter 2011	60,000				$	1.55	$	1.92		(945	)
Settlements to be received in subsequent period										1,331
Total									$	3,236

We estimate that a $5.00 per barrel increase in the crude oil price would decrease the fair value of our crude oil collars by $3.1 million. We estimate that a $5.00 per barrel decrease in the crude oil price would increase the fair value of our crude oil collars by $2.8 million. We estimate that a $1.00 per MMBtu increase in the natural gas price would increase the fair value of our natural gas purchase swaps by $2.7 million. We estimate that a $1.00 per MMBtu decrease in the natural gas price would decrease the fair value of our natural gas purchase swaps by $2.7 million. We estimate that a $0.11 per gallon increase in the natural gasoline (a natural gas liquid, NGL) price would decrease the fair value of our natural gasoline collar by $1.8 million. We estimate that a $0.11 per gallon decrease in the natural gasoline price would increase the fair value of our natural gasoline collar by $1.7 million.

We estimate that, excluding the effects of derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, our natural gas midstream gross margin and operating income in 2010 would increase or decrease by $6.9 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, our natural gas midstream gross margin and operating income in 2010 would increase or decrease by $11.5 million. This assumes that natural gas prices, crude oil prices and inlet volumes remain constant at anticipated levels. These estimated changes in our gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of December 31, 2009, we had $620.1 million of outstanding indebtedness under our Revolver, which carries a variable interest rate throughout its term. We entered into the Interest Rate

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Swaps to establish fixed interest rates on a portion of the outstanding indebtedness under our Revolver. Until March 2010, the notional amounts of the Interest Rate Swaps total $310.0 million, or 50.0% of our outstanding indebtedness under our Revolver as of December 31, 2009, with us 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 Interest Rate Swaps total $250.0 million, or 40.3% of our outstanding indebtedness under our Revolver as of December 31, 2009, with us 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, or 16.1% of our outstanding indebtedness under our Revolver as of December 31, 2009, with us 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 Interest Rate Swaps extend one year past the current maturity of our Revolver. A 1% increase in short-term interest rates on the floating rate debt outstanding under our Revolver (net of amounts fixed through the Interest Rate Swaps) as of December 31, 2009 would cost us approximately $3.1 million in additional interest expense per year.

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. Therefore, 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. Please read Note 6 to our consolidated financial statements included elsewhere in this prospectus supplement for a further description of our derivatives program.

Customer Credit Risk

We are exposed to the credit risk of our customers and lessees. Approximately 84%, or $69.3 million, of our consolidated accounts receivable at December 31, 2009 resulted from our natural gas midstream segment and approximately 16%, or $13.0 million, resulted from our coal and natural resource management segment. Approximately $11.6 million of the natural gas midstream segment’s receivables at December 31, 2009 related to one customer, Tenaska Marketing Ventures. At December 31, 2009, 17% of our natural gas midstream segment accounts receivable and 14% of our consolidated accounts receivable related to this natural gas midstream customer. No significant uncertainties related to the collectability of amounts owed to us exist in regard to this natural gas midstream customer.

This customer concentration increases our exposure to credit risk on our receivables, since the financial insolvency of this customer 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 December 31, 2009, no receivables were collateralized, and we had recorded a $1.2 million allowance for doubtful accounts in the natural gas midstream segment.

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BUSINESS

General

Penn Virginia Resource Partners, L.P. (NYSE: PVR) is a publicly traded Delaware limited partnership formed in 2001 by Penn Virginia Corporation (NYSE: PVA) that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. Both in our current limited partnership form and in our previous corporate form, we have managed coal properties since 1882. We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream. In the year ended December 31, 2009, we generated operating income of $108.3 million and Adjusted EBITDA of $184.8 million. Please read “Selected Historical Financial and Operating Data—Non-GAAP Financial Measures” for a reconciliation of Adjusted EBITDA to net income and cash flows from operating activities. In the year ended December 31, 2009, our coal and natural resource management segment contributed $87.5 million, or 81%, to operating income, and our natural gas midstream segment contributed $20.8 million, or 19%, to operating income.

Coal and Natural Resource Management Segment

Our coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. We do not operate any mines, and therefore we do not have direct exposure to mine operating costs or risks or mine reclamation costs. Coal royalties accounted for 83% of our coal and natural resource management segment revenues in the year ended December 31, 2009. We also earn 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, which accounted for 17% of our coal and natural resource management segment revenues for the year ended December 31, 2009. We have relatively low maintenance capital expenditures that are associated with our coal and natural resource management activities.

As of December 31, 2009, we owned or controlled approximately 829 million tons of proven and probable coal reserves in Central and Northern Appalachia, the Illinois Basin and the San Juan Basin.

In the year ended December 31, 2009, our coal and natural resource management operating income was $87.5 million. In the year ended December 31, 2009, our lessees produced 34.3 million tons of coal from our properties and paid us coal royalties revenues of $120.4 million, for an average royalty per ton of $3.51 ($3.34 per ton net of coal royalties expense).

Approximately 82% of our coal royalties revenues in 2009 were derived from coal mined on our properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. However, because our lessees generally sell their coal under long-term contracts (one to five years), payments from these operators are not directly subject to short-term fluctuations in commodity prices. The balance of our coal royalties revenues in 2009 was derived from coal mined on our properties under leases containing fixed royalty rates that escalate annually.

Natural Gas Midstream Segment

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of December 31, 2009, we owned and operated natural gas midstream

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assets located in Oklahoma and Texas, including six natural gas processing facilities having 400 MMcfd of total capacity and approximately 4,118 miles of natural gas gathering pipelines. Our 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. In addition, we own a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin.

We have recently entered into an agreement with a subsidiary of Range to construct and operate gas gathering and pipeline compression facilities servicing Range’s Marcellus Shale natural gas production located primarily in Lycoming County, Pennsylvania. Our total capital investment in this system is anticipated to range from $170 to $200 million through 2015. We expect that in the fourth quarter of 2010, the initial phase of gathering and compression facilities will become operational. Revenue from this contract will be 100% fee-based. Please read “—PVR Midstream Agreement with Range Resources.”

Our 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. We also own 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 2009, system throughput volumes at our processing plants and gathering systems, including gathering only volumes, were 121.3 Bcf, or approximately 332 MMcfd.

PVR Midstream Agreement with Range Resources

On March 10, 2010, PVR Midstream entered into an agreement with a subsidiary of Range to construct and operate gas gathering pipelines and compression facilities servicing Range’s Marcellus Shale natural gas production primarily in Lycoming County, Pennsylvania.

PVR Midstream and Range have agreed to an area of mutual interest, or AMI, that covers parts of Lycoming, Tioga and Bradford Counties in north central Pennsylvania, in which Range currently holds a substantial acreage position. Within this AMI, PVR Midstream will construct approximately 16 miles of 24- and 30-inch gathering trunklines, smaller-diameter field gathering lines and compression facilities required to gather Range’s production from the AMI. The gathering system is expected to have over 700 MMcfd of throughput capacity, and the initial phase is expected to become operational in the fourth quarter of 2010. The agreement provides Range significant firm gathering capacity in the system, and PVR Midstream will be compensated for the gathering and compression services provided to Range through a combination of firm reservation charges and additional fees based on delivered volumes, with no direct commodity exposure. Excess capacity on the system and the location within a core area of Marcellus Shale development may provide opportunities for PVR Midstream to develop additional revenue by providing gathering and compression services to other third-party producers in the area.

PVR Midstream’s total capital investment in this system is anticipated to range from $170 to $200 million and is expected to be expended between 2010 and 2015, with $35 to $40 million planned for 2010.

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PVR Midstream Agreement to Construct Gas Gathering and Compression Facilities

On March 1, 2010, PVR Midstream entered into an agreement to construct and operate gas gathering pipelines and compression facilities servicing a private firm’s Marcellus Shale natural gas production in Wyoming County, Pennsylvania. Pursuant to the terms of the agreement, PVR Midstream will construct a 12-inch gathering pipeline and compression facilities with 25 MMcfd of throughput capacity and the potential for additional system extensions. PVR Midstream’s 2010 capital investment in this system is anticipated to range from $6 to $7 million, with potential future system extensions costing up to $10 million.

Business Strategies

Our primary business objective is to create sustainable, capital-efficient growth in cash available for distribution to our unitholders while maintaining a strong credit profile and financial flexibility by pursuing the following business strategies:

• Expand our natural gas midstream operations by adding new production to existing systems and acquiring or building new gathering and processing assets.We continually seek new supplies of natural gas both to offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and by contracting for natural gas that has been released from competitors’ systems. During 2009, we acquired a 60 MMcfd processing plant and residue pipeline facilities in western Oklahoma. Additionally, we completed a 40 MMcfd processing plant expansion in our Panhandle system. In March 2010, we entered into an agreement with a subsidiary of Range to construct and operate gas gathering and compression facilities servicing Range’s gas production in the Marcellus Shale formation.

• Continue to grow coal reserve holdings through acquisitions and investments in our existing market areas.We expect to continue to add to our coal reserve holdings in Central Appalachia and the Illinois Basin in the future, but may consider the acquisition of reserves outside of these basins if the market and quality of the reserves satisfy our criteria. We have historically operated in Central Appalachia, our largest area of coal reserves, but we view the Illinois Basin as a growth area, both because of its proximity to power plants and because we expect future environmental regulations will require the scrubbing of most coals, and not just the higher sulfur coal that is typically found in this basin. We will consider acquisitions of coal reserves that are long-lived and that are of sufficient size to yield significant production or serve as a platform for complementary acquisitions.

• Mitigate commodity price exposure in our natural gas midstream segment.Our natural gas midstream operations consist of a mix of fee-based and margin-based services that, together with our hedging activities, are expected to generate relatively stable cash flows. During the quarter ended December 31, 2009, approximately 19% of the system throughput volumes in our natural gas midstream segment were gathered or processed under fee-based contracts. Our Marcellus Shale project with Range, when operational, will generate fee-based revenues from a combination of firm reservation charges and additional fees based on delivered volumes. Under fee-based contracts, we are not exposed directly to commodity price risk. The remainder of our system throughput volumes were gathered or processed under gas purchase/keep-whole arrangements and percentage-of-proceeds arrangements that are subject to commodity price risk. However,

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we expect to manage our exposure to commodity price risk by entering into hedging transactions. Based upon volumes as of December 31, 2009 and after giving effect to additional hedging agreements we entered into on March 29, 2010, we have entered into hedging agreements covering approximately 58% and 56% of our commodity price-sensitive volumes in 2010 and 2011. We generally target hedging 50% to 60% of our commodity price-sensitive volumes covering a two-year period.

• Expand in areas that complement our coal royalty business.Coal and timber infrastructure projects typically involve long-lived, fee-based assets that generally produce predictable cash flows. We own a number of coal infrastructure facilities. We also have an equity interest in a coal handling joint venture, which is expected to provide development opportunities for coal-related infrastructure projects. We also own or control approximately 243,000 acres of forestlands in Appalachia, which primarily produce various hardwoods.

Competitive Strengths

We believe we are well positioned to execute our business strategies successfully because of the following competitive strengths:

• Strategically located natural gas midstream assets. Our natural gas midstream assets are primarily located in Oklahoma and the panhandle of Texas, where natural gas reserves are generally characterized as being moderately declining and long-lived, and east Texas, where we believe natural gas exploration, development and production activities present significant opportunities to generate additional system throughput volumes. We expect that in the fourth quarter of 2010, we will put into operation the initial phase of gathering and compression facilities in the Marcellus Shale formation. Please read “—PVR Midstream Agreement with Range Resources.” We believe that the Marcellus Shale is one of the most prolific natural gas formations in the United States and that our facilities in Lycoming County, Pennsylvania, once fully operational, will have substantial throughput volumes. We believe that our presence in these regions provides us with a competitive advantage in capturing new supplies of natural gas.

• High quality, diverse and strategically located coal reserves. Our coal reserves cover a range of sulfur and heat content and consist of both steam coal and metallurgical coal that are marketable to a diverse customer base. We believe that our higher sulfur Illinois Basin and Northern Appalachian coal will benefit from the ongoing installation of scrubbers at the power plants supplied by our coal. Our Appalachian coal reserves also include metallurgical grade coal, which commands a market premium compared to other grades of coal. In addition, our coal reserves are primarily located on or near major coal hauling railroads and inland waterways that serve Central Appalachia and the Illinois Basin. We believe that this geographic location of our coal reserves gives our lessees a transportation cost advantage to their domestic customers. We also believe that our Appalachian coal reserves are well situated to capitalize on the current favorable export market given their geographical proximity to East Coast ports, which provide access to transoceanic shipments.

• Coal royalty structure that maintains stable and predictable coal-related cash flows and limits exposure to coal mining operational and regulatory costs. Our coal leases, which are

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generally 10 to 15 years in duration, provide either for royalty rates equal to the higher of a fixed minimum rate or a percentage of the gross sales price received by our lessees for the coal they produce from our reserves or for a fixed royalty rate. This structure allows our earnings and cash flow to be stable and predictable in periods of low coal prices, while enabling us to benefit during periods of high coal prices. We also indirectly benefit from the long-term fixed price coal sales contracts our lessees have with their end users, which we believe are typically one to five years in duration, because the royalty rates our lessees pay to us will be fixed during the terms of those contracts. In addition, because we do not operate any mines, we do not directly bear any operational or regulatory costs, such as environmental or occupational health and safety costs and liabilities.

• Broad range of services and long-term contracts and relationships with active natural gas producers. Our natural gas supply strategy for our natural gas midstream segment is to establish long-term, integrated and comprehensive midstream services to our natural gas producers. We provide natural gas gathering, compression, dehydration, treating, processing and marketing and NGL fractionation services to natural gas producers. We believe our ability to provide this broad range of services gives us an advantage in competing for new supplies of natural gas because we can provide all of the services producers require to connect their natural gas quickly and efficiently. We have long-term contracts with many of the most active producers in the areas served by our natural gas midstream assets.

• Experienced coal mine operator lessees that have long-term relationships with a diverse group of major customers. We lease our coal reserves principally to lessees that we believe have substantial experience as coal mine operators, established reputations in the industry and strong relationships with a diverse group of major electric utilities, independent power producers and other commercial and industrial customers.

• Well positioned to pursue acquisition and expansion opportunities. We have a proven track record of successfully growing our business through organic growth projects and acquisitions of coal and natural resource properties and natural gas midstream assets. Since our initial public offering in October 2001, we have completed numerous accretive acquisitions with an aggregate purchase price of approximately $1.1 billion, and expended approximately $188.9 million on expansion projects. We intend to use all of the net proceeds from this offering to repay a portion of the borrowings outstanding under our Revolver, which will increase our borrowing capacity and provide us with greater flexibility to fund organic growth projects and pursue potential acquisitions as they arise.

• Senior Management Team with Substantial Industry Experience. In connection with Penn Virginia’s ongoing reduction of its limited partner interest in PVG, our general partner has a new chief executive officer and chief financial officer who are not officers of Penn Virginia. William H. Shea, Jr., our new Chief Executive Officer, and Robert B. Wallace, our new Executive Vice President and Chief Financial Officer, bring to their new positions substantial industry experience, including from their prior service in such roles at Buckeye GP LLC, the general partner of a major midstream publicly traded partnership, Buckeye Partners, L.P. (NYSE: BPL). Please read “Management—Our Executive Officers and Directors.” At the same time, our operational management remains unchanged to provide continuity. Our Co-Presidents and Chief Operating Officers of our coal and midstream business segments will continue to operate their respective businesses. Members of our executive management team and the heads of our principal business segments have, on average, 30 years of experience in the industries in which we operate.

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Contracts

Coal and Natural Resource Management Segment

We earn most of our coal royalties revenues under long-term leases that generally require our lessees to make royalty payments to us 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 our coal royalties revenues is earned under long-term leases that require the lessees to make royalty payments to us 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 our leases require the lessee to pay minimum rental payments to us 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 us once coal production commences.

Substantially all of our leases impose obligations on the lessees to diligently mine the leased coal using modern mining techniques, indemnify us for any damages we incur in connection with the lessee’s mining operations, including any damages we 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 our written consent prior to assigning the lease and maintain commercially reasonable amounts of general liability and other insurance. Substantially all of the leases grant us 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 us the right to terminate the lease and take possession of the leased premises.

In addition, we earn revenues under coal services contracts, timber contracts and oil and gas leases. Our coal services contracts generally provide that the users of our coal services pay us a fixed fee per ton of coal processed at our facilities. All of our coal services contracts are with lessees of our coal reserves, and these contracts generally have terms that run concurrently with the related coal lease. Our timber contracts generally provide that the timber companies pay us a fixed price per thousand board feet of timber harvested from our property. We receive royalties under our oil and gas leases based on a percentage of the revenues the producers receive for the oil and gas they sell.

Natural Gas Midstream Segment

Our 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 year ended December 31, 2009, our 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. For the fourth quarter of 2009, approximately 28% of our system throughput volumes were gathered or processed under gas purchase/keep-whole contracts, 53% were gathered or processed under percentage-of-proceeds contracts and 19% 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.

In 2009, 21%, 15% and 10% of our natural gas midstream segment revenues and 17%, 11% and 8% of our total consolidated revenues resulted from three of our natural gas midstream customers, Conoco, Inc., Tenaska Marketing Ventures and ONEOK Energy Marketing.

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Gas Purchase/Keep-Whole Arrangements. Under gas purchase/keep-whole arrangements, we generally purchase 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). We then gather the natural gas to one of our plants where it is processed to extract the entrained NGLs, which are then sold to third parties at market prices. We resell 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, we retain a reduced volume of gas to sell after processing. Accordingly, under these arrangements, our revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and our revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. We have generally been able to mitigate our exposure in the latter case by requiring the payment under many of our gas purchase/keep-whole arrangements of minimum processing charges which ensure that we receive a minimum amount of processing revenues. The gross margins that we realize 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, we generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit 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, our revenues and gross margins increase as natural gas prices and NGL prices increase, and our revenues and gross margins decrease as natural gas prices and NGL prices decrease.

Fee-Based Arrangements. Under fee-based arrangements, we receive fees for gathering, compressing and/or processing natural gas. The revenues we earn from these arrangements are directly dependent on the volume of natural gas that flows through our systems and are independent of commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these arrangements would be reduced due to the related reduction in drilling and development of new supply.

In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our 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.We are 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 Panhandle Eastern Pipeline and at market hubs accessed by various interstate pipelines. Connect Energy Services, LLC, or Connect Energy, our wholly owned subsidiary, has earned fees from Penn Virginia Oil & Gas, L.P., or PVOG LP, a wholly owned subsidiary of Penn Virginia, 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 we do not expect it to have an impact on our tax status, as it does not represent a significant percentage of our operating income. For the years ended December 31, 2009 and 2008, natural gas marketing activities generated $1.8 million and $5.8 million in net revenues.

Commodity Derivative Contracts. We utilize collar derivative contracts to hedge against the variability in our frac spread. Our frac spread is the spread between the purchase price for the

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natural gas we purchase from producers and the sale price for NGLs that we sell after processing. We hedge against the variability in our 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.

Please read Note 6 to our consolidated financial statements included elsewhere in this prospectus supplement for a further description of our derivatives program.

Coal Reserves and Production

As of December 31, 2009, we owned or controlled approximately 829 million tons of proven and probable coal reserves located on approximately 497,000 acres (including fee and leased acreage) in Illinois, Kentucky, New Mexico, Virginia and West Virginia. Our 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 our 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 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 coal reserves, is high enough to assume continuity between points of observation.

In areas where geologic conditions indicate potential inconsistencies related to coal reserves, we perform 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 our coal reserves are high in energy content, low in sulfur and suitable for either the steam or to a lesser extent metallurgical market.

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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.

Our lessees mine coal using both underground and surface methods. As of December 31, 2009, our lessees operated 34 surface mines and 41 underground mines. Approximately 52% of the coal produced from our properties in 2009 came from underground mines and 48% came from surface mines. Most of our lessees use the continuous mining method in their underground mines located on our properties. In continuous mining, main airways and transportation entries are developed and remote-controlled continuous miners extract coal from “rooms,” leaving “pillars” to support the roof. Shuttle cars transport coal to a conveyor belt for transportation to the surface. In several underground mines, our lessees use two continuous miners running at the same time, also known as a supersection, to improve productivity and reduce unit costs.

One of our lessees uses the longwall mining method at two different mines to mine underground reserves. Longwall mining uses hydraulic jacks or shields, varying from four feet to twelve feet in height, to support the roof of the mine while a mobile cutting shearer advances through the coal. Chain conveyors then move the coal to a standard deep mine conveyor belt system for delivery to the surface. Continuous mining is used to develop access to long rectangular panels of coal that are mined with longwall equipment, allowing controlled caving behind the advancing machinery. Longwall mining is typically highly productive when used for large blocks of medium to thick coal seams.

Surface mining methods used by our lessees include auger and highwall mining to enhance production, improve reserve recovery and reduce unit costs. On our San Juan Basin property, a combination of the dragline and truck-and-shovel surface mining methods is used to mine the coal. Dragline and truck-and-shovel mining uses large capacity machines to remove overburden to expose the coal seams. Wheel loaders then load the coal in haul trucks for transportation to a loading facility.

Our lessees’ customers are primarily electric utilities, also referred to as “steam” markets. Coal produced from our properties is transported by rail, barge and truck, or a combination of these means of transportation. Coal from the Virginia portion of the Wise property and the Buchanan property is primarily shipped to electric utilities in the Southeast by the Norfolk Southern railroad. Coal from the Kentucky portion of the Wise property is primarily shipped to electric utilities in the Southeast by the CSX railroad. Coal from the Coal River and Spruce Laurel properties in West Virginia is shipped to steam and metallurgical customers by the CSX railroad, by barge along the Kanawha River and by truck or by a combination thereof. Coal from the Northern Appalachia properties is shipped by barge on the Monongahela River, by truck and by the CSX and Norfolk Southern railroads. Coal from the Illinois Basin properties is shipped by barge on the Green River and by truck. Coal from the San Juan Basin property is shipped to steam markets in New Mexico and Arizona by the Burlington Northern Santa Fe railroad. All of our properties contain and have access to numerous roads and state or interstate highways.

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The following table shows our most important coal producing seams by property at December 31, 2009:

Area	Property	State	Producing Mine Types	Seam Name	Height Range (ft.)
Central Appalachia	Wise	VA, KY	Surface, Underground	Parsons	1.00–6.00
				Phillips	1.50–6.00
				Low Splint	1.00–5.50
				Taggart/Marker	1.50–9.00
				U. Wilson	1.50–5.50
				Kelly/Imboden	1.00–7.50
	Buchanan	VA	Underground	Hagy	2.50–3.50
	Wayland	KY	Underground	U. Elkhorn No. 2	2.33–4.00
	Coal River, Fields Creek	WV	Surface, Underground	Coalburg	1.00–11.00
				Winifrede	1.00–6.50
				Cedar Grove	1.00–5.50
				No. 2 Gas	1.50–8.00
	Alloy	WV	Underground	Powellton	2.50–4.50
	Coal River, Cabin Creek	WV	Surface	Coalburg	1.00–5.00
				Buffalo Creek	1.00–5.50
				Winifrede	1.00–10.00
	Coal River, West Coal River	WV	Surface, Underground	Stockton	4.00–12.00
				No. 2 Gas	2.50–4.00
	Huff Creek/Toney Fork	WV	Surface	Coalburg	5.00–16.00
			Underground	Chilton	3.00–4.00
			Underground	U. Alma	3.00–4.00
	Powell Mountain	VA, KY	Surface, Underground	Splint Seams	2.00–2.75
			Underground	Darby	2.50–3.00
Northern Appalachia	Federal No 2	WV	Underground	Pittsburgh	6.50–9.50
	Upshur		Surface	Pittsburgh	3.00–6.50
Illinois Basin	Green River	KY	Surface, Underground	KY No. 9	3.00–5.00
	Allied	KY	Underground	KY No. 9	3.00–5.00
San Juan Basin	Lee Ranch	NM	Surface	Cleary Seams	8.00–16.00

The following tables set forth production data for the periods presented and reserve information with respect to each of our regions for the period presented (tons in millions):

	Production for Year Ended December 31,
Region	2009	2008	2007
Central Appalachia	18.3	19.6	18.8
Northern Appalachia	3.8	3.6	4.2
Illinois Basin	4.7	4.6	3.8
San Juan Basin	7.5	5.9	5.7
Total	34.3	33.7	32.5

	Proven and Probable Coal Reserves as of December 31, 2009
Region	Underground	Surface	Total	Steam	Metallurgical	Total
Central Appalachia	443.6	160.3	603.9	514.7	89.2	603.9
Northern Appalachia	23.4	—	23.4	23.4	—	23.4
Illinois Basin	154.2	9.7	163.9	163.9	—	163.9
San Juan Basin	—	37.4	37.4	37.4	—	37.4
Total	621.2	207.4	828.6	739.4	89.2	828.6

Of the approximately 829 million tons of proven and probable coal reserves to which we had rights as of December 31, 2009, we owned the mineral interests and the related surface rights to

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454.2 million tons, or 53%, and we owned only the mineral interests to 189.6 million tons, or 24%. We leased the mineral rights to the remaining 184.8 million tons, or 23%, from unaffiliated third parties and, in turn, subleased these reserves to our lessees. For the reserves we lease from third parties, we pay royalties to the owner based on the amount of coal produced from the leased reserves. Additionally, in some instances, we purchase surface rights or otherwise compensate surface right owners for mining activities on their properties. In 2009, our aggregate expenses to third-party surface and mineral owners were $5.8 million.

The following table sets forth the coal reserves we owned and leased with respect to each of our coal properties as of December 31, 2009 (tons in millions):

Property	Owned	Leased	Total Controlled
Central Appalachia	452.9	151.0	603.9
Northern Appalachia	23.4	—	23.4
Illinois Basin	133.9	30.0	163.9
San Juan Basin	33.6	3.8	37.4
Total	643.8	184.8	828.6

The following table sets forth our coal reserve activity for the periods presented and ended (tons in millions):

	2009		2008		2007
Reserves – beginning of year	826.8		818.4		765.4
Purchase of coal reserves	2.4		34.6		60.0
Tons mined by lessees	(34.3	)	(33.7	)	(32.5	)
Revisions of estimates and other	33.7		7.5		25.5
Reserves – end of year	828.6		826.8		818.4

Our coal reserve estimates are prepared from geological data assembled and analyzed by our general partner’s or its affiliates’ geologists and engineers. These estimates are compiled using geological data taken from thousands of drill holes, geophysical logs, adjacent mine workings, outcrop prospect openings and other sources. These estimates also take into account legal, qualitative, technical and economic limitations that may keep coal from being mined. Coal reserve estimates will change from time to time due to mining activities, analysis of new engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods and other factors.

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We classify low sulfur coal as coal with a sulfur content of less than 1.0%, medium sulfur coal as coal with a sulfur content between 1.0% and 1.5% and high sulfur coal as coal with a sulfur content of greater than 1.5%. Compliance coal is that portion of low sulfur coal that meets compliance standards for the CAA. As of December 31, 2009, approximately 25% of our reserves met compliance standards for the CAA and 37% were low sulfur. The following table sets forth our estimate of the sulfur content and the typical clean coal quality of our recoverable coal reserves for the period presented (tons in millions):

		Sulfur Content					Typical Clean Coal Quality
		Reserves as of December 31, 2009					Heat Content
Property	Compliance(1)	Low Sulfur(2)	Medium Sulfur	High Sulfur	Sulfur Unclassified	Total	BTU per Pound(3)	Sulfur (%)	Ash (%)
Central Appalachia	203.1	283.0	205.4	106.9	8.6	603.9	14,041	1.04	6.50
Northern Appalachia	—	—	—	23.4	—	23.4	12,900	2.58	8.80
Illinois Basin	—	—	—	163.9	—	163.9	11,034	2.39	8.32
San Juan Basin	—	22.1	11.5	3.8	—	37.4	9,200	0.89	17.80
Total	203.1	305.1	216.9	298.0	8.6	828.6

(1) Compliance coal is low sulfur coal which, when burned, emits less than 1.2 pounds of sulfur dioxide per million BTU. Compliance coal meets the sulfur dioxide emission standards imposed by Phase II of the CAA without blending in other coals or using sulfur dioxide reduction technologies. Compliance coal is a subset of low sulfur coal and is, therefore, also reported within the amounts for low sulfur coal.

(2) Includes compliance coal.

(3) As-received BTU per pound includes the weight of moisture in the coal on an as sold basis.

The following table shows the proven and probable coal reserves we leased to mine operators by property for the period presented (tons in millions):

	Proven and Probable Coal Reserves As of December 31, 2009
Property	Total Controlled	Leased to Operators	Percentage Leased
Central Appalachia	603.9	540.2	89	%
Northern Appalachia	23.4	23.0	98	%
Illinois Basin	163.9	111.5	68	%
San Juan Basin	37.4	37.4	100	%
Total	828.6	712.1	86	%

Other Natural Resource Management Assets

Coal Preparation and Loading Facilities

We generate coal services revenues from fees we charge to our lessees for the use of our 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 our reserves.

Timber and Oil and Gas Royalty Interests

We own approximately 243,000 acres of forestland in Kentucky, Virginia and West Virginia. The majority of our forestland is located on properties that also contain our coal reserves.

We own royalty interests in approximately 7.2 Bcfe of proved oil and gas reserves located in Kentucky, Virginia and West Virginia. Approximately 86% of our oil and gas royalty interests in these reserves are associated with properties acquired from Penn Virginia in 2007.

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Natural Gas Midstream Systems

Our 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.

We own, lease or have rights-of-way to the properties where the majority of our natural gas midstream facilities are located. We also own 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.

We owned six natural gas processing facilities having 400 MMcfd of total capacity as of December 31, 2009. Our 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 4,118 miles of natural gas gathering pipelines as of December 31, 2009.

The following table sets forth information regarding our natural gas midstream assets at and for the year ended December 31, 2009:

Asset	Type	Approximate Length (Miles)	Current Processing Capacity (MMcfd)	Average System Throughput (MMcfd)
Panhandle System	Gathering pipelines and processing facilities	1,681	260	224	(1)
Crossroads System	Gathering pipelines and processing facility	8	80	47
Crescent System	Gathering pipelines and processing facility	1,701	40	22
Hamlin System	Gathering pipelines and processing facility	516	20	8
Arkoma System	Gathering pipelines	78	—	13
North Texas Gas Gathering System	Gathering pipelines	134	—	18
Total		4,118	400	332

(1) Includes gas processed at other systems connected to the Panhandle System.

In addition, the Thunder Creek joint venture, in which we own a 25% member interest, had gathering pipelines of approximately 558 miles in length and 375 MMcfd of average system throughput at and for the year ended December 31, 2009.

Panhandle System

General. The Panhandle System is a natural gas gathering system stretching over ten counties in the Anadarko Basin of the panhandle of Texas and Oklahoma. The system consists of approximately

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1,681 miles of natural gas gathering pipelines, ranging in size from two to 16 inches in diameter, and the Beaver, Spearman and Sweetwater natural gas processing plants. Included in the system is an 11-mile, 10-inch diameter, FERC-jurisdictional residue line.

In July 2009, we completed an acquisition of a natural gas processing and residue pipeline facilities in western Oklahoma for approximately $22.6 million in cash. The acquired assets included a 60 MMcfd gas processing plant located near Sweetwater, Oklahoma (the “Sweetwater” plant). Additionally, we completed a 40 MMcfd processing plant expansion in our Spearman complex that was put into service on July 31, 2009. The acquired and expanded processing facilities increased our processing capacity in the Panhandle System to 260 MMcfd. The increased processing capacity has allowed us to process gas volumes that were being bypassed due to processing capacity constraints in the Panhandle System and has alleviated pipeline pressure-related volume constraints in the eastern portion of the Panhandle System.

The Panhandle System is comprised of a number of major gathering systems and 26 related compressor stations that gather natural gas, directly or indirectly, to the Beaver, Spearman and Sweetwater plants. These include the Beaver, Perryton, Spearman, Wolf Creek/Kiowa Creek and Ellis systems. These gathering systems are located in Beaver, Ellis, Harper and Roger Mills Counties in Oklahoma and Hansford, Hemphill, Hutchinson, Lipscomb, Ochiltree and Roberts Counties in Texas.

The Beaver plant has 100 MMcfd of inlet gas capacity. The plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation of up to 16 hours per day.

The Spearman plant has 100 MMcfd of inlet capacity. The plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation of up to 16 hours per day.

The Sweetwater plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation of up to 16 hours per day.

In conjunction with the acquisition of the Sweetwater plant, two new gas compressor stations were installed; one is located on the east end of the North Canadian pipeline and the other on the east end of the Hemphill pipeline.

Natural Gas Supply and Markets for Sale of Natural Gas and NGLs. The supply in the Panhandle System comes from approximately 203 producers pursuant to 332 contracts. The residue gas from the Beaver plant can be delivered into the Northern Natural Gas, Southern Star Central Gas or ANR Pipeline Company pipelines for sale or transportation to market. The NGLs produced at the Beaver plant are delivered into ONEOK Hydrocarbon’s pipeline system for transportation to and fractionation at ONEOK’s Conway fractionator.

The residue gas from the Spearman plant is delivered into Northern Natural Gas pipelines for sale or transportation to market. The NGLs produced at the Spearman plant are delivered into Enterprise’s pipeline system. Enterprise’s pipeline system has the flexibility of delivering the NGLs to either Mont Belvieu or Conway for fractionation.

The residue gas from the Sweetwater plant is delivered into Northern Natural Gas pipelines for sale or transportation to market. The NGLs produced at the Sweetwater plant are delivered into ONEOK Hydrocarbon’s pipeline system for transportation to and fractionation at ONEOK’s Conway fractionator.

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Crossroads System

General. The Crossroads System is a natural gas gathering system located in the southeast portion of Harrison County, Texas. The Crossroads System consists of approximately eight miles of natural gas gathering pipelines, ranging in size from eight to twelve inches in diameter, and the Crossroads plant. The Crossroads System also includes approximately 20 miles of six-inch NGL pipeline that transport the NGLs produced at the Crossroads plant to the Panola Pipeline.

The Crossroads plant has 80 MMcfd of inlet capacity. The plant is capable of operating in high ethane recovery mode or in ethane rejection mode and has instrumentation allowing for unattended operation of up to 16 hours per day.

Natural Gas Supply and Markets for Sale of Natural Gas and NGLs. The natural gas on the Crossroads System originates from the Bethany Field from where we have contracted with five producers. The Crossroads System delivers the residue gas from the Crossroads plant into the CenterPoint Energy pipeline for sale or transportation to market. The NGLs produced at the Crossroads plant are delivered into the Panola Pipeline for transportation to Mont Belvieu, Texas for fractionation.

Crescent System

General. The Crescent System is a natural gas gathering system stretching over seven counties within central Oklahoma’s Sooner Trend. The system consists of approximately 1,701 miles of natural gas gathering pipelines, ranging in size from two to 10 inches in diameter, and the Crescent natural gas processing plant located in Logan County, Oklahoma. Fifteen compressor stations are operating across the Crescent System.

The Crescent plant is a NGL recovery plant with current capacity of approximately 40 MMcfd. The Crescent facility also includes a gas engine-driven generator which is routinely operated, making the plant self-sufficient with respect to electric power. The cost of fuel (residue gas) for the generator is borne by the producers under the terms of their respective gas contracts.

Natural Gas Supply and Markets for Sale of Natural Gas and NGLs. The gas supply on the Crescent System is primarily gas associated with the production of oil or “casinghead gas” from the mature Sooner Trend. Wells in this region producing casinghead gas are generally characterized as low volume, long-lived producers of gas with large quantities of NGLs. The supply in the Crescent System comes from approximately 256 producers pursuant to 411 contracts. The Crescent plant’s connection to the Enogex and ONEOK Gas Transportation pipelines for residue gas and the ONEOK Hydrocarbon pipeline for NGLs gives the Crescent System access to a variety of market outlets.

Hamlin System

General. The Hamlin System is a natural gas gathering system stretching over eight counties in West Central Texas. The system consists of approximately 516 miles of natural gas gathering pipelines, ranging in size from two to 12 inches in diameter and with current capacity of approximately 20 MMcfd, and the Hamlin natural gas processing plant located in Fisher County, Texas. Eight compressor stations are operating across the system.

Natural Gas Supply and Markets for Sale of Natural Gas and NGLs. The gas on the Hamlin System is primarily gas associated with the production of oil or “casinghead gas.” The supply on the Hamlin System comes from approximately 143 producers pursuant to 114 contracts. The Hamlin System delivers the residue gas from the Hamlin plant into the Enbridge or Atmos pipelines. The NGLs produced at the Hamlin plant are delivered into Enterprise’s pipeline system.

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North Texas System

General. The North Texas assets are located in the southern portion of the Fort Worth Basin of North Texas and include approximately 134 miles of gas gathering pipelines and approximately 240,000 acres dedicated by active producers. This expands the geographic scope of the natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin.

Natural Gas Supply. The gathering and transportation infrastructure captures current and expected volumes in Johnson, Hill, Bosque, Somervell, Hamilton and Erath counties. We averaged 18 MMcfd in gathered volumes during 2009.

Facilities

We currently lease our office space in Radnor, Pennsylvania, Dallas and Houston, Texas as well as Kingsport, Tennessee. We own the field office in Charleston, West Virginia. We believe that our properties are adequate for our current needs.

Partnership Structure

Penn Virginia, a publicly held energy company, has been engaged in the coal royalty business since 1882 and is also engaged in the exploration, development and production of natural gas and oil. Penn Virginia formed us as a Delaware limited partnership in July 2001 to own and operate substantially all of the assets of and assume the liabilities relating to Penn Virginia’s coal land management business. We completed our initial public offering in October 2001. Penn Virginia continues to hold a significant interest in us through its indirect25.8% interest in PVG.

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our subsidiaries through a wholly owned subsidiary, PVR Finco LLC, which is the sole member of the operating company for the coal and natural resource management segment, Penn Virginia Operating Co., LLC, or PVR Coal, and the operating company for the natural gas midstream segment, PVR Midstream. Please read “Prospectus Supplement Summary—Summary Partnership Structure.”

Relationship with Penn Virginia Corporation

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Under an omnibus agreement between us, Penn Virginia and our general partner, Penn Virginia and its affiliates, including PVG and our general partner, are restricted in their ability to engage in any coal-related business. Please read “Certain Relationships and Related Transactions, and Director Independence—Transactions with Related Persons.”

Partnership Distributions

Cash Distributions

We paid cash distributions of $1.88 per common unit during the year ended December 31, 2009. In the first quarter of 2010, we paid a cash distribution of $0.47 ($1.88 on an annualized basis) per common unit with respect to the fourth quarter of 2009. This distribution was unchanged from the previous distribution paid on November 13, 2009. For the remainder of 2010, we expect to pay quarterly cash distributions of at least $0.47 ($1.88 on an annualized basis) per common unit.

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The following table reflects the allocation of total cash distributions paid by us during the years ended December 31, 2009, 2008 and 2007 (in thousands, except per unit information):

	Year Ended December 31,
	2009		2008		2007
Limited partner units	$	97,382	$	89,207	$	76,536
General partner interest (2%)		1,988		1,820		1,562
Incentive distribution rights		24,140		20,049		11,551
Phantom units		499		—		—
Total cash distributions paid	$	124,009	$	111,076	$	89,649
Total cash distributions paid per limited partner unit	$	1.88	$	1.82	$	1.66

Incentive Distribution Rights

In accordance with our partnership agreement, incentive distribution rights, or IDRs, 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. The minimum quarterly distribution is $0.25 ($1.00 on an annualized basis) per unit. Our general partner currently holds 100% of the IDRs, 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 our general partner with or into such entity or the transfer of all or substantially all of our general partner’s assets to another entity without the prior approval of our unitholders if the transferee agrees to be bound by the provisions of our partnership agreement. Prior to September 30, 2011, other transfers of the IDRs will require the affirmative vote of holders of a majority of the outstanding common units. On or after September 30, 2011, the IDRs will be freely transferable. The IDRs are payable as follows:

If for any quarter:

• we have distributed available cash from operating surplus to our common unitholders in an amount equal to the minimum quarterly distribution; and

• we have 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, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

• First, 98% to all unitholders, and 2% to our 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 our 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 our 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 our general partner.

Since 2001, we have increased our 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 our most recently

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declared distribution. These increased cash distributions have placed our general partner at the maximum target cash distribution level as described above and, as a consequence, since reaching such level, our general partner has received 50% of available cash in excess of $0.375 per unit.

Subordinated Units

Until May 22, 2007, we had Class B units, a separate class of subordinated units representing limited partner interests in us that were issued to PVG in connection with PVG’s initial public offering. On May 22, 2007, all of our Class B units automatically converted into common units on a one-for-one basis and no Class B units remain outstanding.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner has the right, which it may assign in whole or in part to any of its affiliates or us, but not the obligation, to acquire all of the remaining common units held by unaffiliated persons as of a record date to be selected by our general partner, on at least ten but not more than 60 days’ notice, at a price equal to the greater of (i) the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed.

As a result of this right of our general partner, a holder of common units may have his or her common units purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his or her units in the market.

As of April 12, 2010, PVG owned 19,587,049 common units, representing approximately 37% of our outstanding common units.

Certain Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Penn Virginia and PVG), on the one hand, and us and our unitholders, on the other hand. Our general partner is owned by PVG. Penn Virginia owns a25.8% limited partner interest and the non-economic general partner interest in PVG. PVG has the ability to appoint and remove three of the six members of our general partner’s board of directors and Penn Virginia accordingly has the indirect right to appoint and remove such board members. The directors of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owner, PVG. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders.

Certain of the non-independent directors and executive officers of our general partner also serve as executive officers and directors of Penn Virginia or PVG GP. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to PVG or Penn Virginia, on the one hand, and us, on the other hand, are in conflict.

Limits on Fiduciary Responsibilities

Our partnership agreement limits the liability and reduces the fiduciary duties owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duty.

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Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement permits our general partner to make a number of decisions in its sole discretion. This entitles our general partner to consider only the interests and factors that it desires and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Other provisions of the partnership agreement provide that our general partner’s actions must be made in its reasonable discretion. These standards reduce the obligations to which our general partner would otherwise be held.

Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be “fair and reasonable” to us under the factors previously set forth. In determining whether a transaction or resolution is “fair and reasonable” our general partner may consider the interests of all parties involved, including its own. Unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty. These standards reduce the obligations to which our general partner would otherwise be held.

In order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Revised Uniform Limited Partnership Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our general partner and those other persons acted in good faith.

We are required by our partnership agreement to indemnify our general partner and its officers, directors, employees, affiliates, partners, members, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by our general partner or these other persons. This indemnification is required if our general partner or any of these persons acted in good faith and in a manner they reasonably believed to be in, or (in the case of a person other than our general partner) not opposed to, our best interests. Indemnification is required for criminal proceedings if our general partner or these other persons had no reasonable cause to believe their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met these requirements concerning good faith and our best interests.

Competition

Coal and Natural Resource Management Segment

The coal industry is intensely competitive primarily as a result of the existence of numerous producers. Our lessees compete with both large and small coal producers in various regions of the United States for domestic sales. The industry has undergone significant consolidation which has led to some of the competitors of our lessees having significantly larger financial and operating resources than most of our lessees. Our 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 our coal and the prices that our lessees obtain are also affected by demand for electricity, demand for metallurgical coal, access to transportation,

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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 our low sulfur coal and the prices our 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 federal Clean Air Act, or CAA, requirements.

Natural Gas Midstream Segment

We experience competition in all of our natural gas midstream markets. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, process, transport and market natural gas. Many of our competitors have greater financial resources and access to larger natural gas supplies than we do.

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 our 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 coal and natural resource management business and 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.

Coal and Natural Resource Management Segment

General Regulation Applicable to Coal Lessees. Our 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, our lessees regularly have on-site inspections and violations during mining operations are not unusual in the industry, notwithstanding compliance efforts by our lessees. However, none of the violations to date, or the monetary penalties assessed, have been material to us or, to our knowledge, to our lessees. Although many new safety requirements have been instituted recently, we do not currently expect that future compliance will have a material adverse effect on us.

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While it is not possible to quantify the costs of compliance by our 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 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 our lessees are contractually liable for all costs relating to their mining operations, including the costs of reclamation and mine closure. However, we do 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 our lessees. The possibility exists that new legislation or regulations may be adopted which have a significant impact on the mining operations of our lessees or their customers’ ability to use coal and may require us, our 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 our business, both directly and indirectly. The CAA directly impacts our 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 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 our lessees’ ability to sell coal, which could have a material effect on our 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 either participate in an EPA-administered “cap-and-trade” program that caps emission in two phases, or by meeting an

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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, intending to propose air toxics standards for coal- and oil-fired electric generating units by March 10, 2011, and finalize a rule by November 16, 2011. In conjunction with these efforts, on December 24, 2009, the EPA approved an Information Collection Request (ICR) requiring all U.S. power plants with coal-or oil-fired electric generating units to submit emissions information for use in developing air toxics emissions standards. 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, our 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

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“hourly rate test” in determining whether a modification to a coal burning 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 our coal could be affected, which could have an adverse effect on our 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 inMassachusetts 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 inMassachusetts 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 inMassachusetts 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. In 2009, the EPA took further steps toward greenhouse gas regulation under the CAA, issuing a final rule declaring that six greenhouse gases, including carbon dioxide and methane, “endanger both the public health and the public welfare of current and future generations.” The issuance of this “endangerment finding” allows the EPA to begin regulating greenhouse gas emissions under existing provisions of CAA. In late September and early October of 2009, in anticipation of the issuance of the endangerment finding, the EPA officially proposed two sets of rules regarding possible future regulation of greenhouse gas emissions under the CAA, one that would regulate greenhouse gas emissions from motor vehicles and the other greenhouse gas emissions from large stationary sources such as power plants or industrial facilities. Any decision in this case or any regulatory action by the EPA limiting greenhouse gas emissions from power plants could impact the demand for our coal, which could have an adverse effect on our 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.

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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 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 the 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. However, Arizona has stated more recently that it does not intend to endorse or participate in any regional cap-and-trade program instituted by the Western Climate Initiative, though it will remain a member of the multistate coalition. 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.

At the federal level, legislation was introduced in Congress in 2007, 2008 and 2009 to reduce greenhouse gas emissions in the United States. Such or similar federal legislation, which generally seeks to place an economy-wide cap on emissions of greenhouse gases and would require most sources of greenhouse gas emissions to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases, could be taken up in 2010 or later years. It is possible that future federal and state initiatives to control and put a price on carbon dioxide emissions, or otherwise regulate greenhouse gas 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

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increased costs for coal consumption could result in some customers switching to alternative sources of fuel, which could negatively impact our lessees’ coal sales, and thereby have an adverse effect on our coal royalties revenues.

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 our coal lessees to another entity such as us if any of our lessees are not financially capable of fulfilling those obligations on the theory that we “owned” or “controlled” the mine operator in such a way for liability to attach. To our knowledge, no such claims have been asserted against us to date. In conjunction with mining the property, our 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 our 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 our lessees’ ability to produce coal, which could affect our 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. We could become liable under federal and state Superfund and waste management statutes if our 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 incurred in connection with such response. It is not uncommon for neighboring landowners and other third

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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, or CCBs, are not regulated at the federal level and not uniformly at the state level. However, in 2009, the EPA announced that it will consider whether to reclassify CCBs as hazardous waste. As long as CCBs are exempt from regulation as hazardous wastes, it is not anticipated that regulation of CCBs will have any material effect on the amount of coal used by electricity generators. However, if CCBs were re-classified as hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCBs, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

Although a proposed rule regarding the management of CCBs was reportedly delivered by the EPA to the Office of Management and Budget for interagency review in October 2009, as of April 4, 2010, the EPA has not yet published the proposed rule. It is not possible to determine with certainty the potential permitting requirements or performance standards that may be imposed on the disposal of CCBs by future regulations or lawsuits. If rules are adopted to regulate the management and disposal of these CCBs, 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. Our coal lessees’ operations are regulated under the 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 our 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 inRapanos 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”

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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 inOhio 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.

In the event similar lawsuits prove to be successful in adjoining jurisdictions, our 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 our lessees obtaining the required mining permits to conduct their operations, which could in turn have an adverse effect on our 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 caseOhio 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 ours 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 in part 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 our lessees, it could have an adverse effect on our coal royalties

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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 our lessees could adversely impact our 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 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 our lessees in the future.

After theOVEC decision was published in February 2009, however, the EPA undertook several initiatives to address the issuance of 404 permits for coal mining activities in the eastern United States. First, the EPA began to comment on Section 404 permit applications pending before the COE raising many of the same issues decided in favor of the coal industry inOVEC. Many of the EPA’s comment letters were submitted long after the end of the EPA’s comment period based on what the EPA contended was “new” information on the impacts of valley fills on stream water quality immediately downstream of valley fills. These letters have created regulatory uncertainty regarding the issuance of 404 permits for coal mining operations and have substantially expanded the time required for issuance of these permits.

The Corps, the EPA and the Department of the Interior announced an interagency action plan in June 2009 for an “enhanced review” of any project that requires both a SMCRA and a CWA permit designed to reduce the harmful environmental consequences of mountaintop mining in the Appalachian region. As part of this interagency action plan, in July 2009 the Corps proposed to suspend and modify NWP 21 in six Appalachian region states to prohibit its use to authorize discharges of fill material into waters of the U.S. for mountaintop mining. The EPA is also taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia, especially in West Virginia where the EPA plans to review all applications for NPDES permits even though the State of West Virginia is authorized to issue NPDES permits in West Virginia. Indeed, interim final guidance issued by the EPA on April 1, 2010, encourages the EPA Regions 3, 4 and 5 to (i) object to the issuance of state program NPDES permits where the Region does not believe that the proposed permit satisfies the requirements of the CWA, and (ii) exercise a greater degree of oversight with regard to state issued general permits.

The April 1, 2010, interim final guidance also addresses Regions’ involvement in Section 404 permitting decisions. The document urges Regions to undertake a meaningful review of Section 404 permitting decisions in Appalachia, with a focus on verifying that:

• Mining activities will not cause or contribute to violations of water quality standards, contaminate drinking water supplies, add toxic pollutants that kill or impair stream life, or result in significant degradation of the aquatic environment;

• Applicants have evaluated a full range of potential alternatives to discharging into waters of the U.S.;

• Mining companies have avoided and minimized their direct, indirect, and cumulative adverse environmental impacts to streams, wetlands, watersheds, and other aquatic resources; and

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• Remaining mining-related aquatic impacts have been effectively mitigated by establishing, restoring, enhancing, or preserving streams and wetlands; protecting water quality, including drinking water; and reclaiming watersheds when mining is completed.

Should a Region’s review conclude that these factors are insufficient with regard to the proposed permit, the guidance encourages the Region to inform the Corps, the permit applicant, and the state of the results of its review, and if appropriate changes to the permit are not made, “proceed” under either (i) the dispute resolution provisions of the Section 404(q) Memorandum of Agreement or (ii) Section 404(c)’s “veto” power. Of course, this guidance has just been issued and it remains to be seen how it will be applied by the EPA and whether it will be subject to judicial challenge by affected states or private parties.

On March 26, 2010, the EPA announced a proposal to exercise its Section 404(c) “veto” power to withdraw or restrict the use of previously issued permits in connection with the Spruce No. 1 Surface Mine in West Virginia. The Spruce No. 1 Mine is one of the largest surface mining operations ever authorized in Appalachia. Though the project was permitted in 2007, it has been subsequently delayed by litigation. The proposed action would be just the thirteenth instance that the EPA has exercised its Section 404(c) “veto” power, and the first time that such power was exercised with regard to a previously permitted project. Consistent with the focus of the EPA’s April 1, 2010, interim final guidance regarding Section 404 permits, the EPA’s proposed action focuses on water quality impacts, fish and wildlife impacts, mitigation impacts, and cumulative mining impacts of the Spruce No. 1 Mine. More frequent use of the EPA’s Section 404 “veto” power as well as the increased risk of application of this power to previously permitted projects could create uncertainly with regard to our continued use of our current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our ability to obtain permits and produce coal.

These initiatives have extended the time required to obtain permits for coal mining and we anticipate further delays in obtaining permits and that the costs associated with obtaining and complying with those permits will increase substantially. It is possible that some projects may not be able to obtain these permits because of the manner in which these rules are being interpreted and applied. It is also possible that we may be unable to obtain or may experience delays in securing, utilizing or renewing additional Section 404 individual permits for surface mining operations due to agency or court decisions stemming from the above developments. The EPA recently published a guidance regarding the issuance of permits under the CWA for Appalachian Surface Coal Mining Operations that sets forth new interpretations of criteria to be considered by state and agencies and the EPA regional offices in connection with the issuance of permits for coal mining projects in Appalachia. This guidance applies to the issuance of permits under Section 402 and 404 of the CWA and has the effect of setting new standards for discharges from coal mining operations. The requirements of this guidance will certainly increase the time and cost of obtaining new permits, may increase the costs of operating under those permits, and could lead to the rejection of new or renewed permits for certain projects that cannot demonstrate that they will not have any adverse impacts under the new tests set forth in this guidance. As an example of the significance of this guidance, the EPA also published on April 1, 2010 a proposed determination to prohibit, restrict or deny a permit issued under Section 404 to Mingo Logan Coal Company for the discharge of dredged fill in connection with the construction of carious fills and sedimentation ponds.

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

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these stream segments. The adoption of new TMDL-related allocations for streams to which our lessees’ coal mining operations discharge could require more costly water treatment and could adversely affect our 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 our lessees’ ability to develop new mines or could require our lessees to modify existing operations, which could have an adverse effect on our 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 our 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 our 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 our 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 our lessees’ ability to mine coal from our properties in accordance with current mining plans.

Mine Health and Safety Laws. The operations of our 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.

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. Moreover, workplace accidents, such as the April 5, 2010, Upper Big Branch Mine, West Virginia incident, may result in more stringent enforcement as well as the development of new laws and regulations.

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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 our lessees’ operations, particularly for underground mines, and could affect the financial performance of our lessees’ operations.

Implementing and complying with these new laws and regulations could adversely affect our lessees’ coal production and could therefore have an adverse effect on our 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, our 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, our 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 our 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, our lessees submit the necessary permit applications between 12 and 24 months before they plan to begin mining a new area. In our experience, permits generally are approved within 12 months after a completed application is submitted. In the past, our lessees have generally obtained their mining permits without significant delay. Our 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. Our 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. Please read “—Coal and Natural Resource Management Segment—Clean Water Act.”

OSHA. Our lessees and our own business are subject to 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.

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Natural Gas Midstream Segment

General Regulation. Our natural gas gathering facilities generally are exempt from the FERC’s jurisdiction under the Natural Gas Act of 1938, or the NGA, but FERC regulation nevertheless could significantly affect our gathering business and the market for our services. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines into which our 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. Our 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. Our 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 our 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, our 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. Our operations in Oklahoma are regulated by the Oklahoma Corporation Commission, which prohibits us from charging any unduly discriminatory fees for our gathering services. We cannot predict whether our gathering rates will be found to be unjust, unreasonable or unduly discriminatory.

We are 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 our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and Texas and 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. We also operate 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

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requirements. Certain of our 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. Our natural gas midstream operations are subject to the CAA and comparable state laws and regulations. Please read “—Coal and Natural Resource Management Segment—Air Emissions.” These laws and regulations govern emissions of pollutants into the air resulting from the activities of our processing plants and compressor stations and also impose procedural requirements on how we conduct our natural gas midstream operations. Such laws and regulations may include requirements that we 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 we are required to obtain or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We 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. Our 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 we own or operate, regardless of whether such disposal or release occurred during or prior to our acquisition of such properties. Please read “—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,” our 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.

Our 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 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 we believe 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 our facilities.

We currently own or lease numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although we believe 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, we 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

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closure operations to prevent future contamination. We have ongoing remediation projects underway at several sites, but we do not believe that the costs associated with such cleanups will have a material adverse impact on our operations or revenues.

Water Discharges. Our natural gas midstream operations are subject to the CWA. Please read “—Coal and Natural Resource Management Segment—Clean Water Act.” Any unpermitted release of pollutants, including NGLs or condensates, from our systems or facilities could result in fines or penalties as well as significant remedial obligations.

OSHA. Our natural gas midstream operations are subject to OSHA. Please read “—Coal and Natural Resource Management Segment—OSHA.”

Employees and Labor Relations

We do not have employees. To carry out our operations, our general partner and its affiliates employed 167 employees who directly supported our operations at December 31, 2009. Our general partner considers 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. Please read “—Government Regulation and Environmental Matters” for a more detailed discussion of our material environmental obligations.

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MANAGEMENT

Management of Penn Virginia Resource Partners, L.P.

Penn Virginia Resource GP, LLC, or PVR GP, our general partner, manages our operations and activities. Our general partner is a wholly owned subsidiary of PVG, a publicly traded Delaware limited partnership. Penn Virginia owns a25.8% limited partner interest and the non-economic general partner interest in PVG. On March 31, 2010, we and PVG entered into the Fifth Amended and Restated Limited Liability Company Agreement of PVR GP (as so amended, the “PVR GP LLC Agreement”), and PVR GP entered into Amendment No. 2 to the Third Amended and Restated Agreement of Limited Partnership of the Partnership (as amended, the “PVR Partnership Agreement”). Pursuant to the PVR GP LLC Agreement, the number of directors constituting the board of PVR GP is six, consisting of three Class A directors and three Class B directors. Our limited partners, other than PVR GP, PVG and their respective affiliates, have a right to nominate and vote in the election of the three Class A directors to the board of directors of PVR GP. PVG has a right to appoint the three Class B directors to the board of directors of PVR GP. In the event of a tie vote, the board of directors of PVR GP has delegated to Penn Virginia the right to break the tie. The right is subject to termination under certain circumstances.

Our general partner owes a fiduciary duty to our unitholders, but our partnership agreement contains various provisions modifying and restricting the fiduciary duty.

Our Executive Officers and Directors

The following table sets forth information concerning the directors and executive officers of our general partner:

Name	Age	Position with Our General Partner
William H. Shea, Jr.	55	Director and Chief Executive Officer
Edward B. Cloues, II	62	Director
James L. Gardner	58	Director
Thomas W. Hofmann	58	Director
James R. Montague	62	Director
Marsha R. Perelman	59	Director
Robert B. Wallace	48	Executive Vice President and Chief Financial Officer
Nancy M. Snyder	56	Vice President, Chief Administrative Officer and General Counsel
Keith D. Horton	56	Co-President and Chief Operating Officer—Coal
Ronald K. Page	59	Co-President and Chief Operating Officer—Midstream

William H. Shea, Jr. has served as a director and as Chief Executive Officer of our general partner since March 2010. Mr. Shea has also served as a director and as President and Chief Executive Officer of PVG GP since March 2010 and as a director of Penn Virginia 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 partnership, 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. Mr. Shea has an agreement with Riverstone, pursuant to which he has agreed to serve on the boards of Carlyle/Riverstone Funds portfolio companies.

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Edward B. Cloues, II has served as a director of our general partner since January 2003. From January 1998 until April 2010, Mr. Cloues 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 and is the non-executive Chairman of the Board of AMREP Corporation and a director of Hillenbrand Inc.

James L. Gardner has served as a director of our general partner since January 2006. Since 2005, Mr. Gardner has been an Associate Professor of Philosophy at Freed-Hardeman University. From 2002 to 2004, Mr. Gardner served as Executive Vice President and Chief Administrative Officer of Massey Energy Company, or Massey, a coal mining company. From 2000 to 2002, Mr. Gardner was in the private practice of law, principally representing Massey. He also served as a director of Massey from 2000 to 2002. Mr. Gardner served as Senior Vice President of Massey from 1994 to 2000 and as General Counsel from 1993 to 2000. From 1991 to 1993, Mr. Gardner was an attorney at the law firm of Hunton & Williams LLP.

Thomas W. Hofmann has served as a director of our general partner since May 2009. Since December 2008, Mr. Hofmann has been retired. Mr. Hofmann served as Senior Vice President and Chief Financial Officer of Sunoco, Inc., an oil refining and marketing company, from January 2002 to December 2008 and as Vice President and Chief Financial Officer of Sunoco from July 1998 to January 2002. Mr. Hofmann also serves as a director of West Pharmaceuticals Services, Inc. In the last five years, he has also served on the board of directors of the general partner of Sunoco Logistics Partners, L.P. and VIASYS Healthcare Inc.

James R. Montague has served as a director of our general partner since July 2001. Since 2003, Mr. Montague has been retired. From 2001 to 2002, Mr. Montague served as President of EnCana Gulf of Mexico LLC, a subsidiary of EnCana Corporation, which is in the business of oil and gas exploration and production. From 1996 to June 2001, Mr. Montague served as President of two subsidiaries of International Paper Company, IP Petroleum Company, an exploration and production oil and gas company, and GCO Minerals Company, a company that manages International Paper Company’s mineral holdings. Mr. Montague also serves as a director of Atwood Oceanics, Inc. and as a director of the general partner of Magellan Midstream Partners, L.P. In the last five years, Mr. Montague has served on the board of directors of The Meridian Resource Corporation.

Marsha R. Perelman has served as a director of our general partner since May 2005. 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.

Robert B. Wallace has served as Executive Vice President and Chief Financial Officer of our general partner since March 2010. Mr. Wallace has also served as Executive Vice President and Chief Financial Officer of PVG’s general partner March 2010. Mr. Wallace served as Senior Vice President, Finance and Chief Financial Officer of Buckeye GP LLC, the general partner of Buckeye Partners, L.P., a refined petroleum products pipeline company, from September 2004 to July 2007. Mr. Wallace also served as Senior Vice President, Finance and Chief Financial Officer of MainLine Management LLC, the general partner of Buckeye GP Holdings L.P., from September 2004 to July 2007. Prior to joining Buckeye, Mr. Wallace served as Executive Director, Corporate Finance of the Energy Group of UBS Investment Bank from September 1997 to February 2004.

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Nancy M. Snyder has served as Vice President and General Counsel since July 2001 and as Chief Administrative Officer since May 2008 and as Vice President and General Counsel and as a director of PVG’s general partner since September 2006 and as Chief Administrative Officer since May 2008. From July 2001 to March 2010, Ms. Snyder served as a director of our general partner. Ms. Snyder has also served in various capacities with Penn Virginia since 1997, including as Executive Vice President since May 2006, as Chief Administrative Officer since May 2008, as Senior Vice President from February 2003 to May 2006, as Vice President from December 2000 to February 2003 and as General Counsel and Corporate Secretary since 1997.

Keith D. Horton has served as Co-President and Chief Operating Officer—Coal of our general partner since June 2006 and as President of PVR Coal since September 2001. From July 2001 to June 2006, Mr. Horton served as President and Chief Operating Officer of our general partner. Mr. Horton has also served in various capacities with Penn Virginia since 1981, including as Executive Vice President since December 2000, as Vice President—Eastern Operations from February 1999 to December 2000 and as Vice President from February 1996 to February 1999. Mr. Horton also serves as a director of Penn Virginia and as director of the Virginia Mining Association, the Powell River Project and the Eastern Coal Council.

Ronald K. Page has served as Co-President and Chief Operating Officer—Midstream of our general partner since June 2006 and as President of PVR Midstream since January 2005. From July 2003 to June 2006, Mr. Page served as Vice President, Corporate Development of our general partner. Mr. Page has also served in various capacities with Penn Virginia since July 2003, including as Vice President since May 2005 and as Vice President, Corporate Development from July 2003 to May 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.

Director Independence

Messrs. Cloues, Gardner, Hofmann and Montague and Ms. Perelman are “independent directors,” as defined by New York Stock Exchange, or NYSE, Listing Standards and SEC rules and regulations. We refer to those directors as “Independent Directors.” The board of directors of our general partner has determined that none of the Independent Directors have any relationship with us other than as a director of our general partner or its affiliates, Penn Virginia or PVG’s general partner.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Our general partner is Penn Virginia Resource GP, LLC, which is a wholly owned subsidiary of PVG. Penn Virginia owns an approximate25.8% limited partner interest in PVG, as well as the non-economic general partner interest in PVG. PVG owns 19,587,049 common units, representing an approximate 37.1% limited partner interest in us, as well as 100% of our general partner, which owns a 2% general partner interest in us and all of our incentive distribution rights.

Transactions with Related Persons

Management and Administrative Services

We are managed and controlled by our general partner pursuant to our partnership agreement. Under our partnership agreement, our general partner is reimbursed for all direct and indirect expenses it incurs or payments it makes on our behalf. These expenses include salaries, fees and other compensation and benefit expenses of employees, officers and directors, insurance, other administrative or overhead expenses and all other expenses necessary or appropriate to conduct our business. The costs allocated to us by our general partner for administrative services and overhead totaled $5.3 million, $5.1 million and $4.2 million for the years ended December 31, 2009, 2008 and 2007.

Incentive Distributions

Our partnership agreement provides for incentive distributions payable to our general partner out of our Available Cash (as defined in our partnership agreement) in the event quarterly distributions to unitholders exceed certain specified targets. In general, subject to certain limitations, if a quarterly distribution exceeds a target of $0.275 per common unit, our general partner will receive incentive distributions equal to (i) 15% of that portion of the distribution per common unit which exceeds but is not more than $0.325, plus (ii) 25% of that portion of the quarterly distribution per common unit which exceeds $0.325 but is not more than $0.375, plus (iii) 50% of that portion of the quarterly distribution per common unit which exceeds $0.375. In 2009, our general partner received total distributions, including incentive distributions, of $63.0 million from us. Please read “Business—Partnership Distributions.”

Oil and Gas Marketing Agreement

Connect Energy, our wholly owned subsidiary, and PVOG LP, Penn Virginia’s wholly owned subsidiary, are parties to a Master Services Agreement effective September 1, 2006. Pursuant to the Master Services Agreement, Connect Energy and PVOG LP have agreed that Connect Energy 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 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 2009, PVOG LP paid Connect Energy $1.4 million in fees pursuant to the Master Services Agreement.

Gas Gathering and Processing Agreement

PVR East Texas Gas Processing LLC, or PVR East Texas, our wholly owned subsidiary, and PVOG LP are parties to a Gas Gathering and Processing Agreement effective May 1, 2007. Pursuant to the Gas Gathering and Processing Agreement, PVR East Texas and PVOG LP 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 NGLs to PVOG LP for a current service fee of

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$0.3115/MMBtu (with an annual CPI adjustment). The Gas Gathering and Processing Agreement has a primary term of 15 years and automatically renews for additional one year terms until terminated by either party. In 2009, PVOG LP paid PVR East Texas $4.0 million in fees pursuant to the Gas Gathering and Processing Agreement.

Gas Purchase Arrangement

From time to time, Connect Energy purchases gas or NGLs from PVOG LP at our Crossroads Plant and resells such gas or NGLs to third parties. The purchase price paid by Connect Energy to PVOG LP for such gas or NGLs equals the sales price received by Connect Energy for such gas or NGLs from the third parties. In 2009, Connect Energy paid PVOG LP $72.5 million in connection with such purchases.

Omnibus Agreement

Penn Virginia, we, our general partner and PVR Coal are parties to an Omnibus Agreement that governs potential competition among us. The Omnibus Agreement was entered into in connection with our 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 Penn Virginia. For purposes of the Omnibus Agreement, any restrictions that apply to Penn Virginia also apply to PVG.

Under the Omnibus Agreement, Penn Virginia and its 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 it or they first offers us the opportunity to acquire these businesses or assets and the board of directors of our general partner, with the concurrence of its conflicts committee, elects to cause us not to pursue such opportunity or acquisition. In addition, Penn Virginia and its 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 Penn Virginia or its affiliates make any such acquisition, it or they must offer us the opportunity to purchase the coal reserves, timber or related infrastructure following the acquisition and the conflicts committee of the board of directors of our general partner will determine whether we should pursue the opportunity. The restriction will terminate upon a change of control of Penn Virginia or our general partner.

Non-Compete Agreement

We and PVG are parties to a Non-Compete Agreement that governs potential competition among us. The Non-Compete Agreement was entered into in connection with PVG’s initial public offering in December 2006, but is not effective until PVG is no longer subject to the Omnibus Agreement. Pursuant to the Non-Compete Agreement, PVG will have a right of first refusal with respect to the potential acquisition of any general partner interest, and any other equity interests under common ownership with such general partner, in a publicly traded partnership, other than any partnerships engaged in the coal or timber businesses described above or the business of gathering or processing natural gas or other hydrocarbons. We will have a right of first refusal with respect to the potential acquisition of assets that relate to the business of (i) owning, mining, processing, marketing or transporting coal, (ii) owning, acquiring or leasing coal reserves, (iii) growing, harvesting or selling timber or (iv) the gathering or processing of natural gas or other hydrocarbons.

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Policies and Procedures 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 any proposed transaction between us (or any of our subsidiaries) and Penn Virginia or PVG (or any of their respective subsidiaries) is approved by the conflicts committee of our general partner. With respect to any proposed transaction with any other related person, as a general matter, our practice is that such transactions are approved by disinterested directors. The General Counsel of our general partner advises the board of directors of our general partner as to which transactions involve related persons, which transactions require the approval of the conflicts committee of our general partner and which directors are prohibited from voting on a particular transaction. All of the related transactions described above were approved in accordance with the foregoing policies and procedures.

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DESCRIPTION OF CERTAIN INDEBTEDNESS

Revolving Credit Facility

As of December 31, 2009, net of outstanding borrowings of $620.1 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $178.3 million on our Revolver. In March 2009, we increased the size of our Revolver from $700.0 million to $800.0 million and secured our Revolver with substantially all of our assets. Our Revolver matures in December 2011 and is available to us 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 2009, we incurred commitment fees of $0.5 million on the unused portion of our Revolver. The interest rate under our Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 1.25% if we select the base rate borrowing option under our Revolver or at a rate derived from the LIBOR plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under our Revolver during 2009 was approximately 2.7%. We do not have a public credit rating for our Revolver. For a discussion of the applicable covenants and related compliance with respect to our Revolver, please read “Management’s Discussion and Analysis of Financial Conditions and Results of Operations—Sources of Liquidity—Long-Term Debt—Revolver.”

Proceeds received from this offering will be used to repay a portion of the borrowings outstanding under our Revolver. Please read “Use of Proceeds.”

Interest Rate Swaps

We have entered into interest rate swaps, or Interest Rate Swaps, to establish fixed rates on a portion of the outstanding borrowings under our Revolver. The following table sets forth the Interest Rate Swap positions at December 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 Interest Rate Swaps extend one year past the maturity of the current Revolver. After considering the applicable margin of 2.25% in effect as of December 31, 2009 the total interest rate on the $310 million portion of our Revolver borrowings covered by the Interest Rate Swaps was 5.79% as of December 31, 2009.

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DESCRIPTION OF NOTES

You can find the definitions of certain terms in this description under the subheading “—Definitions.” In this description, the word “Issuers” refers only to Penn Virginia Resource Partners, L.P. and Penn Virginia Resource Finance Corporation and not to any of their subsidiaries, any reference to the “Company” refers only to Penn Virginia Resource Partners, L.P. and not to any of its subsidiaries and any reference to “Finance Co.” refers only to Penn Virginia Resource Finance Corporation and not to any of its subsidiaries.

The Issuers will issue the notes under a First Supplemental Indenture to the Senior Indenture (as supplemented, the “Indenture”), among the Issuers, the Subsidiary Guarantors and Wells Fargo Bank, N.A., as trustee (the “Trustee”). The terms of the notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939 (the “Trust Indenture Act”). A copy of the Senior Indenture is on file, and a copy of the First Supplemental Indenture will be on file after the closing, with the SEC, and may be obtained by accessing the internet address provided under “Where You Can Find More Information” in the accompanying base prospectus.

The following description is a summary of the material provisions of the Indenture. It does not restate that agreement in its entirety. We urge you to read the Indenture because it, and not this description, defines your rights as a holder of these notes. You should read the Senior Indenture and the First Supplemental Indenture carefully to fully understand the terms of the notes. In addition, to the extent that the following description is not consistent with that contained in the accompanying base prospectus under “Description of Debt Securities,” you should rely on this description.

Brief Description of the Notes and the Guarantees

The Notes

The notes:

• are general unsecured, senior obligations of the Issuers;

• rank equally in right of payment to any existing and future unsecured senior obligations of either of the Issuers, but are effectively subordinated to all present and future secured obligations of either of the Issuers to the extent of the value of the collateral securing such obligations;

• rank senior in right of payment to any existing and future obligations of either Issuer that are, by their terms, subordinated to the notes;

• are effectively subordinated to all existing and future obligations of the Company’s Subsidiaries that do not guarantee the notes; and

• are unconditionally guaranteed on a senior, unsecured basis by the Subsidiary Guarantors.

The Guarantees

Initially, the notes are guaranteed by PVR Finco LLC, which we refer to as the “Holding Company” in this description, and by all of the Holding Company’s other existing subsidiaries (except CBC/Leon Limited Partnership, a 91% owned subsidiary (“CBC/Leon”)).

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Each Guarantee of a Subsidiary Guarantor of these notes:

• is a general unsecured, joint and several senior obligation of that Subsidiary Guarantor;

• ranks equally in right of payment to any future unsecured senior obligations of the Subsidiary Guarantor, but is effectively subordinated to all present and future secured obligations of the Subsidiary Guarantor, including the obligations under the Credit Agreement of each Subsidiary Guarantor that is a borrower or guarantor under the Credit Agreement, to the extent of the value of the collateral securing such obligations; and

• ranks senior in right of payment to any existing and future obligations of that Subsidiary Guarantor that are, by their terms, subordinated to its Guarantee.

As a result of the effective subordination described above, in the event of a bankruptcy, liquidation or reorganization of either Issuer, holders of the notes may recover less ratably than secured creditors of the Issuers and the Subsidiary Guarantors and all creditors of the Company’s Subsidiaries that are not Subsidiary Guarantors.

After giving effect to the closing of this offering and the related transactions and the use of the proceeds thereof, we anticipate that the Holding Company (excluding its subsidiaries) will have approximately $328.1 million of secured obligations outstanding and approximately $470.3 million available for borrowing under the Credit Agreement, and that Finance Co. (excluding its subsidiaries) will have no secured obligations outstanding. On the same basis, we anticipate that the Subsidiary Guarantors will not have secured obligations outstanding other than their guarantees under the Credit Agreement. The Guarantees of the Subsidiary Guarantors of the notes will be structurally subordinated to the Subsidiary Guarantors’ guarantees under the Credit Agreement.

As of the date of the Indenture, all of our Subsidiaries and their respective subsidiaries (except Finance Co. and CBC/Leon) will be Subsidiary Guarantors and Restricted Subsidiaries. Certain Subsidiaries in the future may not be Subsidiary Guarantors. In the event of a bankruptcy, liquidation or reorganization of any of these non-guarantor subsidiaries, the non-guarantor subsidiaries will pay the holders of their debt and their trade creditors before they will be able to distribute any of their assets to us. Also, under the circumstances described below under the subheading “—Covenants—Designation of Restricted and Unrestricted Subsidiaries,” we will be permitted to designate certain of our Subsidiaries as “Unrestricted Subsidiaries.” Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the Indenture. Unrestricted Subsidiaries will not guarantee the notes.

Principal, Maturity and Interest

The Issuers will issue notes offered hereby in an initial aggregate principal amount of $300.0 million. Subject to compliance with the covenant described below under “—Covenants—Incurrence of Indebtedness and Issuance of Disqualified Equity,” we may issue additional notes from time to time under the Indenture. The notes and any additional notes subsequently issued under the Indenture will be treated as a single class for all purposes under the Indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. The Issuers will issue notes in denominations of $2,000 and integral multiples of $1,000 above such amount. The notes will mature on April 15, 2018.

Interest on the notes offered hereby will accrue at the rate of 8 ¹/4% per annum and will be payable semi-annually in arrears on April 15 and October 15, commencing on October 15, 2010. The Issuers will make each interest payment to the holders of record of the notes on the immediately preceding April 1 and October 1.

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Interest on the notes offered hereby will accrue from April 27, 2010 or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

Methods of Receiving Payments on the Notes

If a holder has given wire transfer instructions to the Issuers, the Issuers will make all payments of principal of, premium, if any, and interest on the notes in accordance with those instructions. All other payments on these notes will be made at the office or agency of the Paying Agent within the City and State of New York, unless the Issuers elect to make interest payments by check mailed to the holders at their address set forth in the register of holders.

Paying Agent and Registrar for the Notes

The Trustee will initially act as paying agent (the “Paying Agent”) and registrar (the “Registrar”). The Issuers may change the Paying Agent or Registrar without prior notice to the holders of the notes, and the Issuers or any of their Subsidiaries may act as Paying Agent or Registrar other than in connection with the discharge or defeasance provisions of the Indenture.

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 and the Issuers may require a holder to pay any taxes and fees required by law or permitted by the Indenture. The Issuers are not required to transfer or exchange any note selected for redemption or repurchase. Also, the Issuers are not required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed or between a record date and the next succeeding interest payment date.

The registered holder of a note will be treated as the owner of it for all purposes, and all references in this description to “holders” are to holders of record.

The Guarantees

Initially, all of our Restricted Subsidiaries (except Finance Co. and CBC/Leon, and their respective subsidiaries) will guarantee our Obligations under the notes and the Indenture. In the future, our Restricted Subsidiaries will be required to guarantee our Obligations under the notes and the Indenture in the circumstances described below under “Covenants—Additional Subsidiary Guarantees.” In addition, our Obligations under the notes and the Indenture will not be guaranteed by our non-Subsidiary joint ventures. In the event of a bankruptcy, liquidation or reorganization of any of these non-guarantor Subsidiaries or joint ventures, any future non-guarantor Subsidiaries or joint ventures will pay the holders of their debt and their trade creditors before they will be able to distribute any of their assets to the Company.

The Subsidiary Guarantors will jointly and severally guarantee on a senior basis the Issuers’ Obligations under the notes. The obligations of each Subsidiary Guarantor under its Guarantee will rank equally in right of payment with other obligations of such Subsidiary Guarantor, except to the extent such other obligations are expressly subordinate to the obligations arising under the Guarantee. However, the notes will be structurally subordinated to the secured obligations of the Subsidiary Guarantors to the extent of the value of the collateral securing such obligations. The obligations of each Subsidiary Guarantor under its Guarantee will be limited as necessary to prevent that Guarantee from constituting a fraudulent conveyance under applicable law.

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Not all of the Company’s Subsidiaries will Guarantee the notes. In the event of a bankruptcy, liquidation or reorganization of any of these non-guarantor Subsidiaries, the non-guarantor Subsidiaries will pay the holders of their debt and their trade creditors before they will be able to distribute any of their assets to the Company. For the fiscal year ended December 31, 2009, on a pro forma basis, CBC/Leon, our only non-guarantor Subsidiary, generated ade minimis amount of the Company’s total revenue and adjusted EBITDA, respectively. In addition, as of December 31, 2009, such non-guarantor Subsidiary held ade minimis amount of the Company’s consolidated assets and had no Indebtedness.

A Subsidiary Guarantor may not consolidate with or merge with or into (whether or not such Subsidiary Guarantor is the surviving Person) another Person, except the Company or another Subsidiary Guarantor, unless:

(1) immediately after giving effect to that transaction, no Default or Event of Default exists; and

(2) the Person formed by or surviving any such consolidation or merger assumes all the Obligations of that Subsidiary Guarantor pursuant to a supplemental indenture substantially in the form specified in the Indenture, except as provided in the next paragraph.

The Guarantee of a Subsidiary Guarantor will be released:

(1) in connection with any sale or other disposition of all or substantially all of the assets of that Subsidiary Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary, if the Company applies the Net Proceeds of that sale or other disposition in accordance with the applicable provisions of the Indenture applicable to Asset Sales;

(2) in connection with any sale or other disposition of all of the Equity Interests of a Subsidiary Guarantor to a Person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary, if the Company applies the Net Proceeds of that sale in accordance with the applicable provisions of the Indenture applicable to Asset Sales;

(3) in connection with the release or discharge of the guarantee that resulted in the creation of such Subsidiary Guarantee pursuant to the covenant described under “—Covenants—Additional Subsidiary Guarantees” or a release or discharge of all guarantees by such Guarantor of other Indebtedness, except a release or discharge by or as a result of payment under such guarantee;

(4) if the Company designates any Restricted Subsidiary that is a Subsidiary Guarantor as an Unrestricted Subsidiary in accordance with the Indenture;

(5) at such time as such Guarantor ceases to guarantee any other Indebtedness of the Company and any other Subsidiary of the Company; or

(6) upon Legal Defeasance or Covenant Defeasance as described below under the caption “—Legal Defeasance and Covenant Defeasance” or upon satisfaction and discharge of the Indenture as described below under the caption “—Satisfaction and Discharge.”

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Optional Redemption

Schedule of Redemption Prices

Except as described below, the notes are not redeemable until April 15, 2014. On and after such date, the Issuers 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), 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 12-month period beginning on April 15 of the years indicated below:

Year	Percentage
2014	104.125	%
2015	102.063	%
2016 and thereafter	100.000	%

Make Whole

In addition, before April 15, 2014, the Issuers 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 a redemption price equal to:

• 100% of the aggregate principal amount of the notes to be redeemed, plus accrued and unpaid interest, 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 an interest payment date that is on or prior to the redemption date), plus

• the Make Whole Amount.

“Make Whole Amount” means, with respect to any note at any redemption date, the excess, if any, of (1) an amount equal to the present value of (a) the redemption price of such note at April 15, 2014 plus (b) the remaining scheduled interest payments on the notes to be redeemed (subject to the right of holders on the relevant record date to receive interest due on the relevant interest payment date) to April 15, 2014 (other than interest accrued to the redemption date), computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (2) the aggregate principal amount of the notes to be redeemed.

“Treasury Rate” means, at the time of computation, the yield to maturity 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 of similar market data) most nearly equal to the period from the redemption date to April 15, 2014; providedthat if such period 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 April 15, 2014 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.

The Treasury Rate shall be calculated on the third business day preceding the redemption date. Any weekly average yields calculated by interpolation will be rounded to the nearest 1/100th of 1%, with any figure of 1/200th of 1% or above being rounded upward.

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Equity Offerings

Before April 15, 2013, the Issuers may on any one or more occasions redeem in the aggregate up to 35% of the aggregate principal amount of notes (including any additional notes) issued under the Indenture with the Net Proceeds of one or more Equity Offerings at a redemption price equal to 108.250% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on a record date to receive interest due on the relevant interest payment date that is on or prior to the redemption date);provided that

(1) at least 65% of the aggregate principal amount of notes (including any additional notes) issued under the Indenture remains outstanding after each such redemption; and

(2) any redemption occurs within 90 days after the closing of such Equity Offering (without regard to any over-allotment option).

Selection and Notice

If less than all of the notes are to be redeemed at any time, the Trustee will select notes for redemption as follows:

(1) if the notes are listed, in compliance with the requirements of the principal national securities exchange on which the notes are listed; or

(2) if the notes are not so listed or there are no such requirements, on a pro rata basis, by lot or by such method as the Trustee shall deem fair and appropriate.

No notes of $2,000 or less shall be redeemed in part. Notices of redemption shall be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address. Notice of any redemption may not be conditional.

If any note is to be redeemed in part only, the notice of redemption that relates to that note shall state the portion of the principal amount thereof to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued in the name of the holder thereof upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on notes or portions of them called for redemption unless the Issuers default in making such redemption payment.

Repurchase at the Option of Holders

Change of Control

If a Change of Control occurs, each holder of notes will have the right to require the Issuers to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of that holder’s notes pursuant to the Change of Control Offer. In the Change of Control Offer, the Issuers will offer a change of control payment (the “Change of Control Payment”) in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest thereon, if any, to the date of purchase (the “Change of Control Payment Date”), subject to the rights of any holder in whose name a note is registered on a record date occurring prior to the Change of Control Payment Date to receive interest on an interest payment date that is on or prior to such Change of Control Payment Date. Within 30 days following any Change of Control, the Issuers will mail a notice

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to each holder describing the transaction or transactions that constitute the Change of Control and offering (the “Change of Control Offer”) to repurchase notes on the Change of Control Payment Date specified in such notice, pursuant to the procedures required by the Indenture and described in such notice. The Issuers will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the Indenture, the Issuers will comply with the applicable securities laws and regulations and will not be deemed to have breached their obligations under the Change of Control provisions of the Indenture by virtue of such conflict.

On the Change of Control Payment Date, the Issuers will, to the extent lawful:

(1) accept for payment all notes or portions thereof 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 thereof so tendered; 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 thereof being purchased by the Issuers.

The Paying Agent will promptly mail to each holder of notes so tendered the Change of Control Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of DTC), 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 principal amount of $2,000 or an integral multiple of $1,000 in excess thereof. The Issuers will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.

The provisions described above that require the Issuers to make a Change of Control Offer following a Change of Control will be applicable regardless of 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 holder of the notes to require that the Issuers repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

The Credit Agreement provides that certain change of control events with respect to the Company and the General Partner would constitute a default under the agreements governing such Indebtedness. Because the definition of change of control under the Credit Agreement differs from that under the Indenture, there may be a change of control and resulting default under the Credit Agreement at a time when no change of control has occurred under the Indenture. Any future credit agreements or other agreements relating to Indebtedness to which the Company becomes a party may contain similar restrictions and provisions. Moreover, the exercise by the holders of their right to require the Issuers to repurchase the notes could cause a default under such Indebtedness, even if the Change of Control does not, due to the financial effect of such a repurchase on the Company. If a Change of Control occurs at a time when the Company is prohibited from purchasing notes, the Company could seek the consent of the lenders of the borrowings containing such prohibition to the purchase of notes or could attempt to refinance such borrowings. If the Company does not obtain such a consent or repay such borrowings, the Company will remain prohibited from purchasing notes. In such case, the Company’s failure to purchase tendered notes would constitute an Event of Default under the Indenture, which would, in turn, in all likelihood constitute a default under such

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borrowings. Finally, the Issuers’ ability to pay cash to the holders upon a repurchase may be limited by the Company’s then existing financial resources. We cannot assure you that sufficient funds will be available when necessary to make any required repurchases.

Notwithstanding the preceding paragraphs of this covenant, the Issuers will not be required to make a Change of Control Offer upon a Change of Control, and a holder will not have the right to require the Issuers to repurchase any notes pursuant to a Change of Control Offer, if (i) a third party makes an offer to purchase the notes in the manner, at the times and otherwise in substantial compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer and purchases all notes validly tendered and not withdrawn under such purchase offer or (ii) an irrevocable notice of redemption to purchase all outstanding notes at a purchase price equal to at least 101% of the aggregate principal amount of such notes has been given pursuant to “—Optional Redemption” above, unless and until the Issuers have defaulted in the payment of the applicable redemption price.

A Change of Control Offer may be made in advance of a Change of Control, and conditioned upon the occurrence of such 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. Notes repurchased by the Issuers pursuant to a Change of Control Offer will have the status of notes issued but not outstanding or will be retired and cancelled, at either of the Issuers’ option. Notes purchased by a third party pursuant to the preceding paragraph will have the status of notes issued and outstanding.

Notwithstanding the foregoing, the Issuers shall not be required to make a Change of Control Offer, as provided above, if, in connection with or in contemplation of any Change of Control, they have made an offer to purchase (an “Alternate Offer”) any and all Notes validly tendered at a cash price equal to or higher than the Change of Control Payment and have purchased all Notes properly tendered in accordance with the terms of such Alternate Offer.

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 definition of Change of Control includes a phrase relating to the sale, transfer, lease, conveyance or other disposition of “all or substantially all” of the assets of the Company and its Restricted Subsidiaries taken as a whole. 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, the ability of a holder of notes to require the Company to repurchase such notes as a result of a sale, transfer, lease, conveyance or other disposition of less than all of the assets of the Company and its Restricted Subsidiaries taken as a whole to another Person or group may be uncertain. In addition, in a 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.

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Asset Sales

The Company will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

(1) except in the case of a disposition of Investments in Joint Ventures to the extent required by or made pursuant to customary buy/sell arrangements between the Joint Venture parties set forth in Joint Venture agreements or similar binding arrangements, the Company (or the Restricted Subsidiary, as the case may be) receives consideration at the time of such Asset Sale at least equal to the fair market value of the assets or Equity Interests issued or sold or otherwise disposed of;

(2) such fair market value is determined in good faith by (a) an executive officer of the General Partner if the value is less than $50.0 million, as evidenced by an officers’ certificate delivered to the Trustee or (b) the Board of Directors of the General Partner if the value is $50.0 million or more, as evidenced by a Board Resolution of the General Partner; and

(3) except in the case of a Permitted Asset Swap, at least 75% of the consideration therefor received by the Company or such Restricted Subsidiary is in the form of cash or Cash Equivalents or a combination thereof. For purposes of this provision, each of the following shall be deemed to be cash:

(i) any liabilities (as shown on the Company’s or such Restricted Subsidiary’s most recent balance sheet) of the Company or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation agreement that releases the Company or such Restricted Subsidiary from further liability;

(ii) any securities, notes or other Obligations received by the Company or any such Restricted Subsidiary from such transferee that are within 180 days after the Asset Sale converted by such Issuer or such Restricted Subsidiary into cash (to the extent of the cash received in that conversion); and

(iii) accounts receivable of a business retained by the Company or any Restricted Subsidiary, as the case may be, following the sale of such business, provided, that such accounts receivable are not (a) past due more than 90 days and (b) do not have a payment date greater than 120 days from the date of the invoice creating such accounts receivable.

Within 360 days after the receipt of any Net Proceeds from an Asset Sale (or within 90 days after such 360-day period in the event the Company enters into a binding commitment with respect to such application), the Company or a Restricted Subsidiary may apply such Net Proceeds at its option:

(1) to repay senior Indebtedness of the Company and/or its Restricted Subsidiaries under the Credit Facilities; and/or

(2) to satisfy all mandatory repayment obligations under the Credit Facilities arising by reason of such Asset Sale;

(3) to make a capital expenditure in a Permitted Business;

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(4) to acquire other tangible assets that are used or useful in a Permitted Business; or

(5) to acquire all or substantially all of the assets of a Person engaged in a Permitted Business or Equity Interests of a Person engaged in a Permitted Business so long as such Person or the Person to which such assets are transferred is or becomes a Restricted Subsidiary.

Pending the final application of any such Net Proceeds, the Company may temporarily reduce revolving credit borrowings or otherwise invest such Net Proceeds in any manner that is not prohibited by the Indenture.

Any Net Proceeds from Asset Sales that are not applied or invested as provided in the preceding paragraph will constitute “Excess Proceeds.” When the aggregate amount of Excess Proceeds exceeds $25.0 million, the Issuers will make a pro rata offer (an “Asset Sale Offer”) to all holders of notes and, at the option of the Issuers, all holders of other Indebtedness that is pari passu with the notes to purchase the maximum principal amount of notes and such other pari passu Indebtedness that may be purchased out of the Excess Proceeds;provided that notes tendered shall be given priority over any such other Indebtedness unless such other Indebtedness contains provisions similar to those set forth in the Indenture with respect to offers to purchase or redeem with the proceeds of sales of assets in which case the notes and such other Indebtedness will be purchased on a pro rata basis. The offer price in any Asset Sale Offer will be equal to 100% of principal amount plus accrued and unpaid interest, if any, to the date of purchase, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, the Company may use such Excess Proceeds for any purpose not otherwise prohibited by the Indenture, including, without limitation, the repurchase or redemption of Indebtedness of the Issuers or any Subsidiary Guarantor that is subordinated to the notes or, in the case of any Subsidiary Guarantor, the Guarantee of such Subsidiary Guarantor. If the aggregate principal amount of notes tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds allocated for repurchases of notes pursuant to the Asset Sale Offer for notes, the Trustee shall select the notes to be purchased on a pro rata basis. Upon completion of each Asset Sale Offer, the amount of Excess Proceeds shall be reset at zero.

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sale provisions of the Indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the Indenture by virtue of such conflict.

Covenants

Restricted Payments

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1) declare or pay any dividend or make any other payment or distribution on account of the Company’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) or to the direct or indirect holders of the Company’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than distributions or dividends payable in Equity Interests of the Company (other than Disqualified Equity) and other than distributions or dividends payable to the Company or a Restricted Subsidiary);

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(2) purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving the Company) any Equity Interests of the Company, any of its Restricted Subsidiaries or the General Partner or any other equity holder of the Company (other than any such Equity Interests owned by the Company or any of its Restricted Subsidiaries);

(3) make any principal payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Subordinated Indebtedness or Guarantor Subordinated Indebtedness, except a scheduled payment of principal within one month of its Stated Maturity; or

(4) make any Investment other than a Permitted Investment

(all such payments and other actions set forth in clauses (1) through (4) above being collectively referred to as “Restricted Payments”), unless, at the time of and after giving effect to such Restricted Payment, no Default (except a Reporting Failure) or Event of Default shall have occurred and be continuing or would occur as a consequence thereof and either:

(1) if the Fixed Charge Coverage Ratio for the Company’s four most recent fiscal quarters for which internal financial statements are available is equal to or greater than 1.75 to 1.0, such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Company and its Restricted Subsidiaries during the quarter in which such Restricted Payment is made (excluding Restricted Payments permitted by clauses (2), (3), (4) (to the extent paid to the Company or a Restricted Subsidiary), (5), (6), (7), (8) or (9) of the next succeeding paragraph), is less than the sum, without duplication, of:

(a) Available Cash from Operating Surplus with respect to the Company’s preceding fiscal quarter,plus

(b) the aggregate net cash proceeds received by the Company (including the fair market value of any Permitted Business or long-term assets that are used or useful in a Permitted Business to the extent acquired in consideration of Equity Interests (other than the Disqualified Equity) of the Company) after the Issue Date from (x) a contribution to the common equity capital of the Company from any Person (other than a Restricted Subsidiary of the Company) or (y) the issuance and sale (other than to a Restricted Subsidiary of the Company) of Equity Interests (other than Disqualified Equity) of the Company or from the issuance or sale (other than to a Restricted Subsidiary of the Company) of convertible or exchangeable Disqualified Equity or convertible or exchangeable debt securities of the Company that have been converted into or exchanged for such Equity Interests (other than Disqualified Equity),plus

(c) to the extent that any Restricted Investment that was made after the Issue Date is sold for cash or Cash Equivalents or otherwise liquidated or repaid for cash or Cash Equivalents, the return of capital or similar payment made in cash or Cash Equivalents with respect to such Restricted Investment (less the cost of such disposition, if any), plus

(d) the net reduction in Restricted Investments resulting from dividends, repayments of loans or advances, or other transfers of assets in each case to the Company or any of its Restricted Subsidiaries from any Person (including, without limitation, Unrestricted Subsidiaries and joint ventures) or from redesignations of Unrestricted

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Subsidiaries as Restricted Subsidiaries, to the extent such amounts have not been included in Available Cash from Operating Surplus for any period commencing on or after the Issue Date (items (b), (c) and (d) being referred to as “Incremental Funds”), minus

(e) the aggregate amount of Incremental Funds previously expended pursuant to this clause (1) or clause (2) below or to make a Permitted Business Investment; or

(2) if the Fixed Charge Coverage Ratio for the Company’s four most recent fiscal quarters for which internal financial statements are available is less than 1.75 to 1.0, such Restricted Payment (it being understood that the only Restricted Payments permitted to be made pursuant to this clause (2) are distributions on common units of the Company, plus the related distribution on the general partner interest and any distributions with respect to incentive distribution rights), together with the aggregate amount of all other Restricted Payments made by the Company and its Restricted Subsidiaries during the quarter in which such Restricted Payment is made (excluding Restricted Payments permitted by clauses (2), (3), (4) (to the extent paid to the Company or a Restricted Subsidiary), (5), (6), (7), (8) or (9) of the next succeeding paragraph) is less than the sum, without duplication, of:

(a) $120.0 million less the aggregate amount of all Restricted Payments made by the Company and its Restricted Subsidiaries pursuant to this clause (2)(a) during the period beginning on the Issue Date and ending on the last day of the fiscal quarter of the Company immediately preceding the date of such Restricted Payment, plus

(b) Incremental Funds to the extent not previously expended pursuant to this clause (2) or clause (1) above.

The preceding provisions will not prohibit:

(1) the payment by the Company or any Restricted Subsidiary of any distribution or dividend or the consummation of any redemption of a Subordinated Indebtedness pursuant to an irrevocable notice of redemption within 60 days after the date of declaration of such dividend or distribution, or the giving of such irrevocable notice of redemption, if at said date of declaration or the date of such notice of redemption, as applicable, such payment would have complied with the provisions of the Indenture;

(2) the redemption, repurchase, retirement, defeasance or other acquisition of subordinated Indebtedness of the Company or any Subsidiary Guarantor or of any Equity Interests of the Company in exchange for, or out of the net cash proceeds of, a substantially concurrent (a) capital contribution to the Company from any Person (other than a Restricted Subsidiary of the Company) or (b) sale (other than to a Restricted Subsidiary of the Company) of Equity Interests (other than Disqualified Equity) of the Company, with a sale being substantially concurrent if such redemption, repurchase, retirement, defeasance or other acquisition occurs not more than 120 days after such sale;provided that the amount of any such net cash proceeds that are utilized for any such redemption, repurchase, retirement, defeasance or other acquisition will be excluded or deducted from the calculation of Available Cash from Operating Surplus and Incremental Funds and from clause 1(b) of the preceding paragraph;

(3) the defeasance, redemption, repurchase or other acquisition of any Subordinated Indebtedness or Guarantor Subordinated Indebtedness with the net cash proceeds from an incurrence of, or in exchange for, Permitted Refinancing Indebtedness;

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(4) the payment of any distribution or dividend by a Restricted Subsidiary to the Company or to the holders of its Equity Interests (other than Disqualified Equity) on a pro rata basis;

(5) so long as no Default (other than a Reporting Failure) has occurred and is continuing or would be caused thereby, the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of the Company or any Restricted Subsidiary of the Company pursuant to any management equity subscription agreement or equity option agreement or other employee benefit plan or to satisfy obligations under any Equity Interests appreciation rights or option plan or similar arrangement;provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests shall not exceed $6.0 million in any calendar year;

(6) repurchases of Equity Interests deemed to occur upon exercise of stock options, warrants or other convertible securities if such Equity Interests represent a portion of the exercise price of such options, warrants or other convertible securities;

(7) cash payments in lieu of the issuance of fractional shares in connection with the exercise of warrants, options or other securities convertible or exchangeable for Equity Interests that are not derivative securities;

(8) any repurchases, redemptions or other acquisitions or retirements for value of Equity Interests made in lieu of withholding taxes in connection with any exercise or exchange of warrants, options or rights to acquire Equity Interests; and

(9) in connection with an acquisition by the Company or any of its Restricted Subsidiaries, the return to the Company or any of its Restricted Subsidiaries of Equity Interests of the Company or its Restricted Subsidiaries constituting a portion of the purchase consideration in settlement of indemnification claims.

In computing the amount of Restricted Payments previously made for purposes of the first paragraph of this section, Restricted Payments made under clauses (1) (but only if the declaration of such dividend or other distribution has not been counted in a prior period) and (4) (but in the case of clause (4), only to the extent paid to a Person other than the Company or a Restricted Subsidiary) of this paragraph shall be included, and Restricted Payments made under clauses (2), (3), (5), (6), (7), (8) and (9) of this paragraph shall not be included. The amount of all Restricted Payments (other than cash) shall be the fair market value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The fair market value of any assets or securities that are required to be valued by this covenant shall be determined, in the case of amounts under $50.0 million, by an officer of the General Partner and, in the case of amounts over $50.0 million, by the Board of Directors of the General Partner whose Board Resolution with respect thereto shall be delivered to the Trustee.

Incurrence of Indebtedness and Issuance of Disqualified Equity

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt), and the Company will not issue any Disqualified Equity and will not permit any of its Restricted Subsidiaries to issue any Disqualified Equity;provided that the Company and the Restricted Subsidiaries may incur Indebtedness (including Acquired Debt), and the Company and the Restricted Subsidiaries may issue Disqualified Equity, if the Fixed Charge Coverage Ratio for the Company’s most recently ended four full fiscal quarters for which internal financial statements are

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available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Equity is issued would have been at least 2.0 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred, or the Disqualified Equity had been issued, as the case may be, at the beginning of such four-quarter period.

So long as no Default shall have occurred and be continuing or would be caused thereby, the first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, “Permitted Debt”):

(1) the incurrence by the Company and any Subsidiary Guarantor of Indebtedness (including letters of credit) under Credit Facilities and the guarantees thereof;provided that the aggregate principal amount of all Indebtedness of the Company and the Restricted Subsidiaries incurred pursuant to this clause (1) and outstanding under all Credit Facilities after giving effect to such incurrence does not exceed the greater of (a) $800.0 million or (b) $600.0 millionplus 20% of the Consolidated Net Tangible Assets of the Company;

(2) the incurrence by the Company and its Restricted Subsidiaries of Existing Indebtedness (other than under the Credit Agreement);

(3) the incurrence by the Company and the Subsidiary Guarantors of Indebtedness represented by the notes issued and sold in this offering and the related Guarantees;

(4) the incurrence by the Company or any Subsidiary Guarantor of Indebtedness represented by Capital 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 improvement of property, plant or equipment used in the business of the Company or such Restricted Subsidiary, in an aggregate principal amount including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (4) not to exceed the greater of (a) $20.0 million at any time outstanding or (b) 2.5% of the Consolidated Net Tangible Assets of the Company;

(5) the incurrence by the Company or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to refund, refinance, replace, defease or discharge, Indebtedness that was permitted by the Indenture to be incurred under the first paragraph of this covenant or clause (2) or (3) of this paragraph or this clause (5);

(6) the incurrence by the Company or any of its Restricted Subsidiaries of intercompany Indebtedness between or among the Company and any of its Restricted Subsidiaries;provided that:

(a) if the Company is the obligor on such Indebtedness and a Subsidiary Guarantor is not the obligee, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations with respect to the notes, or if a Subsidiary Guarantor is the obligor on such Indebtedness and neither the Company nor another Subsidiary Guarantor is the obligee, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations with respect to the Guarantee of such Subsidiary Guarantor; and

(b) (i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Company or a Restricted

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Subsidiary thereof and (ii) any sale or other transfer of any such Indebtedness to a Person that is not either the Company or a Restricted Subsidiary thereof, shall be deemed, in each case, to constitute an incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

(7) the incurrence by the Company or any of its Restricted Subsidiaries of Hedging Obligations;

(8) the guarantee by the Company or any of its Restricted Subsidiaries of Indebtedness of the Company or any of its Restricted Subsidiaries that was permitted to be incurred by another provision of this covenant;provided that in the event such Indebtedness that is being guaranteed is a Subordinated Indebtedness or a Guarantor Subordinated Indebtedness, then the guarantee shall be subordinated in right of payment to the notes or the Guarantee, as the case may be;

(9) the incurrence by the Company or any Subsidiary Guarantor of additional Indebtedness or the issuance of Disqualified Equity in an aggregate principal amount at any time outstanding not to exceed the greater of (a) $30.0 million at any time outstanding or (b) 3.0% of the Consolidated Net Tangible Assets of the Company; and

(10) 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 Consolidated Net Tangible Assets of the Company.

For purposes of determining compliance with this “—Incurrence of Indebtedness and Issuance of Disqualified Equity” covenant, in the event that an item of proposed Indebtedness meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (10) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, the Company will be permitted to classify (or later reclassify in whole or in part) such item of Indebtedness in any manner that complies with this covenant. An item of Indebtedness may be divided and classified in one or more of the types of Permitted Indebtedness. Any outstanding Indebtedness under the Credit Facilities on the Issue Date shall be considered incurred under clause (1) of this covenant and may not be reclassified.

The accrual of interest, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, and the payment of dividends on Disqualified Equity in the form of additional shares of the same class of Disqualified Equity will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Equity for purposes of this covenant;provided, in each such case, that the amount thereof is included in Fixed Charges of the Company as accrued.

Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness or Disqualified Equity that the Company or any Restricted Subsidiary may incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of the fluctuations in exchange rates or currency values.

Liens

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, assume or suffer to exist any Lien of any kind securing Indebtedness upon any asset now owned or hereafter acquired, except Permitted Liens, without making effective

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provision whereby all Obligations due under the notes and Indenture or any Guarantee, as applicable, will be secured by a Lien equally and ratably with (or prior to in the case of Liens with respect to Subordinated Indebtedness or Guarantor Subordinated Indebtedness, as the case may be) any and all Obligations thereby secured for so long as any such Obligations shall be so secured.

Dividend and Other Payment Restrictions Affecting Subsidiaries

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any encumbrance or restriction on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Equity Interests to the Company or any of its Restricted Subsidiaries, or pay any Indebtedness or other Obligations owed to the Company or any of its Restricted Subsidiaries;provided that the priority that any series of preferred stock of a Restricted Subsidiary has in receiving dividends or liquidating distributions before dividends or liquidating distributions are paid in respect of common stock of such Restricted Subsidiary shall not constitute a restriction on the ability to make dividends or distributions on Equity Interests for purposes of this covenant;

(2) make loans or advances to or make other Investments in the Company or any of its Restricted Subsidiaries; or

(3) sell, lease or transfer any of its properties or assets to the Company or any of its Restricted Subsidiaries.

However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

(1) agreements as in effect on the Issue Date (including the Credit Agreement) and any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of any such agreements;provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are no more restrictive, taken as a whole, with respect to such distribution, dividend and other payment restrictions and loan or investment restrictions than those contained in such agreement, as in effect on the Issue Date;

(2) the Indenture, the notes and the Guarantees;

(3) applicable law, rule, regulation, order, licenses, permits or similar governmental, judicial or regulatory restriction;

(4) any instrument governing Indebtedness or Equity Interests of a Person acquired by the Company or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the property or assets of any Person, other than such Person, or the property or assets of such Person, so acquired;provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the Indenture to be incurred;

(5) customary non-assignment provisions in Hydrocarbon or timber purchase and sale or exchange agreements or similar operational agreements or in licenses and leases entered into in the ordinary course of business and consistent with past practices;

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(6) Capital Lease Obligations, mortgage financings or purchase money obligations, in each case for property acquired in the ordinary course of business that impose restrictions on that property of the nature described in clause (3) of the preceding paragraph;

(7) any agreement for the sale or other disposition of a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary pending its sale or other disposition;

(8) Permitted Refinancing Indebtedness;provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are no more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;

(9) Liens securing Indebtedness otherwise permitted to be incurred pursuant to the provisions of the covenant described above under the caption “—Liens” that limit the right of the Company or any of its Restricted Subsidiaries to dispose of the assets subject to such Lien;

(10) provisions with respect to the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, stock sale agreements and other similar agreements customary for transactions of that type that solely affect the assets or property that are the subject of such agreements;provided that, in the case of joint venture agreements, such provisions solely affect assets or property of the joint venture;

(11) any agreement or instrument relating to any property or assets acquired after the Issue Date, so long as such encumbrance or restriction relates only to the property or assets so acquired and is not and was not created in anticipation of such acquisition;

(12) restrictions on cash or other deposits or net worth imposed by customers or lessors under contracts or leases entered into in the ordinary course of business;

(13) Hedging Obligations incurred from time to time; and

(14) 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 Issuance of Disqualified Equity;” 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 General Partner in good faith, than the provisions contained in the Credit Agreement as in effect on the Issue Date;

Merger, Consolidation or Sale of Assets

Neither of the Issuers may, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not such Issuer is the survivor); or (2) sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets, in one or more related transactions, to another Person, unless:

(1) either: (a) such Issuer is the surviving entity of such transaction; or (b) the Person formed by or surviving any such consolidation or merger (if other than such Issuer) or to which such sale, assignment, transfer, lease, conveyance or other disposition shall have been made is an entity organized or existing under the laws of the United States, any state thereof or the District of Columbia;provided that Finance Co. may not consolidate or merge with or into any entity other than a corporation satisfying such requirement;

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(2) the Person formed by or surviving any such consolidation or merger (if other than such Issuer) or the Person to which such sale, assignment, transfer, lease, conveyance or other disposition shall have been made expressly assumes all the Obligations of such Issuer under the notes, the Indenture pursuant to agreements reasonably satisfactory to the Trustee;

(3) immediately after such transaction no Default or Event of Default exists;

(4) in the case of a transaction involving the Company and not Finance Co., the Company or the Person formed by or surviving any such consolidation or merger (if other than the Company) will, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, (A) be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “—Incurrence of Indebtedness and Issuance of Disqualified Equity” or (B) have a Fixed Charge Coverage Ratio for such four-quarter period equal to or greater than the Fixed Charge Coverage Ratio immediately before such transaction;provided that this clause (4) shall be terminated after the Company and its Restricted Subsidiaries are not subject to the Terminated Covenants; and

(5) such Issuer has delivered to the Trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger or disposition and, if a supplemental indenture is required, such supplemental indenture comply with the Indenture and all conditions precedent therein relating to such transaction have been satisfied.

Notwithstanding the preceding paragraph, the Company is permitted to reorganize as any other form of entity in accordance with the procedures established in the Indenture;provided that:

(1) the reorganization involves the conversion (by merger, sale, contribution or exchange of assets or otherwise) of the Company into a form of entity other than a limited partnership formed under Delaware law;

(2) the entity so formed by or resulting from such reorganization is an entity organized or existing under the laws of the United States, any state thereof or the District of Columbia;

(3) the entity so formed by or resulting from such reorganization assumes all the Obligations of the Company under the notes and the Indenture pursuant to agreements reasonably satisfactory to the Trustee;

(4) immediately after such reorganization no Default or Event of Default exists; and

(5) such reorganization is not adverse to the holders of the notes (for purposes of this clause (5), it is stipulated that such reorganization shall not be considered adverse to the holders of the notes solely because the successor or survivor of such reorganization (a) is subject to federal or state income taxation as an entity or (b) is considered to be an “includible corporation” of an affiliated group of corporations within the meaning of Section 1504(b)(i) of the Code or any similar state or local law).

Notwithstanding anything herein to the contrary, in the event the Company becomes a corporation or the Company or the Person formed by or surviving any consolidation or merger (permitted in accordance with the terms of the Indenture) is a corporation, Finance Co. may be dissolved in accordance with the Indenture and may cease to be an Issuer.

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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 properties or assets of a Person.

Transactions with Affiliates

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, any Affiliate (each, an “Affiliate Transaction”), unless:

(1) such Affiliate Transaction is on terms that are no less favorable to the Company or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person; and

(2) the Company delivers to the Trustee:

(a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration more than $25.0 million, an officers’ certificate certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members of the Board of Directors of the General Partner; and

(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $50.0 million, (i) a resolution of the Board of Directors of the General Partner set forth in an officers’ certificate certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members of the Board of Directors of the General Partner and (ii) an opinion as to the fairness to the Company of such Affiliate Transaction from a financial point of view issued by an accounting, appraisal or investment banking firm of national standing recognized as an expert in rendering fairness opinions on transactions such as those proposed.

The following items shall not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

(1) any employment, equity award, equity option or equity appreciation agreement or plan or similar arrangement entered into by the Company or any of its Restricted Subsidiaries in the ordinary course of business;

(2) transactions between or among the Company and/or its Restricted Subsidiaries;

(3) Restricted Payments that are permitted by the provisions of the Indenture described above under the caption “—Restricted Payments” and Permitted Investments;

(4) transactions effected in accordance with the terms of (i) agreements described in this prospectus supplement under the caption “Certain Relationships and Related Transactions” as such agreements are in effect on the date of the Indenture and (ii) any amendment or replacement of any of such agreements, so long as, in the case of clause (ii), such amendment, replacement or similar agreement, taken as a whole, is no less advantageous to the Company in any material respect than the applicable agreement referred to in clause (i);

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(5) customary compensation, indemnification and other benefits made available to officers, directors or employees of the Company or a Restricted Subsidiary, including reimbursement or advancement of out-of-pocket expenses and provisions of officers’ and directors’ liability insurance;

(6) purchase, sale, processing, fractionating, treating, gathering, transportation, wheelage, handling, marketing, hedging, production, handling, cutting, operating, construction, terminalling, storage, lease, platform use or other operational contracts, entered into in the ordinary course of business on terms substantially similar to those contained in similar contracts entered into by the Company or any Restricted Subsidiary with third parties, or if neither the Company nor any Restricted Subsidiary has entered into a similar contract with a third party, on terms that are no less favorable than those available from third parties on an arm’s-length basis;

(7) the issuance or sale for cash of Equity Interests (other than Disqualified Equity);

(8) any transaction in which the Company or any of its Restricted Subsidiaries, as the case may be, deliver to the Trustee opinion from an accounting, appraisal or investment banking firm of national standing stating that such transaction is fair to the Company or such Restricted Subsidiary from a financial point of view or that such transaction meets the requirements of clause (1) of the first paragraph of this covenant;

(9) guarantees of performance by the Company and its Restricted Subsidiaries of the Company’s Unrestricted Subsidiaries in the ordinary course of business, except for guarantees of Indebtedness in respect of borrowed money;

(10) if such Affiliate Transaction is with a Person in its capacity as a holder of Indebtedness or Equity Interests of the Company or any Restricted Subsidiary where such Person is treated no more favorably than the holders of Indebtedness or Equity Interests of the Company or any Restricted Subsidiary who are unaffiliated with the Company and its Restricted Subsidiaries;

(11) transactions effected pursuant to agreements in effect on the Issue Date and any amendment, modification or replacement of such agreement (so long as such amendment or replacement is not in the good faith determination of the Board of Directors of the General Partner materially more disadvantageous to the holders of notes, taken as a whole than the original agreement as in effect on the Issue Date);

(12) transactions between the Company and any Person, a director of which is also a director of the Company;provided that such director abstains from voting as a director of the Company on any matter involving such other Person;

(13) any issuance of Equity Interests (other than Disqualified Equity) of the Company to Affiliates of the Company for cash;

(14) transactions with a Joint Venture that comply with clause (1) of the preceding paragraph;

(15) payments to the General Partner with respect to reimbursement of expenses in accordance with applicable provisions of the Partnership Agreement as in effect on the Issue Date;

(16) payments to Penn Virginia Corporation or its Affiliates in respect of transition services under written agreements entered into after the Issue Date;provided that such

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agreements have been approved by the Board of Directors of the General Partner, including a majority of the directors who are not affiliated with Penn Virginia Corporation; and

(17) loans or advances to employees in the ordinary course of business not to exceed $2.0 million in the aggregate at any one time outstanding.

Additional Subsidiary Guarantees

If, after the Issue Date, any Restricted Subsidiary that is not already a Subsidiary Guarantor guarantees any other Indebtedness of either of the Issuers or any Indebtedness of the Holding Company or any other Subsidiary Guarantor, then, in each such case, such Subsidiary must become a Subsidiary Guarantor by executing a supplemental indenture substantially in the form provided in the Indenture and delivering it to the Trustee within 20 business days of the date on which such other guarantee was executed;providedthat the preceding shall not apply to Subsidiaries of the Company that have properly been designated as Unrestricted Subsidiaries in accordance with the Indenture for so long as they continue to constitute Unrestricted Subsidiaries. Notwithstanding the preceding, any Guarantee of a Restricted Subsidiary that was incurred pursuant to this paragraph shall provide by its terms that it shall be automatically and unconditionally released upon the release or discharge of the guarantee which resulted in the creation of such Restricted Subsidiary’s Guarantee, except a discharge or release by, or as a result of payment under, such guarantee and except if, at such time, such Restricted Subsidiary is then a guarantor under any other Indebtedness of the Issuers or another Subsidiary.

Designation of Restricted and Unrestricted Subsidiaries

The Board of Directors of the General Partner may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation would not cause a Default or Event of Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, all outstanding Investments owned by the Company and its Restricted Subsidiaries in the Subsidiary so designated will be deemed to be an Investment made as of the time of such designation and will reduce the amount available for Restricted Payments under the first paragraph of the covenant described above under the caption “—Restricted Payments” or represent Permitted Investments, as applicable. All such outstanding Investments will be valued at their fair market value at the time of such designation. That designation will only be permitted if such Restricted Payment or Permitted Investments would be permitted at that time and such Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. All Subsidiaries of an Unrestricted Subsidiary shall also be Unrestricted Subsidiaries. Upon the designation of a Restricted Subsidiary that is a Subsidiary Guarantor as an Unrestricted Subsidiary, the Guarantee of such entity shall be automatically released.

The Board of Directors of the General Partner may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary;provided that such designation shall be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of the Company of any outstanding Indebtedness of such Unrestricted Subsidiary and such designation shall only be permitted if (1) such Indebtedness is permitted under the covenants described under the caption “—Covenants—Incurrence of Indebtedness and Issuance of Disqualified Equity,” calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period, and “—Covenants—Liens” and (2) no Default or Event of Default (other than a Reporting Failure) would be in existence following such designation.

After covenants are terminated pursuant to “—Terminated Covenants,” the Company will not be permitted to designate or redesignate any of its Subsidiaries pursuant to the covenant described under the caption “—Covenants—Designation of Restricted and Unrestricted Subsidiaries.”

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Business Activities

The Company will not, and will not permit any Restricted Subsidiary to, engage in any business other than Permitted Businesses.

Finance Co. may not engage in any business or incur any Indebtedness other than activities in connection with its rights and obligations as an issuer of the notes and any additional notes issued under the Indenture.

Payments for Consent

The Company will not, and will not permit any of its Subsidiaries to, directly or indirectly, pay or cause to be paid any consideration to or for the benefit of any holder of 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 and 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 agreement.

Reports

Whether or not required by the SEC, so long as any notes are outstanding, the Company will file with the SEC (unless the SEC will not accept such a filing) within the time periods specified in the SEC’s rules and regulations and, unless already publicly available through the SEC’s EDGAR filing system, the Company will (a) furnish (without exhibits) to the Trustee for delivery to the holders of the notes and (b) post on its website or otherwise make available to prospective purchasers of the notes:

(1) all quarterly and annual financial information that would be required to be contained in a filing with the SEC on Forms 10-Q and 10-K if the Company were required to file such forms, including a “Management’s discussion and analysis of financial condition and results of operations” and, with respect to the annual information only, a report on the annual financial statements by the Company’s independent registered public accounting firm; and

(2) all current reports that would be required to be filed with the SEC on Form 8-K if the Company were required to file such reports (provided that, so long as the Company is not required to file with the SEC the reports referred to in this paragraph, the time period for filing reports on Form 8-K shall be 10 business days after the event giving rise to the obligation to file such report).

If, as of the end of any such quarterly or annual period, the Company has Subsidiaries that are not Subsidiary Guarantors, then the Company shall include in such reports, in accordance with Section 3-10 of Regulation S-X, either on the face of the financial statements or in the footnotes thereto, the financial information of the Company and its Subsidiary Guarantors separate from the financial information of the non-Guarantor Subsidiaries of the Company.

Terminated Covenants

If at any time the notes achieve an Investment Grade Rating from both of the Rating Agencies and no Default or Event of Default has occurred and is then continuing under the Indenture, then upon the Issuers’ giving notice to the trustee of such event, the Company and its Restricted Subsidiaries will no longer be subject to the following provisions of the Indenture:

• “—Repurchase at the Option of Holders—Asset Sales,”

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• “—Restricted Payments,”

• “—Incurrence of Indebtedness and Issuance of Disqualified Equity,”

• “—Dividend and Other Payment Restrictions Affecting Subsidiaries,”

• “—Designation of Restricted and Unrestricted Subsidiaries,”

• “—Business Activities,”

• “—Additional Subsidiary Guarantees,”

• clause (4) of the first paragraph of the covenant described above under the caption “—Merger, Consolidation or Sale of Assets,” and

• “—Transactions with Affiliates.”

There can be no assurance that the notes will ever achieve or maintain an Investment Grade Rating. After the foregoing covenants have been terminated, the Company may not designate any of its Subsidiaries as Unrestricted Subsidiaries pursuant to the definition of “Unrestricted Subsidiary.”

Events of Default and Remedies

Each of the following is an Event of Default:

(1) default for 30 days in the payment when due of interest on the notes;

(2) default in payment when due of the principal of or premium, if any, on the notes;

(3) failure by the Company to comply (for 30 days in the case of a failure to comply that is capable of cure) with the provisions described under “—Merger, Consolidation or Sale of Assets” or its obligations to consummate a purchase of notes in accordance with the provisions described under “—Repurchase at the Option of Holders—Change of Control” or “Asset Sales;”

(4) failure by the Company to comply for 60 days (or 180 days in the case of a Reporting Failure) after notice with any of the other agreements in the Indenture;

(5) 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), whether such Indebtedness or guarantee now exists or is created after the Issue Date, if that default:

(a) is caused by a failure to pay principal of or premium, if any, or interest on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness on the date of such default (a “Payment Default”); or

(b) results in the acceleration of such Indebtedness prior to its express maturity,

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

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Default or the maturity of which has been so accelerated, aggregates $20.0 million or more;provided,that so long as the outstanding notes have not been accelerated, if within a period of 60 days from the continuation of such default under such other Indebtedness beyond the applicable grace period or the occurrence of such acceleration of such other Indebtedness, as the case may be, any such default is cured or waived or any such acceleration rescinded, or such other Indebtedness is repaid (other than as a result of any such acceleration), such Event of Default shall be automatically rescinded, so long as such rescission does not conflict with any judgment or decree;

(6) failure by the Company or any of the Company’s Restricted Subsidiaries to pay final judgments aggregating in excess of $20.0 million, which judgments are not paid, discharged or stayed for a period of 60 days;

(7) except as permitted by the Indenture, any Guarantee by any Subsidiary Guarantor other than an Immaterial Subsidiary shall be held in any judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in force and effect or any such Subsidiary Guarantor, or any Person acting on behalf of any such Subsidiary Guarantor, shall deny or disaffirm its Obligations under its Guarantee; and

(8) certain events of bankruptcy or insolvency with respect to Finance Co., the Company or any of its Restricted Subsidiaries that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

In the case of an Event of Default arising from events described in clause (8) above, with respect to the Company or Finance Co., all outstanding notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the Trustee or the holders of at least 25% in principal amount of the then outstanding notes may declare all the notes to be due and payable immediately.

Holders of the notes may not enforce the Indenture or the notes except as provided in the Indenture. Subject to certain limitations, holders of a majority in principal amount of the then outstanding notes may direct the Trustee in its exercise of any trust or power. The Trustee may withhold from holders of the notes notice of any continuing Default or Event of Default (except a Default or Event of Default relating to the payment of principal or interest) if it determines that withholding notice is in their interest.

The holders of a majority in aggregate principal amount of the notes then outstanding by notice to the Trustee may on behalf of the holders of all of the notes waive any existing Default or Event of Default and its consequences under the Indenture except a continuing Default or Event of Default in the payment of interest on, or the principal of, the notes.

The Issuers and the Subsidiary Guarantors are required to deliver to the Trustee annually a statement regarding compliance with the Indenture. Upon any officer of the General Partner or Finance Co. becoming aware of any Default or Event of Default, the Issuers are required to deliver to the Trustee a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees and Unitholders and No Recourse Against General Partner

Neither the General Partner nor any past, present or future director, officer, partner, member, trustee, employee, incorporator, manager or unitholder or other owner of Equity Interests of the Issuers, the General Partner or any Subsidiary Guarantor, as such, shall have any liability for any

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Obligations of the Issuers or the Subsidiary Guarantors under the notes, the Indenture, the Guarantees or for any claim based on, in respect of, or by reason of, such Obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

Legal Defeasance and Covenant Defeasance

The Issuers may, at their option and at any time, elect to have all of the Issuers’ Obligations discharged with respect to the outstanding notes and all Obligations of the Subsidiary Guarantors discharged with respect to their Guarantees (“Legal Defeasance”), except for:

(1) the rights of holders of outstanding notes to receive payments in respect of the principal of, premium, if any, and interest on such notes when such payments are due from the trust referred to below;

(2) the Issuers’ Obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3) the rights, powers, trusts, duties and immunities of the Trustee, and the Issuers’ Obligations in connection therewith; and

(4) the Legal Defeasance provisions of the Indenture.

In addition, the Company may, at its option and at any time, elect to have the Obligations of the Issuers and the Guarantors released with respect to certain covenants that are described in the Indenture (“Covenant Defeasance”) and thereafter any omission to comply with those covenants shall not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, receivership, rehabilitation and insolvency events) described under “Events of Default” will no longer constitute an Event of Default with respect to the notes.

If the Issuers exercise either their Legal Defeasance or their Covenant Defeasance option, upon satisfaction of all conditions precedent to such Legal Defeasance or Covenant Defeasance each Subsidiary Guarantor will be released and relieved from any obligation under its Subsidiary Guarantee and any security for the notes (other than the trust) will be released.

In order to exercise either Legal Defeasance or Covenant Defeasance:

(1) the Issuers must irrevocably deposit with the Trustee, in trust, for the benefit of the holders of the notes, cash in U.S. dollars, U.S. Government Obligations or a combination thereof, in such amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, premium, if any, and interest on the outstanding notes at the Stated Maturity thereof or on the applicable redemption date, as the case may be, and the Issuers must specify whether the notes are being defeased to Stated Maturity or to a particular redemption date;

(2) in the case of Legal Defeasance, the Issuers shall have delivered to the Trustee an opinion of counsel reasonably acceptable to the Trustee confirming that (a) the Company has received from, or there has been published by, the Internal Revenue Service a ruling or (b) since the Issue Date, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel shall confirm

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that, the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3) in the case of Covenant Defeasance, the Issuers shall have delivered to the Trustee an opinion of counsel reasonably acceptable to the Trustee confirming that the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4) no Default or Event of Default shall have occurred and be continuing either: (a) on the date of such deposit (other than a Default or Event of Default resulting from the incurrence of Indebtedness all or a portion of the proceeds of which shall be applied to such deposit); or (b) insofar as Events of Default from bankruptcy or insolvency events are concerned, at any time in the period ending on the 91st day after the date of deposit;

(5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the Indenture) to which the Company or any of its Subsidiaries is a party or by which the Company or any of its Subsidiaries is bound;

(6) the Issuers must have delivered to the Trustee an opinion of counsel to the effect that after the 91st day following the deposit, the trust funds will not be subject to the effect of any applicable bankruptcy, insolvency, reorganization or similar laws affecting creditors’ rights generally, subject to customary assumptions and qualifications;

(7) the Issuers must deliver to the Trustee an officers’ certificate stating that the deposit was not made by the Issuers with the intent of preferring the holders of notes over the other creditors of the Issuers or with the intent of defeating, hindering, delaying or defrauding other creditors of the Issuers; and

(8) the Issuers must deliver to the Trustee an officers’ certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

Amendment, Supplement and Waiver

Generally, the Issuers, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture, the Guarantees and the notes with the consent of the holders of at least a majority in principal amount of the notes then outstanding. However, without the consent of each holder affected, an amendment, supplement or waiver may not (with respect to any notes held by a nonconsenting holder):

(1) reduce the principal amount of notes whose holders must consent to an amendment, supplement or waiver;

(2) reduce the principal of or change the fixed maturity of any note or alter or waive the provisions with respect to the redemption or repurchase of the notes (other than provisions relating to the covenants described above under the caption “—Repurchase at the Option of Holders”;

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(3) reduce the rate of or change the time for payment of interest on any note;

(4) waive a Default or Event of Default in the payment of principal of or premium, if any, or interest on the notes (except a rescission of acceleration of the notes by the holders of at least a majority in aggregate principal amount of the notes and a waiver of the payment default that resulted from such acceleration);

(5) make any note payable in money other than that stated in the notes;

(6) make any change in the provisions of the Indenture relating to waivers of past Defaults or the rights of holders of notes to receive payments of principal of or premium, if any, or interest on the notes (other than as permitted in clause (7) below);

(7) waive a redemption or repurchase payment with respect to any note (other than a payment required by one of the covenants described above under the caption “—Repurchase at the Option of Holders”);

(8) except as otherwise permitted in the Indenture, release any Subsidiary Guarantor from its Obligations under its Guarantee or the Indenture or change any Guarantee in any manner that would adversely affect the rights of holders;

(9) make any change in the preceding amendment, supplement and waiver provisions (except to increase any percentage set forth therein); or

(10) modify or change any provision of the Indenture or the related definitions affecting the ranking of the notes or any Guarantee in a manner that adversely affects the holders of the notes.

Notwithstanding the preceding, without the consent of any holder of notes, the Issuers, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture, the Guarantees or the notes:

(1) to cure any ambiguity, defect or inconsistency;

(2) to provide for uncertificated notes in addition to or in place of certificated notes;

(3) to provide for the assumption of an Issuer’s or Subsidiary Guarantor’s Obligations to holders of notes in the case of a merger or consolidation or sale of all or substantially all of such Issuer’s assets, or to provide for the reorganization of the Company as any other form of entity, in accordance with the second paragraph of “—Covenants—Merger, Consolidation or Sale of Assets;”

(4) to add or release Subsidiary Guarantors pursuant to the terms of the Indenture;

(5) to make any change that would provide any additional rights or benefits to the holders of notes or surrender any right or power conferred upon the Issuers or the Subsidiary Guarantors by the Indenture that does not adversely affect the rights under the Indenture of any holder of the notes;

(6) to provide for the issuance of additional notes in accordance with the limitations set forth in the Indenture;

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(7) to comply with requirements of the SEC in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act;

(8) to evidence or provide for the acceptance of appointment under the Indenture of a successor Trustee;

(9) to add any additional Events of Default;

(10) to secure the notes and/or the Guarantees;

(11) to comply with the rules of any applicable securities depository;

(12) to conform the text of the Indenture or the Guarantees to any provision of this “Description of Notes” to the extent such text of the Indenture or Guarantee was intended to reflect such provision of this “Description of Notes.”

Satisfaction and Discharge

The Indenture will be discharged and will cease to be of further effect as to all notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the notes and as otherwise specified in the Indenture), when

(1) either:

(a) 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 been deposited in trust and thereafter repaid to the Issuers, have been delivered to the Trustee for cancellation; or

(b) 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 mailing of a notice of redemption or otherwise and the Issuers or any Subsidiary Guarantor has irrevocably deposited or caused to be deposited with the Trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, U.S. Government Obligations or a combination of cash in U.S. dollars and U.S. Government Obligations, in 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, premium, if any, and accrued interest to the date of fixed maturity or redemption;

(2) no Default or Event of Default has occurred and is continuing on the date of the deposit or will occur as a result of the deposit and the deposit will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the Indenture) to which the Company or any of its Subsidiaries is a party or by which the Company or any of its Subsidiaries is bound;

(3) the Issuers or any Subsidiary Guarantor has paid or caused to be paid all sums payable by the Issuers under the Indenture; and

(4) the Issuers have delivered irrevocable instructions to the Trustee to apply the deposited money toward the payment of the notes at fixed maturity or the redemption date, as the case may be.

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In addition, the Issuers must deliver an officers’ certificate and an opinion of counsel to the Trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Concerning the Trustee

If the Trustee becomes a creditor of an Issuer or any Subsidiary Guarantor, the Indenture limits its right to obtain payment of claims in certain cases or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest it must eliminate such conflict within 90 days, apply to the SEC for permission to continue (if the Indenture has been qualified under the Trust Indenture Act) or resign.

The holders of a majority in principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the Trustee, subject to certain exceptions. The Indenture provides that in case an Event of Default shall occur and be continuing, the Trustee will be required, in the exercise of its power, to use the degree of care of a prudent person the conduct of his own affairs. Subject to such provisions, the Trustee will be under no obligation to exercise any of its rights or powers under the Indenture at the request of any holder of notes, unless such holder shall have offered to the Trustee security or indemnity satisfactory to it against any loss, liability or expense.

Definitions

Set forth below are defined terms used in the Indenture. Reference is made to the Indenture for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided.

“Acquired Debt” means, with respect to any specified Person:

(1) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Subsidiary of, such specified Person, but excluding Indebtedness that is extinguished, retired or repaid in connection with such Person merging with or becoming a Subsidiary of such specified Person; and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

“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 purposes of this definition, “control,” as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise;provided that beneficial ownership of 10% or more of the Voting Stock of a specified Person shall be deemed to be control by the other Person;provided, further, that any third Person which also beneficially owns 10% or more of the Voting Stock of a specified Person shall not be deemed to be an Affiliate of either the specified Person or the other Person merely because of such common ownership in such specified Person; andprovided, further, that no holder of 10% or more of the Voting Stock of either Penn Virginia Corporation or Penn Virginia GP Holdings, L.P. (other than Penn Virginia Corporation) shall be deemed to be an “Affiliate” of the Company solely by reason of such holding. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” shall have correlative meanings. Notwithstanding the preceding, the term “Affiliate” shall not include a Restricted Subsidiary of any specified Person.

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“Asset Sale” means:

(1) the sale, lease, conveyance or other disposition of any assets, other than sales of inventory in the ordinary course of business;provided that the sale, lease, conveyance or other disposition of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the Indenture described above under the caption “Repurchase the Option of Holders—Change of Control” and/or the provisions described above under the caption “—Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sale covenant; and

(2) the issuance of Equity Interests by any of the Company’s Restricted Subsidiaries or the sale by the Company or any of its Restricted Subsidiaries of Equity Interests in any of its Restricted Subsidiaries.

Notwithstanding the preceding, the following items shall not be deemed to be Asset Sales:

(1) any single transaction or series of related transactions that involves assets having a fair market value of less than $20.0 million;

(2) a transfer of assets between or among the Company and its Restricted Subsidiaries;

(3) an issuance of Equity Interests by a Restricted Subsidiary to the Company or to another Restricted Subsidiary of the Company;

(4) a Restricted Payment that is permitted by the covenant described above under the caption “—Restricted Payments” or a Permitted Investment;

(5) the sale or other disposition of cash or Cash Equivalents, Hedging Obligations or other financial instruments in the ordinary course of business;

(6) transfers of damaged, worn-out or obsolete equipment or assets that, in the Company’s reasonable judgment, are no longer used or useful in the business of the Company or its Restricted Subsidiaries;

(7) surrender or waiver of contract rights, natural resources leases or the settlement, release or surrender of contract, tort or other claims of any kind;

(8) the creation or perfection of a Lien that is not prohibited by the covenant described above under the caption “—Covenants—Liens;”

(9) the grant in the ordinary course of business of any non-exclusive license of patents, trademarks, registrations therefor and other similar intellectual property;

(10) the sale or discounting of accounts receivable in the ordinary course of business;

(11) the abandonment, farmout, lease or sublease of developed or undeveloped coal properties in the ordinary course of business; and

(12) the sale or transfer (whether or not in the ordinary course of business) of any coal property or interest therein to which no proven and probable reserves are attributable at the time of such sale or transfer.

“Attributable Debt” in respect of a sale and lease-back transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and lease-back transaction including any period

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for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP.

“Available Cash” has the meaning assigned to such term in the Partnership Agreement, as in effect on the Issue Date.

“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 upon the occurrence of a subsequent condition. The terms “Beneficially Owns” and “Beneficially Owned” have correlative meanings.

“Board Resolution” means a copy of a resolution certified by the Secretary or an Assistant Secretary of the applicable Person to have been duly adopted by the Board of Directors of such Person and to be in full force and effect on the date of such certification, and delivered to the Trustee.

“Capital Lease Obligation” means, at the time any determination thereof is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet in accordance with GAAP.

“Cash Equivalents” means:

(1) United States dollars;

(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality thereof (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;

(3) certificates of deposit, time deposits and eurodollar time deposits with maturities of one year or less from the date of acquisition, bankers’ acceptances with maturities not exceeding 365 days, demand and overnight bank deposits and other similar types of investments routinely offered by commercial banks, in each case, with any domestic commercial bank having a combined capital and surplus in excess of $500.0 million and a Thompson Bank Watch Rating of “B” or better;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;

(5) commercial paper having one of the two highest ratings obtainable from Moody’s or Standard & Poor’s and in each case maturing within six months after the date of acquisition; and

(6) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (5) of this definition.

“Change of Control” means the occurrence of any of the following:

(1) the direct or indirect 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

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substantially all of the properties or assets (including Equity Interests of the Restricted Subsidiaries) of the Company and its Restricted Subsidiaries taken as a whole, to any “person” (as that term is used in Section 13(d)(3) of the Exchange Act);

(2) the adoption of a plan relating to the liquidation or dissolution of the Company or the removal of the General Partner by the limited partners of the Company;

(3) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any “person” or “group” (as those terms are used in Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision), other than a Qualified Owner, becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the General Partner, measured by voting power rather than number of shares or units;

(4) the Company consolidates or merges with or into another Person or any Person consolidates or merges with or into the Company, in either case under this clause (4), in one transaction or a series of related transactions in which immediately after the consummation thereof “persons” (as that term is used in Section 13(d)(3) of the Exchange Act) Beneficially Owning, directly or indirectly, Voting Stock representing in the aggregate more than 50% of the Voting Stock of the Company, measured by voting power rather than shares or units, immediately prior to such consummation do not Beneficially Own, directly or indirectly, Voting Stock representing more than 50% of the Voting Stock of the Company or the surviving or transferee Person, measured by voting power rather than by shares or units; or

(5) the first day on which a majority of the members of the Board of Directors of the General Partner are not Continuing Directors.

Notwithstanding the preceding, a conversion of the Company or any of its Restricted Subsidiaries from limited partnership, corporation, limited liability company or other form of entity to a limited liability company, corporation, limited partnership or other form of entity or an exchange of all of the outstanding Equity Interests in one form of entity for Equity interests in another form of entity shall not constitute a Change of Control, so long as following such conversion or exchange the “persons” (as that term is used in Section 13(d)(3) of the Exchange Act) who Beneficially Owned the Capital Stock of the Company immediately prior to such transactions continue to Beneficially Own in the aggregate more than 50% of the Voting Stock of such entity, measured by voting power rather than by shares or units, or continue to Beneficially Own sufficient Equity Interests in such entity to elect a majority of its directors, managers, trustees or other persons serving in a similar capacity for such entity or its general partner, as applicable, and, in either case no person Beneficially Owns more than 50% of the Voting Stock of such entity or its general partner, as applicable, measured by voting power rather than by shares or units.

“Code” means the Internal Revenue Code of 1986, as amended from time to time, and the rules and regulations thereunder, and any successor thereto.

“Consolidated Cash Flow” means, with respect to any Person for any period, the Consolidated Net Income of such Person for such period plus (without duplication):

(1) an amount equal to the dividends or distributions paid during such period in cash or Cash Equivalents to such Person or any of its Restricted Subsidiaries by a Person that is not a Restricted Subsidiary of such Person;plus

(2) the provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income;plus

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(3) the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued (including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings, and net of the effect of all payments, made or received pursuant to interest-rate Hedging Obligations), to the extent that any such expense was deducted in computing such Consolidated Net Income;plus

(4) depreciation, depletion and amortization (including amortization of goodwill and other intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period) and other non-cash expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion and amortization and other non-cash expenses were deducted in computing such Consolidated Net Income;plus

(5) all extraordinary or non-recurring items of loss or expense;plus

(6) an amount equal to any extraordinary loss plus any net loss realized by such Person or any of its Restricted Subsidiaries in connection with an Asset Sale, including any non-recurring charges relating to any premium or penalty paid, write-off of deferred financing costs or other financial recapitalization charges, in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity, to the extent such losses were included in computing such Consolidated Net Income;minus

(7) all extraordinary or non-recurring items of gain or revenue;minus

(8) non-cash items increasing such Consolidated Net Income for such period, other than items that were accrued in the ordinary course of business, in each case, on a consolidated basis and determined in accordance with GAAP.

“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP;provided that (without duplication):

(1) the aggregate Net Income (but not net loss in excess of such aggregate Net Income) of all Persons that are not Restricted Subsidiaries shall be excluded, except to the extent of the amount of dividends or distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person (without duplication);

(2) the earnings included therein attributable to all Persons that are accounted for by the equity method of accounting and the aggregate Net Income (but not net loss in excess of such aggregate Net Income) included therein attributable to all entities constituting Joint Ventures that are accounted for on a consolidated basis (rather than by the equity method of accounting) shall be excluded, except to the extent of the amount of dividends or distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person;

(3) the Net Income of any Restricted Subsidiary shall be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior

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governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement (other than the Indenture, the notes or its Guarantee), instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, partners or members;

(4) unrealized losses and gains under derivative instruments included in the determination of Consolidated Net Income shall be excluded;

(5) the cumulative effect of a change in accounting principles shall be excluded; and

(6) any nonrecurring charges relating to any premium or penalty paid, write off of deferred finance costs or other charges in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity shall be excluded.

“Consolidated Net Tangible Assets” means, with respect to any Person at any date of determination, the aggregate amount of total assets included in such Person’s most recent quarterly or annual consolidated balance sheet prepared in accordance with GAAP less applicable reserves reflected in such balance sheet, after deducting the following amounts: (1) all current liabilities reflected in such balance sheet and (2) all goodwill, trademarks, patents, unamortized debt discounts and expenses and other like intangibles reflected in such balance sheet.

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the General Partner who (1) was a member of such Board of Directors on the Issue Date or (2) was nominated for election or elected to such Board of Directors with the approval of either (x) a majority of the Continuing Directors who were members of such Board at the time of such nomination or election or (y) any “person” or “group” (as those terms are used in Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision) who owns all of the general partnership interests or a majority of the Equity Interests of the General Partner.

“Credit Agreement” means that certain Amended and Restated Credit Agreement, dated August 5, 2008, by and among PVR Finco LLC and the guarantors, lenders agent banking and financial institutions party thereto, including any related notes, guarantees, collateral documents, instruments and agreements executed in connection therewith, and in each case as amended, restated, modified, renewed, refunded, replaced, supplemented or refinanced in whole or in part from time to time.

“Credit Facilities” means, with respect to the Company, Finance Co. or any Restricted Subsidiary, one or more credit facilities or commercial paper facilities, including the Credit Agreement, in each case with banks, investment banks, insurance companies, mutual funds and/or institutional lenders providing for revolving credit loans, term loans, production payments, receivables or inventory financing (including through the sale of receivables or inventory 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, supplemented or refinanced (including refinancing with any capital markets transaction) in whole or in part from time to time.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Disqualified Equity” means any Equity Interest that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case at the option of the holder thereof), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder thereof,

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in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature. Notwithstanding the preceding sentence, any Equity Interest that would constitute Disqualified Equity solely because the holders thereof have the right to require the Company or any of its Restricted Subsidiaries to repurchase such Equity Interests upon the occurrence of a change of control or an asset sale shall not constitute Disqualified Equity if the terms of such Equity Interests provide that the Company or any Restricted Subsidiary may not repurchase or redeem any such Equity Interests pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “—Covenants—Restricted Payments.”

“Equity Interests” means:

(1) in the case of a corporation, corporate stock;

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited);

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person; and

(5) all warrants, options or other rights to acquire any of the interests described in clauses (1)-(4) above (but excluding any debt security that is convertible into, or exchangeable for, any of the interests described in clauses (1)-(4) above).

“Equity Offering” means any public or private sale for cash of Equity Interests of the Company (other than Disqualified Equity) after the Issue Date.

“Exchange Act” means the Securities Exchange Act of 1934, as amended.

“Existing Indebtedness” means the aggregate principal amount of Indebtedness of the Company and its Restricted Subsidiaries in existence on the Issue Date.

“Fixed Charge Coverage Ratio” means, with respect to any specified Person for any four-quarter reference period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, guarantees, repays or redeems any Indebtedness (other than revolving credit borrowings not constituting a permanent commitment reduction) or issues or redeems Disqualified Equity subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated but prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio shall be calculated giving pro forma effect to such incurrence, assumption, guarantee, repayment, redemption, defeasance or discharge of Indebtedness, or such issuance or redemption of Disqualified Equity, and the application of the net proceeds thereof as if the same had occurred at the beginning of the applicable four-quarter reference period (and if such Indebtedness is incurred to finance the acquisition of assets (including, without limitation, a single asset, a division or segment or an entire company) that were conducting commercial operations prior to such acquisition, there shall be included pro forma net income for such assets, as if such assets had been acquired on the first day of such period).

In addition, for purposes of calculating the Fixed Charge Coverage Ratio:

(1) acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers or consolidations and including any related

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financing transactions, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date shall be deemed to have occurred on the first day of the four-quarter reference period and pro forma effect will be given to the amount of net cost savings certified in an officer’s certificate executed by the Chief Financial Officer of the Company to have occurred or that are reasonably and in good faith projected to occur (regardless of whether such expense or cost savings 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);

(2) designations of Restricted Subsidiaries and Unrestricted Subsidiaries during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date shall be deemed to have occurred on the first day of the four-quarter reference period;

(3) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, shall be excluded;

(4) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, shall be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date;

(5) if any Indebtedness bears a floating rate of interest, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of the applicable period to the Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligation applicable to such Indebtedness if such Hedging Obligation has a remaining term as at the Calculation Date in excess of 12 months); and

(6) if any Indebtedness is incurred under a revolving Credit Facility and is being given pro forma effect, the interest on such Indebtedness shall be calculated based on the average daily balance of such Indebtedness for the four fiscal quarters subject to the pro forma calculation.

“Fixed Charges” means, with respect to any Person for any period, the sum, without duplication, of:

(1) the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued, including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings, and net of the effect of all payments made or received pursuant to interest-rate Hedging Obligations;plus

(2) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period;plus

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(3) any interest expense on Indebtedness of another Person that is guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such guarantee or Lien is called upon;plus

(4) all dividend payments, whether paid or accrued and whether or not in cash, on any series of Disqualified Equity of such Person or any of its Restricted Subsidiaries, other than dividend payments on Equity Interests payable solely in Equity Interests of the Company (other than Disqualified Equity) or to the Company or a Restricted Subsidiary of the Company;

in each case, on a consolidated basis and in accordance with GAAP.

“GAAP” means generally accepted accounting principles in the United States, which are in effect from time to time.

“General Partner” means Penn Virginia Resource GP, LLC, a Delaware limited liability company, and its successors and permitted assigns as general partner of the Company.

“guarantee” means to guarantee, other than by endorsement of negotiable instruments for collection in the ordinary course of business, directly or indirectly, in any manner, including, by way of a pledge of assets, or through letters of credit or reimbursement agreements in respect thereof, all or any part of any Indebtedness.

“Guarantee” means a guarantee of the notes.

“Guarantor Subordinated Indebtedness” 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 Guarantee pursuant to a written agreement.

“Hedging Obligations” means, with respect to any Person, the obligations of such Person under interest rate and commodity price swap agreements, interest rate and commodity price cap agreements, interest rate and commodity price collar agreements and foreign currency and commodity price exchange agreements, options or futures contracts or other similar agreements or arrangements or Hydrocarbon hedge contracts or Hydrocarbon forward sales contracts, in each case, designed to protect such Person against fluctuations in interest rates, foreign exchange rates or commodities prices.

“Hydrocarbons” means coal, crude oil, natural gas, natural gas liquids, casinghead 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.

“Indebtedness” means, with respect to any specified Person, any indebtedness of such Person, whether or not contingent:

(1) in respect of borrowed money;

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(2) evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof);

(3) in respect of banker’s acceptances;

(4) representing Capital Lease Obligations;

(5) representing all Attributable Debt of such Person in respect of any sale and lease-back transactions not involving a Capital Lease Obligation;

(6) representing the balance deferred and unpaid of the purchase price of any property, except any such balance that constitutes an accrued expense or trade payable incurred in the ordinary course of business; or

(7) representing any Hedging Obligations;

if and to the extent any of the preceding items (other than letters of credit and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term “Indebtedness” includes all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person) and, to the extent not otherwise included, the guarantee by such Person of any indebtedness of any other Person;provided that a guarantee otherwise permitted by the Indenture to be incurred by the Company or any of its Restricted Subsidiaries of Indebtedness incurred by the Company or a Restricted Subsidiary in compliance with the terms of the Indenture shall not constitute a separate incurrence of Indebtedness.

The amount of any Indebtedness outstanding as of any date shall be:

(1) the accreted value thereof, in the case of any Indebtedness issued with original issue discount;

(2) in the case of any Hedging Obligation, the termination value of the agreement or arrangement giving rise to such Hedging Obligation that would be payable by such Person at such date; and

(3) in the case of any letter of credit, the face amount thereof.

Notwithstanding the foregoing, the following shall not constitute “Indebtedness”:

(1) accrued expenses and trade accounts payable arising in the ordinary course of business;

(2) any obligation of the Company or any of its Restricted Subsidiaries in respect of bid, performance, surety and similar bonds issued for the account of the Company and any of its Restricted Subsidiaries in the ordinary course of business, including Guarantees and obligations of the Company or any of its Restricted Subsidiaries with respect to letters of credit supporting such obligations (in each case other than an obligation for money borrowed);

(3) any Indebtedness that has been defeased in accordance with GAAP or defeased pursuant to the irrevocable deposit of cash or U.S. Government Obligations (in an amount sufficient to satisfy all such Indebtedness at fixed 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, and the other applicable terms of the instrument governing such Indebtedness;

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(4) any obligation arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business;provided that such obligation is extinguished within five business days of its incurrence;

(5) any obligation arising from any agreement providing for indemnities, guarantees, purchase price adjustments, holdbacks, earnouts, contingency payment obligations based on the performance of the acquired or disposed assets or similar obligations (other than Guarantees of Indebtedness) incurred by any Person in connection with the acquisition or disposition of assets (including, without limitation, any such obligations pursuant to that certain Purchase and Sale Agreement, dated June 17, 2008, between the Company and Loan Star Gathering, L.P.);

(6) the incurrence by the Company or any Restricted Subsidiary of net gas balancing positions arising in the ordinary course of business and consistent with past practice;

(7) the incurrence by the Company or any of its Restricted Subsidiaries of obligations in respect of workers’ compensation claims, payment obligations in connection with health or other types of social security benefits, unemployment or other insurance or self-insurance obligations, reclamation, statutory obligations, banks’ acceptances and bid, performance, surety and appeal bonds or other similar obligations incurred in the ordinary course of business, including guarantees and obligations respecting standby letters of credit supporting such obligations, to the extent not drawn (in each case other than an obligation for money borrowed); and

(8) the incurrence by the Company or any of its Restricted Subsidiaries of obligations arising out of advances on trade receivables, factoring of receivables, customer prepayments and similar transactions in the ordinary course of business and consistent with past practice;

“Investment Grade Rating” means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s or BBB- (or the equivalent) by Standard & Poors or, if Moody’s and Standard & Poors both cease to rate the notes for reasons outside the Company’s control, the equivalent ratings from any other nationally recognized statistical rating agency.

“Investments” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the forms of direct or indirect loans (including guarantees of Indebtedness or other Obligations), advances (other than advances to customers in the ordinary course of business that are recorded as accounts receivable on the balance sheet of the lender and commission, moving, travel and similar advances to officers and employees made in the ordinary course of business) or capital contributions, purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. For purposes of the definition of “Unrestricted Subsidiary,” the definition of “Restricted Payment” and the covenant described under “—Covenants—Restricted Payments,” (1) the term “Investment” shall include the portion (proportionate to the Company’s Equity Interest in such Subsidiary) of the fair market value of the net assets of any Subsidiary of the Company or any of its Restricted Subsidiaries at the time that such Subsidiary is designated an Unrestricted Subsidiary and (2) any property transferred to or from an Unrestricted Subsidiary shall 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 General Partner. If the Company or any Restricted Subsidiary of the Company sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary of the Company such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of the Company, the

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Company shall be deemed to have made an Investment on the date of any such sale or disposition equal to the fair market value of the Equity Interests of such Restricted Subsidiary not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Covenants—Restricted Payments.”

“Issue Date” means April 27, 2010.

“Joint Venture” means any Person that is not a direct or indirect Subsidiary of the Company in which the Company or any of its Restricted Subsidiaries makes any Investment;provided that the Company and its Restricted Subsidiaries own at least 20% of the Equity Interests of such Person on a fully diluted basis or control the management of such Person pursuant to a contractual agreement.

“Lien” means, with respect to any asset, any mortgage, lien (statutory or otherwise), pledge, charge, security interest, hypothecation, assignment for security, claim, 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 or any lease in the nature thereof, any option or other agreement to grant a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statute) of any jurisdiction other than a precautionary financing statement respecting a lease not intended as a security agreement.

“Moody’s” means Moody’s Investors Service, Inc. or any successor to the rating agency business thereof.

“Net Income” means, with respect to any Person, the consolidated net income (loss) of such Person and its Restricted Subsidiaries, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends, excluding, however:

(1) the aggregate after tax effect of gains and losses realized in connection with any Asset Sale or the disposition of any securities by such Person or any of its Restricted Subsidiaries; and

(2) other than for purposes of “—Covenants—Restricted Payments,” any extraordinary gain or loss, together with any related provision for taxes on such extraordinary gain or loss.

“Net Proceeds” means, with respect to any Asset Sale or sale of Equity Interests, the aggregate proceeds received by the Company or any of its Restricted Subsidiaries in cash or Cash Equivalents in respect of any Asset Sale or sale of Equity Interests (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any such sale), net of, without duplication, (1) the direct costs relating to such Asset Sale or sale of Equity Interests, including, without limitation, brokerage commissions and legal, accounting and investment banking fees, sales commissions, recording fees, title transfer fees, and any relocation expenses incurred as a result thereof, (2) taxes paid or payable as a result thereof, in each case after taking into account any available tax credits or deductions and any tax sharing arrangements, (3) amounts required to be applied to the repayment of Indebtedness secured by a Lien on the asset or Equity Interests that were the subject of such Asset Sale or sale of Equity Interests, (4) all distributions and payments required to be made to minority interest holders in Restricted Subsidiaries as a result of such Asset Sale and (5) any amounts to be set aside in any reserve established in accordance with GAAP or any amount placed in escrow, in either case for adjustment in respect of the sale price of such asset or Equity Interests or for liabilities associated with such Asset Sale or sale of Equity Interests and retained by the Company or any of its Restricted Subsidiaries until such time as such reserve is reversed or such escrow arrangement is terminated, in which case Net Proceeds shall include only the amount of the reserve so reversed or the amount returned to the Company or its Restricted Subsidiaries from such escrow arrangement, as the case may be.

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“Non-Recourse Debt” means Indebtedness as to which:

(1) neither the Company nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a guarantor or otherwise or (c) constitutes the lender of such Indebtedness;

(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 (other than the notes) of the Company or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its Stated Maturity; and

(3) the lenders have been notified in writing (including by the provisions of the agreement governing such Indebtedness) that they will not have any recourse to the stock or assets of the Company or any of its Restricted Subsidiaries, except as contemplated in clause (11) of the definition of “Permitted Liens”.

“Obligations” means any principal, interest, penalties, fees, indemnifications, reimbursement obligations, damages and other liabilities payable under the documentation governing any Indebtedness.

“Operating Surplus” shall have the meaning assigned to such term in the Partnership Agreement, as in effect on the Issue Date.

“Partnership Agreement” means the Third Amended and Restated Agreement of Limited Partnership of the Company, dated as of August 5, 2008, as such has been or may be amended, modified or supplemented from time to time.

“Permitted Asset Swap” means the concurrent purchase and sale or exchange of assets used in a Permitted Business or a combination of assets used in a Permitted Business and cash or Cash Equivalents between the Company or any of its Restricted Subsidiaries and another Person, or any transaction pursuant to Section 1031 of the Code.

“Permitted Business” means:

(1) the business of acquiring, leasing, managing, exploring, exploiting, developing, producing, operating and disposing of interests in coal, oil, natural gas, natural gas liquids and other Hydrocarbon and mineral properties or products produced in association with any of the foregoing, or timberland or timber or forest products, or of creating and/or restoring wetlands and wetland credits;

(2) the business of gathering, marketing, distributing, treating, processing, fractionating, handling, storing, refining, selling and transporting of any production from such interests or properties and products produced in association therewith and the marketing of coal, oil, natural gas, natural gas liquids, other Hydrocarbons and minerals obtained from unrelated Persons;

(3) any other related energy business, directly or indirectly, from coal, oil, natural gas and other Hydrocarbons and minerals, or timber or forest products produced substantially from properties in which the Company or its Restricted Subsidiaries, directly or indirectly, participates; and

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(4) any business or activity relating to, arising from, or necessary, appropriate or incidental to the activities described in the foregoing clauses (1) through (3) of this definition that generates gross income at least 90% of which constitutes “qualifying income” under Section 7704(d)(1)(E) of the Code.

“Permitted Business Investments” means Investments by the Company or any of its Restricted Subsidiaries in any Unrestricted Subsidiary of the Company or in any Joint Venture,providedthat:

(1) either (a) at the time of such Investment and immediately thereafter, the Company could incur $1.00 of additional Indebtedness under the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described under “—Covenants—Incurrence of Indebtedness and Issuance of Disqualified Equity” above or (b) such Investment does not exceed the aggregate amount of Incremental Funds (as defined in the covenant described under “—Covenants—Restricted Payments”) not previously expended at the time of making such Investment;

(2) if such Unrestricted Subsidiary or Joint Venture has outstanding Indebtedness at the time of such Investment, either (a) all such Indebtedness is Non-Recourse Debt or (b) any such Indebtedness of such Unrestricted Subsidiary or Joint Venture that is recourse to the Company or any of its Restricted Subsidiaries (which shall include all Indebtedness of such Unrestricted Subsidiary or Joint Venture for which the Company or any of its Restricted Subsidiaries may be directly or indirectly, contingently or otherwise, obligated to pay, whether pursuant to the terms of such Indebtedness, by law or pursuant to any guarantee) could, at the time such Investment is made, be incurred at that time by the Company and its Restricted Subsidiaries under the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described under “—Covenants—Incurrence of Indebtedness and Issuance of Disqualified Equity;” and

(3) such Unrestricted Subsidiary’s or Joint Venture’s activities are not outside the scope of the Permitted Business.

“Permitted Investments” means:

(1) any Investment in, or that results in the creation of, any Restricted Subsidiary of the Company;

(2) any Investment in the Company or in a Restricted Subsidiary of the Company (excluding redemptions, purchases, acquisitions or other retirements of Equity Interests in the Company);

(3) any Investment in cash or Cash Equivalents;

(4) any Investment by the Company or any Restricted Subsidiary of the Company in a Person if as a result of such Investment:

such Person becomes a Restricted Subsidiary of the Company; or

such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, the Company or a Restricted Subsidiary of the Company;

(5) any Investment made as a result of the receipt of consideration other than cash or Cash Equivalents from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “—Asset Sales;”

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(6) any Investment in a Person to the extent in exchange for the issuance of Equity Interests (other than Disqualified Equity) of the Company;

(7) Investments in stock, obligations or securities received in settlement of debts owing to the Company or any of its Restricted Subsidiaries as a result of bankruptcy or insolvency proceedings or upon the foreclosure, perfection or enforcement of any Lien in favor of the Company or any such Restricted Subsidiary, or in settlement of litigation, arbitration or other disputes, in each case as to debt owing to the Company or any such Restricted Subsidiary that arose in the ordinary course of business of the Company or any such Restricted Subsidiary;

(8) any Investment in Hedging Obligations permitted to be incurred under the “Incurrence of Indebtedness and Issuance of Disqualified Equity” covenant;

(9) other Investments in any Person having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (9) since the Issue Date and existing at the time of the Investment, which is the subject of the determination, was made, not to exceed the greater of (a) $30.0 million and (b) 3.0% of the Consolidated Net Tangible Assets of the Company;

(10) any Investment in the notes and Investments existing on the Issue Date;

(11) Permitted Business Investments;

(12) Investments consisting of purchases and acquisitions of inventory, supplies, materials and equipment or purchases of contract rights or licenses or leases of intellectual property, in each case in the ordinary course of business; and

(13) loans or advances to employees of the Company or its Restricted Subsidiaries made in the ordinary course of business, in an aggregate amount not to exceed $2.0 million at any time outstanding.

“Permitted Liens” means:

(1) Liens securing Indebtedness under the Credit Facilities permitted to be incurred under the covenant “—Incurrence of Indebtedness and Issuance of Disqualified Equity;”

(2) Liens in favor of the Company or any of its Restricted Subsidiaries;

(3) any interest or title of a lessor in the property subject to a Capital Lease Obligation;

(4) Liens on property (including Equity Interests) of a Person existing at the time such Person is merged with or into or consolidated with the Company or any Restricted Subsidiary of the Company;provided that such Liens were in existence prior to, and were not obtained in contemplation of, such merger or consolidation and do not extend to any assets other than those of the Person merged into or consolidated with the Company or such Restricted Subsidiary;

(5) Liens on property existing at the time of acquisition thereof by the Company or any Restricted Subsidiary of the Company;provided that such Liens were in existence prior to, and were not obtained in contemplation of, such acquisition and relate solely to such property, accessions thereto and the proceeds thereof;

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(6) Liens to secure the performance of tenders, bids, leases, statutory or regulatory obligations, surety, indemnity or appeal bonds, government contracts, performance bonds or other obligations of a like nature incurred in the ordinary course of business;

(7) Liens on any property or asset acquired, constructed or improved by the Company or any Restricted Subsidiary, which (a) are in favor of the seller of such property or assets, in favor of the Person constructing or improving such asset or property, or in favor of the Person that provided the funding for the acquisition, construction or improvement of such asset or property, (b) are created within 360 days after the date of acquisition, construction or improvement, (c) secure the purchase price or construction or improvement cost, as the case may be, of such asset or property in an amount not to exceed 100% of the fair market value (as determined by the Board of Directors of the General Partner) of such acquisition, construction or improvement of such asset or property, and (d) are limited to the asset or property so acquired, constructed or improved (including proceeds thereof, accessions thereto and upgrades thereof);

(8) Liens to secure performance of Hedging Obligations of the Company or a Restricted Subsidiary;

(9) Liens existing on the Issue Date and Liens in connection with any extensions, refinancing, renewal, replacement or defeasance of any Indebtedness or other obligation secured thereby;provided that (a) the principal amount of the Indebtedness secured by such Lien is not increased and (b) no assets are encumbered by any such Lien other than the assets encumbered immediately prior to such extension, refinancing, renewal, replacement or defeasance;

(10) Liens on pipelines or pipeline facilities that arise by operation of law;

(11) Liens on and pledges of the Equity Interests of any Unrestricted Subsidiary or any Joint Venture owned by the Company or any Restricted Subsidiary of the Company to the extent securing Non-Recourse Debt of such Unrestricted Subsidiary or Joint Venture;

(12) Liens in favor of collecting or payor banks having a right of setoff, revocation, refund or chargeback with respect to money or instruments of the Company or any of its Restricted Subsidiaries on deposit with or in possession of such bank;

(13) Liens arising under operating agreements, joint venture agreements, partnership agreements, construction agreements, interconnection agreements, coal leases, oil and gas leases, farmout agreements, division orders, contracts for sale, transportation, wheelage, handling, cutting, purchase, gathering, treating, processing, natural gas storage or exchange of coal, or oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements and other similar agreements arising in the ordinary course of the Company’s or any Restricted Subsidiary’s business that are customary in the Permitted Business; provided that any such Liens only attach to the assets covered by the applicable agreement and, in the case of operating agreements, joint venture agreements, partnership agreements and other similar agreements, the Equity Interests of the applicable joint venture, partnership or other Person that is the subject of such agreement;

(14) Liens securing the Obligations of the Issuers under the notes and the Indenture and of the Subsidiary Guarantors under the Guarantees;

(15) Liens upon specific items of inventory or other goods and proceeds thereof of any Person securing such Person’s Obligations in respect of bankers’ acceptances issued or created

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for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods and permitted by the covenant described under “—Covenants—Incurrence of Indebtedness and Issuance of Disqualified Equity;”

(16) Liens securing any indebtedness equally and ratably with all Obligations due under the notes or any Guarantee pursuant to a contractual covenant that limits liens in a manner substantially similar to the covenant entitled “Liens;”

(17) Liens incurred in the ordinary course of business of the Company or any Restricted Subsidiary of the Company with respect to Obligations that do not exceed 5% of the Consolidated Net Tangible Assets of the Company at any one time outstanding; and

(18) any Lien renewing, extending, refinancing or refunding a Lien permitted by clauses (1) through (17) above;provided that (a) the principal amount of Indebtedness secured by such Lien does not exceed the principal amount of such Indebtedness outstanding immediately prior to the renewal, extension, refinance or refund of such Lien, plus all accrued interest on the Indebtedness secured thereby and the amount of all fees, expenses and premiums incurred in connection therewith, and (b) no assets encumbered by any such Lien other than the assets permitted to be encumbered immediately prior to such renewal, extension, refinance or refund are encumbered thereby.

“Permitted Refinancing Indebtedness” means any Indebtedness of the Company or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease, discharge or refund, other Indebtedness of the Company or any of its Restricted Subsidiaries (other than intercompany Indebtedness);provided that:

(1) the principal amount of such Permitted Refinancing Indebtedness does not exceed the principal amount of, plus accrued interest on the Indebtedness so extended, refinanced, renewed, replaced, defeased, discharged or refunded (plus the amount of necessary fees and expenses incurred in connection therewith and any premiums paid on the Indebtedness so extended, refinanced, renewed, replaced, defeased or refunded);

(2) such Permitted Refinancing Indebtedness has a final maturity date no earlier than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being extended, refinanced, renewed, replaced, defeased, discharged or refunded;

(3) if the Indebtedness being extended, refinanced, renewed, replaced, defeased, discharged or refunded is subordinated in right of payment to the notes or the Guarantees, such Permitted Refinancing Indebtedness is subordinated in right of payment to, the notes or the Guarantees, as the case may be, on terms at least as favorable to the holders of notes as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased, discharged or refunded; and

(4) such Indebtedness is not incurred by a Restricted Subsidiary if the Company is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded.

For the avoidance of doubt, the foregoing clauses (1) through (4) shall not apply to extensions, refinancings, renewals, replacements, defeasances or refunds of the Credit Facilities.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or agency or political subdivision thereof or other entity.

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“Qualified Owner” means Penn Virginia Corporation, a Virginia corporation, Penn Virginia GP Holdings, L.P., a Delaware limited partnership, the Company and their respective Subsidiaries and controlled Affiliates .

“Rating Agency” means each of Standard & Poors and Moody’s, or if Standard & Poors 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 Issuers (as certified by a Board Resolution of the General Partner) which shall be substituted for Standard & Poors or Moody’s, or both, as the case may be.

“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 “—Covenants—Reports” (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 an Investment other than a Permitted Investment.

“Restricted Subsidiary” of a Person means any Subsidiary of the referenced Person that is not an Unrestricted Subsidiary. Notwithstanding anything in the Indenture to the contrary, Finance Co. shall be a Restricted Subsidiary of the Company so long as the Company is organized as a partnership.

“Securities Act” means the Securities Act of 1933, as amended.

“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act and the Exchange Act, as such Regulation is in effect on the Issue Date.

“Standard & Poors” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc., or any successor to the rating agency business thereof.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which such payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and shall not include any contingent Obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

“Subordinated Indebtedness” means, with respect to either Issuer, any Indebtedness of such Issuer (whether outstanding on the Issue Date or thereafter incurred) which is expressly subordinate in right of payment to the Obligations of such Issuer under notes pursuant to a written agreement.

“Subsidiary” means, with respect to any Person:

(1) any corporation, association or other business entity (other than an entity referred to in clause (2) below) of which more than 50% of the total Voting Stock is at the time owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2) any partnership (whether general or limited), limited liability company or joint venture (a) the sole general partner or the managing general partner or managing member of which is such Person or a Subsidiary of such Person, or (b) if there are more than a single general partner or member, either (i) the only general partners or managing members of which are such Person and/or one or more Subsidiaries of such Person (or any

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combination thereof) or (ii) such Person owns or controls, directly or indirectly, a majority of the outstanding general partner interests, member interests or other Voting Stock of such partnership, limited liability company or joint venture, respectively.

“Subsidiary Guarantors” means each of:

(1) each Restricted Subsidiary of the Company existing on the Issue Date; and

(2) any other Subsidiary of the Company that becomes a Subsidiary Guarantor in accordance with the provisions of the Indenture,

in each case until such Subsidiary Guarantor ceases to be such in accordance with the Indenture. Notwithstanding anything in the Indenture to the contrary, Finance Co. shall not be a Subsidiary Guarantor.

“U.S. Government Obligations” means securities that are (1) direct Obligations of the United States of America for the payment of which its full faith and credit is pledged and (2) Obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States of America, which, in either case under clause (1) or (2) above, are not callable or redeemable at the option of the issuers thereof.

“Unrestricted Subsidiary” means any Subsidiary of the Company (other than Finance Co. or the Holding Company) that is designated by the Board of Directors of the General Partner as an Unrestricted Subsidiary pursuant to a Board Resolution, but only to the extent that such Subsidiary:

(1) except to the extent permitted by subclause (2)(b) of the definition of “Permitted Business Investments,” has no Indebtedness other than Non-Recourse Debt;

(2) except as permitted under the covenant described above under the caption “—Covenants—Transactions with Affiliates,” is not a party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary of the Company unless the terms of any such arrangement, contract, arrangement or understanding are no less favorable to the Company or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Company; and

(3) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of the Company or any of its Restricted Subsidiaries. Notwithstanding anything in the Indenture to the contrary, Finance Co. shall not be designated as an Unrestricted Subsidiary so long as the Company is organized as a partnership.

Any designation of a Subsidiary of the Company as an Unrestricted Subsidiary shall be evidenced to the Trustee by (i) in case of an Unrestricted Subsidiary with the fair market value of assets under $50.0 million, an officer’s certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “—Covenants—Restricted Payments” and (ii) in case of an Unrestricted Subsidiary with the fair market value of assets equal to or greater than $50.0 million, by a Board Resolution and an officer’s certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “—Covenants—Restricted Payments,” in each case, filed with the Trustee giving effect to such designation.

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“Voting Stock” of any Person as of any date means the Equity Interests of such Person pursuant to which the holders thereof have the general voting power under ordinary circumstances to elect at least a majority of the board of directors, managers, general partners or trustees of such Person (regardless of whether, at the time, Equity Interests of any other class or classes shall have, or might have, voting power by reason of the occurrence of any contingency) or, with respect to a partnership (whether general or limited), any general partner interest in such partnership.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect thereof, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

(2) the then outstanding principal amount of such Indebtedness.

Book-Entry, Delivery and Form

General

The notes initially will be issued in the form of one or more fully registered notes in global form (the “Global Notes”). The Global Notes will be deposited upon issuance with the Trustee as custodian for the Depository Trust Company (“DTC”) and registered in the name of DTC or its nominee, in each case for credit to the accounts of institutions that have accounts with DTC or its nominee (the “DTC participants”) and to the accounts of institutions that have accounts with Euroclear Bank S.A./NV (“Euroclear”) or its nominee participants (the “Euroclear participants” and, collectively with the DTC participants, the “participants”). Each of DTC and Euroclear is referred to herein as a “Book Entry Facility.” Ownership of beneficial interests in the Global Notes will be limited to participants or persons that may hold interests through participants. Ownership of beneficial interest in the Global Notes will be shown on, and the transfer of that ownership will be effected only through, records maintained by a Book Entry Facility or its nominee (with respect to participants interests) for such Global Notes or by participants or persons that hold interests through participants (with respect to beneficial interests of persons other than participants). The laws of some jurisdictions may require that certain purchasers of securities take physical delivery of such securities in definitive form. Such limits and laws may impair the ability to transfer or pledge beneficial interests in the Global Notes.

So long as DTC, or its nominee, is the registered holder of the Global Notes, DTC or such nominee, as the case may be, will be considered the sole legal owner and holder of such notes represented by such Global Notes for all purposes under the Indenture and the notes. Except as set forth below, owners of beneficial interests in the Global Notes will not be entitled to have such Global Notes or any notes represented thereby registered in their names, will not receive or be entitled to receive physical delivery or certificated notes in exchange therefor and will not be considered to be the owners or holders of such Global Notes or any notes represented thereby for any purpose under the notes or the Indenture. We understand that under existing industry practice, in the event an owner of a beneficial interest in a Global Notes desires to take any action that DTC, as the holder of such Global Notes, is entitled to take, DTC would authorize the participants to take such action, and that the participants would authorize beneficial owners owning through such participants to take such action or would otherwise act upon the instructions of beneficial owners owning through them.

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Any payment of principal or interest due on the notes on any interest payment date or at maturity will be made available by us to the Trustee by such date. As soon as possible thereafter, the Trustee will make such payments to DTC or its nominee, as the case may be, as the registered owner of the Global Notes representing such notes in accordance with existing arrangements between the Trustee and the depositary.

We expect that DTC or its nominee, upon receipt of any payment of principal or interest in respect of the Global Notes, will credit immediately the accounts of the related participants with payments in amounts proportionate to their respective beneficial interests in the principal amount of such Global Notes as shown on the records of DTC. We also expect that payments by participants to owners of beneficial interests in the Global Notes held through such participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers in bearer form of registered in “street name,” and will be the responsibility of such participants.

None of us, the Trustee or any payment agent for the Global Notes will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests or for other aspects of the relationship between the depositary and its participants or the relationship between such participants and the owners of beneficial interests in the Global Notes owning through such participants.

Because of time zone differences, the securities account of a Euroclear participant purchasing an interest in a Global Note from a DTC participant will be credited, and any such crediting will be reported to the relevant Euroclear participant, during the securities settlement processing day (which must be a business day for Euroclear) immediately following the DTC settlement date. Cash received in Euroclear as a result of sales of interests in a Global Note by or through a Euroclear participant to a DTC participant will be received with value on the DTC settlement date but will be available in the relevant Euroclear cash account only as of the business day following settlement in DTC.

As long as the notes are represented by a Global Note, DTC’s nominee will be the holder of such notes and therefore will be the only entity that can exercise a right to repayment or repurchase of such notes.

Notice by participants or by owners of beneficial interests in the Global Notes held through such participants of the exercise of the option to elect repayment of beneficial interests in notes represented by the Global Note must be transmitted to the relevant Book Entry Facility in accordance with its procedures on a form required by the relevant Book Entry Facility and provided to participants. In order to ensure that DTC’s nominee will timely exercise a right to repayment with respect to a particular Note, the beneficial owner of such note must instruct the broker or other participant to exercise a right to repayment. Different firms have cut-off times for accepting instructions from their customers and, accordingly, each beneficial owner should consult the broker or other participant through which it holds an interest in a note in order to ascertain the cut-off time by which such an instruction must be given in order for timely notice to be delivered to DTC. We will not be liable for any delay in delivery of notices of the exercise of the option to elect repayment.

Unless and until exchanged in whole or in part for notes in definitive form in accordance with the terms of the notes, the Global Notes may not be transferred except as a whole by DTC to a nominee of DTC or by a nominee of DTC to DTC or another nominee of DTC or by DTC or any such nominee to a successor of DTC or a nominee of each successor.

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Although DTC has agreed to the foregoing procedures in order to facilitate transfers of interests in the Global Notes among participants of a Book Entry Facility, it is under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. None of us or the Trustee will have any responsibility for the performance by a Book Entry Facility or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations. We and the Trustee may conclusively rely on, and shall be protected in relying on, instructions from a Book Entry Facility for all purposes.

The Clearing System

DTC has advised us as follows: DTC is a limited-purpose trust company organized under the laws of the State of New York, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code, and “a clearing agency” registered pursuant to the provisions of section 17A of the Exchange Act. DTC was created to hold securities of institutions that have accounts with its participants and to facilitate the clearance and settlement of securities transactions among its participants in such securities through electronic book-entry changes in accounts of participants, thereby elimination the need for physical movement of securities certificates. DTC’s participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s book-entry system is also available to others such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, whether directly or indirectly.

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CERTAIN UNITED STATES FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS

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, owning 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;

• 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 holders of interests therein.

If any 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 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.

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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, 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.” The possibility of such excess amounts being paid will not cause the notes to be treated as contingent payment debt instruments if there is only a “remote” chance that these contingencies will occur, or if such contingencies are considered “incidental.” We intend to take the position that the possibility that any such contingencies will occur is remote and/or that such contingencies are incidental. Our determination that these contingencies are remote and/or incidental is binding on you unless you disclose your contrary position to the IRS in the manner that is required by applicable U.S. Treasury Regulations. Our determination, however, is not binding on the IRS, and it is possible that the IRS may take a different position, in which case you 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.

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.

Interest on the Notes

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 United States federal income tax purposes.

Disposition of the 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

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accrued but unpaid stated interest which will be recognized as ordinary interest income to the extent you have not previously included such amounts 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. 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 interest on, and the proceeds of the sale or other disposition (including a retirement or redemption) of, notes held by you, and backup withholding may apply to such payments unless 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 that is an individual, corporation, estate or trust that is not a U.S. holder.

Interest on the Notes

Payments to you of interest 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, (i) 10% or more of the capital or profits interests in Penn Virginia Resource Partners, L.P. or (ii) 10% or more of the total combined voting power of Penn Virginia Resource Finance Corporation’s stock entitled to vote;

• you are not a “controlled foreign corporation” that is related to Penn Virginia Resource Partners, L.P. or Penn Virginia Resource Finance Corporation (actually or constructively);

• 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. If you hold the notes through a financial institution or other agent acting on your behalf, you may be required to provide appropriate

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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 estates and trusts, and in certain circumstances certifications as to foreign status of 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 reduction of) withholding under the benefit of a tax treaty (in which case, you generally will be required to provide a U.S. taxpayer identification number), 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 (and, if required by an applicable income tax treaty, is treated as attributable to a permanent establishment maintained by you in the United States); 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 will be subject to tax as described below (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 generally 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 certain U.S. source capital losses.

Income or Gain Effectively Connected with a U.S. Trade or Business

If any interest 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, then the income or gain will be subject to U.S. federal income tax at regular graduated income tax rates, unless an applicable income tax treaty provides otherwise. 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 IRS Form W-8BEN if a treaty exemption applies) or successor form. 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, unless an applicable income tax treaty provides for a lower rate.

Information Reporting and Backup Withholding

Payments to you of interest 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 generally will not apply to payments to you of interest 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

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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 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 a disposition of a note effected outside the United States by a broker that has certain relationships with the United States.

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 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 ACQUIRING, OWNING AND DISPOSING OF OUR 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 dated the date of this prospectus supplement by and among us and the underwriters named below, for whom Wells Fargo Securities, LLC, Banc of America Securities LLC, J.P. Morgan Securities Inc. and RBC Capital Markets Corporation are acting as representatives, we have agreed to sell to each of the underwriters, and each of the underwriters has agreed to purchase from us, severally and not jointly, the principal amount of the notes indicated in the following table.

Underwriter	Principal Amount of Notes
Wells Fargo Securities, LLC	$	105,000,000
Banc of America Securities LLC		31,500,000
J.P. Morgan Securities Inc.		31,500,000
RBC Capital Markets Corporation		31,500,000
BB&T Capital Markets, a division of Scott & Stringfellow, LLC		14,250,000
BNP Paribas Securities Corp.		14,250,000
Mitsubishi UFJ Securities (USA), Inc.		14,250,000
PNC Capital Markets LLC		14,250,000
Barclays Capital Inc.		6,000,000
BMO Capital Markets Corp.		4,500,000
Capital One Southcoast, Inc.		4,500,000
Comerica Securities, Inc.		4,500,000
Credit Suisse Securities (USA) LLC		4,500,000
SG Americas Securities, LLC		4,500,000
TD Securities (USA) LLC		4,500,000
UBS Securities LLC		6,000,000
U.S. Bancorp Investments, Inc.		4,500,000
Total	$	300,000,000

The underwriting agreement provides that the obligations of the underwriters are subject to certain conditions precedent. Under the terms and condition of the underwriting agreement, if the underwriters purchase any of the notes, then they are obligated to purchase all of the notes.

The underwriters propose to offer the notes initially at the price to investors on the cover page of this prospectus supplement and may offer the notes to certain dealers, who may include the underwriters, at that price less a concession not in excess of 0.375% of the principal amount per note. The underwriters may allow, and those dealers may reallow, a concession to certain other broker/dealers not in excess of 0.250% of the principal amount per note. After the initial offering of the notes to the public, the underwriters may change the public offering price and the concession.

We estimate that the total expenses of this offering to be paid by us, excluding underwriting discounts, will be approximately $500,000.

In connection with this offering and in compliance with applicable law, the underwriters may engage in over-allotment, stabilizing and syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934, as amended, or the Exchange Act.

• Over-allotment involves syndicate sales in excess of the offering size, which creates a syndicate short position.

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• The underwriters may also effect transactions which stabilize, maintain or otherwise affect the market price of the notes at levels above those which might otherwise prevail in the open market.

• Such transactions may include placing bids for the notes or effecting purchases of the notes for the purpose of pegging, fixing or maintaining the price of the notes.

• Syndicate covering transactions involve purchases of the notes in the open market after the distribution has been completed in order to cover syndicate short positions.

• Penalty bids permit the representatives of the underwriters to reclaim a selling concession from a syndicate member when the notes sold by that syndicate member are purchased in a syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of preventing or retarding a decline in the market price of the notes. They may also cause the price of the notes to be higher than it would otherwise be in the absence of these transactions. These transactions may be effected in the over-the-counter market or otherwise. The underwriters are not required to engage in any of these activities and such activities, if commenced, may be discontinued at any time.

The notes are offered for sale only in those jurisdictions where it is legal to offer them.

There is no public market for the notes. The notes will not be listed on any securities exchange or included in any automated quotation system. The underwriters have advised us that, following completion of the offering of the notes, they intend to make a market in the notes, as permitted by applicable law. They are not obligated, however, to make a market in the notes, and may discontinue any market-making activities at any time without notice, in their sole discretion. If any of the underwriters ceases to act as a market-maker for the notes for any reason, there can be no assurance that another firm or person will make a market in the notes. Accordingly, we cannot assure you as to the development or liquidity of any market for these notes.

Neither we nor any of the underwriters makes any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the notes. In addition, neither we nor any of the underwriters makes any representation that the underwriters will engage in such transactions or that such transactions, once commenced, will not be discontinued without notice.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, or the Securities Act, or to contribute to payments that the underwriters may be required to make in respect of any such liabilities.In addition, we have agreed that we will not offer, sell, contract to sell or otherwise dispose of any debt securities issued or guaranteed by Penn Virginia Resource Partners and having a term of more than one year (other than the notes) for a period of90days after the date of this prospectus supplement without the prior consent of Wells Fargo Securities, LLC.

In relation to each Member State of the European Economic Area that has implemented the Prospectus Directive (each, a “Relevant Member State”), the Underwriters have represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”) they have 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 that has been approved by the competent

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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 €443,000,000 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 purpose of this provision, the expression of 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.

The Underwriters have represented and agreed that:

• they have only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000 (the “FSMA”) received by it in connection with the issue or sale of the notes in circumstances in which Section 21(1) of the FSMA does not apply to us; and

• they have complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the notes in, from or otherwise involving the United Kingdom.

In the ordinary course of their business, the underwriters and their affiliates have engaged, and may in the future engage, in commercial banking and/or investment banking transactions with us and our affiliates for which they received or will receive customary fees and expenses. In particular, affiliates of certain of the underwriters are lenders under our lenders under our Revolver, which we expect to pay down using the proceeds of this offering, for which they receive customary compensation. In addition, from time to time, certain of our underwriters and their affiliates may effect transactions for their own account or the account of customers, and hold on behalf of themselves or their customers, long or short positions in our debt or equity securities or loans, and may do so in the future.

Conflicts of Interest

Affiliates of each of the underwriters, excluding Credit Suisse Securities (USA) LLC, are lenders or agents under our Revolver. As described under “Use of Proceeds,” we intend to use the net proceeds from this offering to reduce borrowings under our Revolver and, therefore, affiliates of the

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underwriters that are lenders under our Revolver will receive a portion of the net proceeds from this offering. Those underwriters whose affiliates will receive at least 5% of the total net proceeds (not including underwriting compensation) from this offering are considered by FINRA to have a conflict of interest with us in regards to this offering. As a result, this offering is being conducted in accordance with the applicable requirements of FINRA Rule 5110 regarding the underwriting of securities of a company with a member that has a conflict of interest within the meaning of those rules. FINRA Rule 5110 requires that under these circumstances a qualified independent underwriter participate in the preparation of the prospectus and exercise the usual standards of due diligence in respect thereto. Credit Suisse Securities (USA) LLC has agreed to act as the qualified independent underwriter with respect to this offering. We have agreed to indemnify Credit Suisse Securities (USA) LLC in its capacity as qualified independent underwriter against certain liabilities under the Securities Act. No underwriter having a conflict of interest under FINRA Rule 5110 will confirm sales to any account over which the underwriter exercises discretionary authority without the specific written approval of the accountholder.

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LEGAL MATTERS

Certain legal matters in connection with the offering and sale of the notes and the guarantees will be passed upon for us by Vinson & Elkins L.L.P., New York, New York. Certain legal matters in connection with this offering will be passed upon for the underwriters by Cahill Gordon & ReindelLLP, New York, New York.

EXPERTS

Our consolidated balance sheets as of December 31, 2009 and 2008, and the related consolidated statements of income, cash flows and partners’ capital and comprehensive income, for each of the years in the three-year period ended December 31, 2009, and the effectiveness of our internal control over financial reporting as of December 31, 2009, 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.

AVAILABLE INFORMATION

We are subject to the informational requirements of the Exchange Act and file reports and other information with the SEC. You may read and copy any document we file at the SEC’s public reference room at 110 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information on their public reference room. Our SEC filings are also available at the SEC’s website at http://www.sec.gov. You can also obtain information about us at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

Our internet address is http://www.pvresource.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 unitholder who so requests. We also make available free of charge on or through our website our Annual Reports 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 units are listed on the NYSE under the symbol “PVR,” 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.

INCORPORATION 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 base 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 Penn Virginia Resource Partners to “incorporate by reference” the information it has filed with the SEC. This means that Penn Virginia Resource Partners can disclose important

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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 Resource Partners 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 Exchange Act (excluding any information furnished and not filed with the SEC) are incorporated by reference in this prospectus until the termination of each offering under this prospectus.

We incorporate by reference in this prospectus supplement the following documents that we have previously filed with the SEC (Registration File No. 001-16735):

• Annual Report on Form 10-K for the fiscal year ended December 31, 2009, filed March 1, 2010; and

• Current Reports on Form 8-K filed February 19, 2010, March 9, 2010, March 24, 2010, March 25, 2010, March 31, 2010 and April 16, 2010.

These reports contain important information about us, our financial condition and our results of operations.

All documents that we file with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended, after the date of this prospectus supplement and prior to the termination of this offering will also be deemed to be incorporated herein by reference and will automatically update and supersede this information. Nothing in this prospectus supplement shall be deemed to incorporate information furnished to, but not filed with, the SEC pursuant to Item 2.02 or Item 7.01 of Form 8-K (or corresponding information furnished under Item 9.01 or included as an exhibit).

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 Resource Partners, L.P.

Four Radnor Corporate Center, Suite 200

100 Matsonford Road

Radnor, Pennsylvania 19087

Telephone: (610) 687-8900

You should rely only on the information incorporated by reference or provided in this prospectus supplement. If information in incorporated documents conflicts with information in this prospectus supplement you should rely on the most recent information. If information in an incorporated document conflicts with information in another incorporated document, you should rely on the most recent incorporated document. You should not assume that the information in this prospectus supplement or any document incorporated by reference is accurate as of any date other than the date of those documents. We have not authorized anyone else to provide you with any information.

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INDEX TO FINANCIAL STATEMENTS

Penn Virginia Resource Partners, L.P. Audited Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firm	F-2
Consolidated Statements of Income for the Years Ended December 31, 2009, 2008 and 2007	F-4
Consolidated Balance Sheets as of December 31, 2009 and 2008	F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007	F-6
Consolidated Statements of Partners’ Capital and Comprehensive Income for the Years Ended December 31, 2009, 2008 and 2007	F-7
Notes to Consolidated Financial Statements	F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Penn Virginia Resource Partners, L.P.:

We have audited the accompanying consolidated balance sheets of Penn Virginia Resource Partners, L.P., and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Partnership’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 Resource Partners, L.P. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Penn Virginia Resource Partners, L.P.’s internal control over financial reporting as of December 31, 2009, based on criteria established inInternal Control —Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 1, 2010, expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

March 1, 2010

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Penn Virginia Resource Partners, L.P.:

We have audited Penn Virginia Resource Partners, L.P.’s internal control over financial reporting as of December 31, 2009, based on criteria established inInternal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Penn Virginia Resource Partners, L.P.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting (Item 9A(b) herein). Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Penn Virginia Resource Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established inInternal Control —Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Penn Virginia Resource Partners, L.P. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated March 1, 2010 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

March 1, 2010

F-3

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per unit amounts)

	Year Ended December 31,
	2009			2008			2007
Revenues
Natural gas midstream	$	504,789		$	720,002		$	433,174
Coal royalties		120,435			122,834			94,140
Coal services		7,332			7,355			7,252
Other		24,148			31,389			14,879
Total revenues		656,704			881,580			549,445
Expenses
Cost of midstream gas purchased		406,583			612,530			343,293
Operating		35,111			32,677			20,964
Taxes other than income		4,794			4,258			3,036
General and administrative		30,168			26,906			22,915
Impairments		1,511			31,801			—
Depreciation, depletion and amortization		70,235			58,166			41,512
Total expenses		548,402			766,338			431,720
Operating income		108,302			115,242			117,725
Other income (expense)
Interest expense		(24,653	)		(24,672	)		(17,338	)
Other		1,280			(2,907	)		1,804
Derivatives		(19,714	)		16,837			(45,568	)
Net income	$	65,215		$	104,500		$	56,623
General partner’s interest in net income	$	24,962		$	23,715		$	14,224
Limited partners’ interest in net income	$	40,253		$	80,785		$	42,399
Basic and diluted net income per limited partner unit (see Note 14)	$	0.76		$	1.63		$	0.92
Weighted average number of units outstanding, basic and diluted		51,799			49,495			46,103

See accompanying notes to consolidated financial statements.

F-4

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit amounts)

	December 31, 2009			December 31, 2008
Assets
Current assets
Cash and cash equivalents	$	8,659		$	9,484
Accounts receivable, net of allowance for doubtful accounts		82,321			73,267
Derivative assets		1,331			30,431
Other current assets		4,468			4,263
Total current assets		96,779			117,445
Property, plant and equipment		1,162,070			1,093,526
Accumulated depreciation, depletion and amortization		(261,226	)		(198,407	)
Net property, plant and equipment		900,844			895,119
Equity investments		87,601			78,442
Intangible assets, net		83,741			92,672
Derivative assets		1,284			—
Other long-term assets		37,811			35,141
Total assets	$	1,208,060		$	1,218,819
Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	60,679		$	60,390
Accrued liabilities		9,726			10,796
Deferred income		3,839			4,842
Derivative liabilities		11,251			13,585
Total current liabilities		85,495			89,613
Deferred income		5,482			6,150
Other liabilities		16,191			17,359
Derivative liabilities		4,285			6,915
Long-term debt		620,100			568,100
Commitments and contingencies (see Note 17)
Partners’ capital
Common units (51,798,895 at December 31, 2009 and 2008)		471,068			526,927
General partner interest		6,834			8,000
Accumulated other comprehensive income		(1,395	)		(4,245	)
Total partners’ capital		476,507			530,682
Total liabilities and partners’ capital	$	1,208,060		$	1,218,819

See accompanying notes to consolidated financial statements.

F-5

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2009			2008			2007
Cash flows from operating activities
Net income	$	65,215		$	104,500		$	56,623
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		70,235			58,166			41,512
Impairments		1,511			31,801			—
Commodity derivative contracts:
Total derivative losses (gains)		22,700			(11,357	)		50,163
Cash settlements of derivatives		3,000			(38,466	)		(17,779	)
Non-cash interest expense		4,391			2,693			678
Equity earnings, net of distributions received		(2,537	)		(224	)		(285	)
Other		765			(1,408	)		(845	)
Changes in operating assets and liabilities:
Accounts receivable		(8,387	)		5,607			(12,701	)
Accounts payable		1,121			(4,615	)		13,435
Accrued liabilities		3,440			(3,613	)		(1,415	)
Deferred income		(1,671	)		1,145			(1,799	)
Other asset and liabilities		189			(5,053	)		237
Net cash provided by operating activities		159,972			139,176			127,824
Cash flows from investing activities
Acquisitions		(29,580	)		(260,376	)		(176,917	)
Additions to property, plant and equipment		(51,097	)		(71,652	)		(48,123	)
Other		1,147			998			858
Net cash used in investing activities		(79,530	)		(331,030	)		(224,182	)
Cash flows from financing activities
Distributions to partners		(124,009	)		(111,076	)		(89,649	)
Proceeds from borrowings		132,000			453,800			220,500
Repayments of borrowings		(80,000	)		(297,800	)		(27,000	)
Net proceeds from issuance of partners’ capital		—			141,084			860
Debt issuance costs		(9,258	)		(4,200	)		(263	)
Net cash provided by (used in) activities		(81,267	)		181,808			104,448
Net increase (decrease) in cash and cash equivalents		(825	)		(10,046	)		8,090
Cash and cash equivalents – beginning of period		9,484			19,530			11,440
Cash and cash equivalents – end of period	$	8,659		$	9,484		$	19,530
Supplemental disclosure:
Cash paid for interest	$	25,271		$	23,282		$	15,880
Noncash investing activities:
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-6

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL AND COMPREHENSIVE INCOME

(in thousands)

	Common Units				Class B Units					General Partner			Accumulated Other Comprehensive Income (Loss)			Total			Comprehensive Income (Loss)
	Units	Amount			Units		Amount
Balance at December 31, 2006	42,060	$	302,938		4,012		$	102,500		$	5,394		$	(8,652	)	$	402,180		$	70,167
Capital contributions	—		—		—			—			19			—			19
Issuance of units	—		—		34			843			—			—			843
Conversion of class B units	4,046		99,675		(4,046	)		(99,675	)		—			—			—
Distributions ($1.66 per unit)	—		(73,260	)	—			(3,277	)		(13,112	)		—			(89,649	)
Net income allocation	—		44,562		—			(391	)		12,452			—			56,623		$	56,623
Other comprehensive income	—		—		—			—			—			1,260			1,260			1,260
Balance at December 31, 2007	46,106	$	373,915		—		$	—		$	4,753		$	(7,392	)	$	371,276		$	57,883
Public unit offering (See Note 4)	5,150		138,141		—			—			2,943			—			141,084
Issuance of units for acquisition (See Note 3)	543		21,316		—			—			435			—			21,751
Distributions ($1.82 per unit)	—		(89,207	)	—			—			(21,869	)		—			(111,076	)
Net income allocation	—		82,762		—			—			21,738			—			104,500		$	104,500
Other comprehensive income	—		—		—			—			—			3,147			3,147			3,147
Balance at December 31, 2008	51,799	$	526,927		—		$	—		$	8,000		$	(4,245	)	$	530,682		$	107,647
Unit based compensation	—		1,769		—			—			—			—			1,769
Distributions ($1.88 per unit)	—		(97,881	)	—			—			(26,128	)		—			(124,009	)
Net income allocation	—		40,253		—			—			24,962			—			65,215		$	65,215
Other comprehensive income	—		—		—			—			—			2,850			2,850			2,850
Balance at December 31, 2009	51,799	$	471,068		—		$	—		$	6,834		$	(1,395	)	$	476,507		$	68,065

See accompanying notes to consolidated financial statements.

F-7

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

Penn Virginia Resource Partners, L.P. (the “Partnership,” “we,” “us” or “our”) is a publicly traded Delaware limited partnership formed by Penn Virginia Corporation (“Penn Virginia”) in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream.

Our coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. Our coal reserves are primarily located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. We also earn 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.

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. We own and operate natural gas midstream assets located in Oklahoma and Texas. Our 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, we own 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. We also own 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.

Our general partner is Penn Virginia Resource GP, LLC, which is a wholly owned subsidiary of Penn Virginia GP Holdings, L.P. (“PVG”), a publicly traded Delaware limited partnership. At December 31, 2009, Penn Virginia owned an approximately 51% limited partner interest in PVG, as well as the non-economic general partner interest in PVG. At December 31, 2009, PVG owned an approximately 37% limited partner interest in us as well as 100% of our general partner, which owns a 2% general partner interest in us.

2. Summary of Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements include the accounts of the Partnership and all of our wholly owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. We own 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 our 25% member interest in Thunder Creek are recorded in the other revenues line on the consolidated statements of income, and earnings from our 50% member interest in a coal handling venture are recorded in the coal services line on the consolidated statements of income. Our 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. Certain reclassifications have been made to conform to the current period’s presentation. Management has evaluated all activities of the Partnership through the date upon which the

F-8

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2. Summary of Significant Accounting Policies—(continued)

Consolidated Financial Statements were issued, and concluded that no subsequent events have occurred that would require recognition in the Consolidated Financial Statements or disclosure in the Notes to the Consolidated Financial Statements.

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.

Property, Plant and Equipment

Property, plant and equipment consist of our ownership in coal fee mineral interests, our royalty interest in oil and natural gas wells, forestlands, processing facilities, gathering systems, compressor stations and related equipment. Property, plant 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 charged to expense 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 therein. Proven and probable coal reserves have been estimated by our own geologists and outside consultants. Our 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, we carry out core-hole drilling activities on our 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. We deplete timber using a methodology consistent with the units-of-production method, but that is based on the quantity of timber harvested. We determine 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 we retire or sell an asset, we remove its cost and related accumulated depreciation and amortization from our consolidated balance sheets. Upon sale, we record the

F-9

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2. Summary of Significant Accounting Policies—(continued)

difference between the net book value, net of any assumed asset retirement obligation (“ARO”), and proceeds from disposition 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, customer relationships and rights-of-way, and are reviewed for impairment along with their associated property, plant and equipment whenever events or changes in circumstances indicated that the carrying amounts may not be recoverable. See Note 10, “Intangible Assets, net,” for a more detailed description of our intangible assets.

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 12, “Asset Retirement Obligations.” The long-lived assets for which our AROs are recorded include compressor stations, gathering systems and coal processing plants. The amount of an ARO and the costs capitalized represent 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 our natural gas midstream assets, we are obligated under federal regulations to perform limited procedures around the abandonment of pipelines. In some cases, 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, including related intangible assets, 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.

The natural gas midstream segment has completed a number of acquisitions in recent years. See Note 3, “Acquisitions,” for a description of our natural gas midstream 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

F-10

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2. Summary of Significant Accounting Policies—(continued)

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 that we could incur a significant impairment loss on our consolidated statements of income.

Impairment of Goodwill

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 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 loss of $31.8 million. As a result of this impairment loss, 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 9, “Goodwill” for a description of goodwill and the related impairment loss.

Equity Investments

We use the equity method of accounting to account for our 25% member interest in Thunder Creek, as well as our 50% member interest investment in a coal handling joint venture, recording the initial investment at cost. Subsequently, the carrying amount of the investment is increased to reflect our share of income of the investees and capital contributions, and is reduced to reflect our share of losses of the investees or distributions received from the investees as the joint ventures report them. Our share of earnings or losses from Thunder Creek is included in other revenues on the consolidated statements of income, and our share of earnings and losses from the coal handling joint venture is included in coal services on the consolidated statements of income. Other revenues and coal services revenues also include amortization of the amount of the equity investments that exceed

F-11

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2. Summary of Significant Accounting Policies—(continued)

our portion of the underlying equity in net assets. We record this amortization over the life of the contracts acquired in the Thunder Creek acquisition, which is 12 years, and the life of the coal services contracts entered into in connection with the coal handling joint venture, which is 15 years.

Debt Issuance Costs

Debt issuance costs relating to long-term debt have been capitalized and are being amortized and recorded as interest expense over the term of the related debt instrument.

Long-Term Prepaid Minimums

We lease a portion of our reserves from third parties that require monthly or annual minimum rental payments. The prepaid minimums are recoupable from future production and are deferred and charged to coal royalties expense as the coal is subsequently produced. We evaluate the recoverability of the prepaid minimums on a periodic basis; consequently, any prepaid minimums that cannot be recouped are charged to coal royalties expense.

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 84% of our consolidated accounts receivable at December 31, 2009 resulted from our natural gas midstream segment and approximately 16% resulted from our coal and natural resource management segment. Approximately 17% of our natural gas midstream segment accounts receivables and 14% of our consolidated accounts receivable at December 31, 2009 related to one natural gas midstream customer. As of December 31, 2009, no receivables were collateralized, and we had recorded a $1.2 million allowance for doubtful accounts in the natural gas midstream segment. No significant uncertainties related to the collectability of amounts owed to us exist in regard to this natural gas midstream customer. This customer concentration increases our exposure to credit risk on our receivables, since the financial insolvency of this customer could have a significant impact on our results of operations.

Revenues

Natural Gas Midstream Revenues. We recognize revenues from the sale of natural gas liquids (“NGLs”) and residue gas when we sell the NGLs and residue gas produced at our 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

F-12

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2. Summary of Significant Accounting Policies—(continued)

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 and Deferred Income. We recognize coal royalties revenues on the basis of tons of coal sold by our lessees and the corresponding revenues from those sales. Since we do not operate any coal mines, we do 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. Most of our lessees must make minimum monthly or annual payments that are generally recoupable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recoups a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of income. Deferred income also includes unearned income from a coal services facility lease, which is recognized as interest income as it is earned.

Coal Services Revenues. We recognize coal services revenues when lessees use our facilities for the processing, loading and/or transportation of coal. Coal services revenues consist of fees collected from lessees for the use of our loadout facility, coal preparation plants and dock loading facility. We also include equity earnings of our coal handling joint venture in coal services revenues. We recognize our share of income or losses from our investment in a coal handling joint venture as the joint venture reports them to us.

Oil and Gas Royalty Revenues. We recognize oil and gas royalty revenues in connection with royalty interests owned by us. Royalties are recognized as revenue when natural gas, crude oil and NGLs are removed from the respective underground mineral reserve locations. Royalty payments are generally received two months after the products are removed. An accrual is included in accounts receivables for amounts not received during the month removed based on historical trends.

Timber Revenues. We recognize timber revenues based on the volume of timber harvested and sold from our properties.

Producer Services Revenues. We recognize producer services revenues in connection with agent fees for the marketing of Penn Virginia’s and other third parties’ natural gas production. We aggregate third-party volumes and sell those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

Derivative Instruments

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 swaps. All derivative financial instruments are recognized in our consolidated financial statements at

F-13

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2. Summary of Significant Accounting Policies—(continued)

fair value. 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 the board of directors of our general partner. During 2006 we discontinued hedge accounting for commodity derivatives.

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.

We have also entered into interest rate swaps agreements (the “Interest Rate Swaps”) to mitigate our exposure to debt interest expense. 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 the derivatives line item on our consolidated statements of income. During the year ended December 31, 2009, we reclassified a total of $3.4 million from accumulated other comprehensive income (“AOCI”) to earnings related the Interest Rate Swaps. At December 31, 2009, a $1.4 million loss remained in AOCI and will be recognized in interest expense as the Interest Rate Swaps settle. See Note 6, “Derivative Instruments,” for a description of our derivative program.

Income Taxes

As a partnership, we are not a taxable entity and have no federal income tax liability. The taxable income and losses of the Partnership are includable in the federal and state income tax returns of our partners. Net income for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under our partnership agreement.

Net Income per Limited Partner Unit

Effective January 1, 2009, we adopted the new accounting standard addressing the computation of earnings per unit for master limited partnerships that issue multiple classes of securities that participate in partnerships distribtutions. Our securities consist of publicly traded common units held by limited partners, a general partner interest and separately transferable incentive distribution rights (“IDRs”). This standard requires earnings or losses for a reporting period to be allocated to our limited partners, our general partner and holders of IDRs using the two-class method to compute earnings per unit. Under this method, our net income (or loss) for a reporting period is reduced (or increased) by the amount that has been or will be distributed to our participating security holders. In the event that our net income exceeds our distributions (or our distributions exceed our net income), such excess undistributed net income (or loss) is allocated to our limited partners and our general partner in the ratio of 98% and 2%, as provided in our partnership agreement.

F-14

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2. Summary of Significant Accounting Policies—(continued)

Also, on January 1, 2009, we adopted the new accounting standard which determines whether instruments granted in share-based payments transactions are participating securities. Under this standard, unvested unit-based payment awards that contain non-forfeitable rights to distributions or distribution equivalents are participating securities and, therefore, are included in the computation of net income allocable to limited partners pursuant to the two-class method of computing earnings per unit. During 2009, our general partner granted phantom units to employees of our general partner or its affiliates. See Note 16, “Unit-Based Payments.” We have determined that our unvested phantom unit awards contain non-forfeitable rights to distributions and, therefore, are participating securities for purposes of this standard.

Basic and diluted net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner units outstanding during the period. Diluted net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner units outstanding during the period and, when dilutive, phantom units.

Unit-Based Compensation

Our general partner has a long-term incentive plan that permits the grant of awards to directors and employees of our general partner and employees of its affiliates who perform services for us. Awards under our long-term incentive plan can be in the form of common units, restricted units, unit options, phantom units and deferred common units. Our long-term incentive plan is administered by the compensation and benefits committee of our general partner’s board of directors. We reimburse our general partner for payments made pursuant to our long-term incentive plan and recognize compensation expense over the vesting period of the awards.

Authoritative accounting literature establishes standards for transactions in which an entity exchanges its equity instruments for goods and services. This standard requires us 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 16, “Unit-Based Payments,” for a more detailed description of our long-term incentive plan.

New Accounting Standards

In April 2008, an amendment to accounting standards related to the determination of the useful life of intangible assets was issued. This amendment addresses the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible. This amendment is effective for fiscal years beginning after December 15, 2008 and did not have a material impact on our financial statements.

In April 2009, an amendment to business combination standards was issued related to accounting for assets acquired and liabilities assumed in a business combination that arise from contingencies. This amendment addresses application issues raised by preparers, auditors and members of the legal profession on initial recognition and measurement, subsequent measurement and accounting and disclosure of assets and liabilities arising from contingencies in a business combination. The amendment is effective for assets or liabilities arising from contingencies in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2. Summary of Significant Accounting Policies—(continued)

business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. This amendment will have an impact on our accounting for any future acquisitions and our financial statements.

In May 2009, an accounting standard related to Subsequent Events was issued and established principles and requirements for evaluating and reporting subsequent. Disclosures are required as of the date through which subsequent events are evaluated by management and were effective for interim periods ending after June 15, 2009 and apply prospectively. Because these are disclosure requirements only, and do not affect the accounting treatment for subsequent events, the adoption of this accounting standard did not impact our financial statements.

Effective July 1, 2009, we adopted the Financial Accounting Standards Board (“FASB”) accounting standards codification for generally accepted accounting. These standards establish the FASB’s accounting standards codification (the “Codification”) as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with United States generally accepted accounting principles (“U.S. GAAP”). Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. All guidance contained in the Codification carries an equal level of authority. The Codification superseded all existing non-SEC accounting and reporting standards. All other non-grandfathered, non-SEC accounting literature not included in the Codification is non-authoritative. The FASB will not issue new standards in the form of Statements, FASB Staff Positions or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates (“ASUs”). The FASB will not consider ASUs as authoritative in their own right. ASUs will serve only to update the Codification, provide background information about the guidance and provide the bases for conclusions on the change(s) in the Codification. References made to FASB guidance throughout these financials have been updated for the Codification.

In August 2009, the FASB issued guidance on how companies should measure liabilities at fair value. The guidance clarifies that the quoted price for an identical liability should be used. However, if such information is not available, an entity may use the quoted price of an identical liability when traded as an asset, quoted prices for similar liabilities or similar liabilities traded as assets, or another valuation technique (such as the market or income approach). The guidance also indicates that the fair value of a liability is not adjusted to reflect the impact of contractual restrictions that prevent its transfer and indicates circumstances in which quoted prices for an identical liability or quoted price for an identical liability traded as an asset may be considered level 1 fair value measurements. This guidance was effective October 1, 2009. The adoption of this guidance did not have a material impact on our financial statements.

3. Acquisitions

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.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

3. Acquisitions—(continued)

Business Combination

Lone Star Gathering, L.P. (“Lone Star”)

On July 17, 2008, we 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 expanded the geographic scope of the natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin.

We 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 our revolving credit facility (the “Revolver”), 2,009,995 PVG common units (which we purchased from two subsidiaries of Penn Virginia for $61.8 million) and 542,610 of our newly issued 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 our election.

The Lone Star acquisition has been accounted for using the purchase method of accounting. Under the purchase method of 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 (in thousands):

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 included approximately $11.2 million of goodwill, all of which was allocated to the natural gas midstream segment. A significant factor that contributed to the recognition of goodwill was the ability to acquire an established business on the western border of the expanding Barnett Shale play in the Fort Worth Basin. In accordance with goodwill and other intangible assets accounting standards, goodwill recorded in connection with a business combination is not

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

3. Acquisitions—(continued)

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 9, “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 along with the related tangible assets. Based on when the estimated economic benefit will be earned, we estimate the useful lives of these intangible assets to be 20 years. See Note 10, “Intangible Assets, net.”

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 our 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, except per unit data):

	Year Ended December 31,
	2008		2007
	(Unaudited)
Revenues	$	885,147	$	552,439
Net income	$	93,363	$	38,778
Net income per limited partner unit, basic & diluted	$	1.41	$	0.54

Other Business Combinations

In July 2009, we completed an acquisition of the gas processing and residue pipeline facilities in western Oklahoma for approximately $22.6 million in cash. Funding of the acquisition was provided by long-term debt under the Revolver. The acquired assets included a 60 MMcfd processing plant. The purchase price has been allocated as follows: $13.1 million to processing plant and related equipment and $9.5 million to pipelines and compressor stations.

In April 2008, we 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 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 our portion of the underlying equity in the net assets acquired related to customer contracts and related customer relations. This excess is being

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

3. Acquisitions—(continued)

amortized to equity earnings over the life of the underlying contracts, which is 12 years. See Note 8, “Equity Investments.” The earnings are recorded in other revenues on the consolidated statements of income.

In October 2007, we purchased from Penn Virginia oil and gas royalty interests associated with leases of property in eastern Kentucky and southwestern Virginia and with estimated proved oil and gas reserves of 8.7 Bcfe at January 1, 2007. The purchase price for this asset acquisition was $31.0 million in cash and was funded with long-term debt under the Revolver.

In September 2007, we 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 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 June 2007, we 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 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. We 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 these business combinations for the years ended December 31, 2008 and 2007 do not materially change the net income for these periods.

4. Unit Offering

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

5. Fair Value Measurement of Financial Instruments

Effective January 1, 2009, we present fair value measurements and disclosures applicable to both our financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis. Our financial instruments that are subject to fair value disclosures consist of cash and cash equivalents, accounts receivable, accounts payable, derivative instruments and long-term debt. At December 31, 2009, the carrying values of all these financial instruments approximated their fair value.

Authoritative accounting literature 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.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

5. Fair Value Measurement of Financial Instruments—(continued)

• 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).

Nonrecurring Fair Value Measurements

We have completed a number of acquisitions in recent years. See Note 3, “Acquisitions,” for a description of our natural gas midstream 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, AROs and the resulting amount of goodwill, if any. The Sweetwater plant acquisition included nonfinancial assets and liabilities that were measured at fair value during 2009. The cost approach was used to develop the fair values of the Sweetwater plant assets. The cost approach is a technique that uses the reproduction or replacement cost as an initial basis for value. The cost to reproduce or replace the subject asset with a new asset, either identical (reproduction) or having the same utility (replacement), establishes the highest amount a prudent investor is likely to pay. A series of models were used to value the Sweetwater plant and related pipelines. Salient data points for the model included capacities of the processing plant, processing technology, and size and length of pipeline. To the extent that the asset being valued provides less utility than a new one, due to physical deterioration, functional obsolescence, and/or economic obsolescence, the value of the subject asset is adjusted for those reductions in value. Adjustments may be made for age, physical wear and tear, technological inefficiencies, changes in price levels, and reduced demand, among other factors. Related to the Sweetwater plant assets, an ARO liability was recognized. See Note 2, “Summary of Significant Accounting Policies” for a description of the inputs and techniques used to derive ARO fair values. Unrelated to the Sweetwater plant acquisition, there was a fair value measurement of an intangible asset. During 2009 an intangible asset was impaired related to a bankruptcy court’s decision to reject a wheelage agreement associated with a lessee of PVR’s coal and natural resource segment. The following table summarizes the initial fair value estimates for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis by category during 2009 (in thousands):

				Fair Value Measurements, Using
Description	Fair Value Measurements at December  31, 2009			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Sweetwater plant PP&E-noncurrent assets	$	22,772		$	—	$	—	$	22,772
Sweetwater plant ARO-noncurrent liabilities		(208	)		—		—		(208	)
Total	$	22,564		$	—	$	—	$	22,564

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

5. Fair Value Measurement of Financial Instruments—(continued)

Recurring Fair Value Measurements

The following table summarizes the assets and liabilities measured at fair value on a recurring basis and included our derivative financial instruments by categories as of December 31, 2009 (in thousands):

				Fair Value Measurements at December 31, 2009, Using
Description	Fair Value Measurements at December 31, 2009			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Interest rate swap assets – noncurrent	$	1,266		$	—	$	1,266		$	—
Interest rate swap liabilities – current		(7,710	)		—		(7,710	)		—
Interest rate swap liabilities –noncurrent		(3,241	)		—		(3,241	)		—
Commodity derivative assets – current		1,331			—		1,331			—
Commodity derivative assets – noncurrent		18			—		18			—
Commodity derivative liabilities – current		(3,541	)		—		(3,541	)		—
Commodity derivative liabilities –noncurrent		(1,044	)		—		(1,044	)		—
Total	$	(12,921	)	$	—	$	(12,921	)	$	—

The values of both the Interest Rate Swap and commodity derivatives are presented in the derivative assets and derivative liabilities line items on the consolidated balance sheets.

See Note 6, “Derivative Instruments,” for the effects of these instruments on our consolidated statements of income.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

5. Fair Value Measurement of Financial Instruments—(continued)

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

• Commodity derivative instruments : We utilize collar derivative contracts to hedge against the variability in the frac spread. We determine the fair values of our commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. This is a level 2 input. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. See Note 6, “Derivative Instruments.”

• 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. 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. This is a level 2 input. See Note 6, “Derivative Instruments.”

6. Derivative Instruments

Natural Gas Midstream Segment Commodity Derivatives

We utilize costless collars and swap derivative contracts to hedge against the variability in cash flows associated with anticipated natural gas midstream revenues and cost of midstream gas purchased. We also utilize collar derivative contracts to hedge against the variability in our frac spread. Our frac spread is the spread between the purchase price for the natural gas we purchase from producers and the sale price for NGLs that we sell after processing. We hedge against the variability in our 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.

With respect to a costless collar contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the Put (or 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 Call (or ceiling) price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. With respect to a swap contract for the purchase of a commodity, the counterparty is required to make a payment to us if the settlement price for any settlement period is greater than the swap price for such contract, and we are required to make a payment to the counterparty if the settlement price is less than the swap price for such contract.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

6. Derivative Instruments—(continued)

We determine the fair values of our derivative agreements by discounting the cash flows based on quoted forward prices for the respective commodities as of December 31, 2009, using 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. The following table sets forth our positions as of December 31, 2009 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:

	Average Volume Per Day	Swap Price		Weighted Average Price				Fair Value at December 31, 2009
				Put		Call
								(in thousands)
Crude Oil Collar	(barrels)				($ per barrel)
First Quarter 2010 through Fourth Quarter 2010	750			$	70.00	$	81.25	$	(1,329	)
First Quarter 2010 through Fourth Quarter 2010	1,000			$	68.00	$	80.00		(2,171	)
First Quarter 2011 through Fourth Quarter 2011	400			$	75.00	$	98.50		18
Natural Gas Purchase Swap	(MMBtu)		($ per MMBtu)
First Quarter 2010 through Fourth Quarter 2010	5,000	$	5.815						(41	)
First Quarter 2011 through Fourth Quarter 2011	3,000	$	6.430						(99	)
NGL – Natural Gasoline Collar	(gallons)				($ per gallon)
First Quarter 2011 through Fourth Quarter 2011	60,000			$	1.55	$	1.92		(945	)
Settlements to be received in subsequent period									1,331

At December 31, 2009, we reported a net derivative liability related to the natural gas midstream segment of $3.2 million. No amounts remain in AOCI as of December 31, 2008 related to derivatives in the natural gas midstream segment for which we discontinued hedge accounting in 2006, and no amounts have been recorded to AOCI related to the derivative positions as of December 31, 2009.

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 March 2010, the notional amounts of the Interest Rate Swaps total $310.0 million, or approximately 50% of our total long-term debt outstanding as of December 31, 2009, with us 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 London Interbank Offered Rate (“LIBOR”). From March 2010 to December 2011, the notional amounts of the Interest Rate Swaps total $250.0 million with us 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 us paying a weighted average fixed rate of 2.09% on the notional amount, and the

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

6. Derivative Instruments—(continued)

counterparties paying a variable rate equal to the three-month LIBOR. The Interest Rate Swaps extend one year past the maturity of the current Revolver. The Interest Rate Swaps have been entered into with seven financial institution counterparties, with no counterparty having more than 24% of the open positions. The following table sets forth our positions as of December 31, 2009 for the Interest Rate Swaps:

Dates	Notional Amounts		Weighted-Average Fixed Rate		Fair Value at December 31, 2009
					(in thousands)
Until March 2010	$	310.0	3.54	%	$	(2,479	)
March 2010 – December 2011	$	250.0	3.37	%		(8,456	)
December 2011 – December 2012	$	100.0	2.09	%		1,252

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 have been recognized in the derivatives line item on our consolidated statements of income. At December 31, 2009, a $1.4 million loss remained in AOCI related to the Interest Rate Swaps. The $1.4 million loss will be recognized in interest expense as the original forecasted interest payments occur.

We reported a (i) net derivative liability of $9.7 million at December 31, 2009 and (ii) loss in AOCI of $1.4 million at December 31, 2009 related to the Interest Rate Swaps. In connection with periodic settlements, we recognized $3.4 million of net hedging losses in interest expense in the year ended December 31, 2009. Based upon future interest rate curves at December 31, 2009, we expect to realize $7.7 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.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

6. Derivative Instruments—(continued)

Financial Statement Impact of Derivatives

The following table summarizes the effects of our derivative activities, as well as the location of the gains and losses, on our consolidated statements of income for the periods presented (in thousands):

	Location of gain (loss) on derivatives recognized in income	Year Ended December 31,
		2009			2008
Derivatives not designated as hedging instruments:
Commodity contracts(1)	Natural gas midstream revenues	$	—		$	(8,219	)
Commodity contracts(1)	Cost of midstream gas purchased		—			2,739
Interest rate contracts(2)	Interest expense		(3,356	)		(1,706	)
Interest rate contracts	Derivatives		(4,306	)		(8,635	)
Commodity contracts	Derivatives		(15,408	)		25,472
Total increase (decrease) in net income resulting from derivatives		$	(23,070	)	$	9,651
Realized and unrealized derivative impact:
Cash received (paid) for commodity and interest rate	Derivatives		3,000			(38,466	)
Cash paid for interest rate contract settlements	Interest expense		(370	)		(503	)
Unrealized derivative gain (loss)(3)			(25,700	)		48,620
Total increase (decrease) in net income resulting from derivatives		$	(23,070	)	$	9,651

(1) This represents commodity derivative 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.

(2) This represents Interest Rate Swap amounts reclassified out of AOCI and into earnings. During 2008 and 2009 we discontinued hedge accounting for various Interest Rate Swaps at different times. By the first quarter of 2009 we discontinued hedge accounting for the remaining Interest Rate Swaps. During 2009 and 2008 we reclassified $0.4 million and $0.5 million out of AOCI relating to actual hedge settlements accounted for under hedge accounting. During 2009 and 2008 we reclassified $3.0 million and $1.2 million for remaining AOCI that have been reclassified into earnings in the same period or periods relating to Interest Rate Swaps not designated for hedge accounting.

(3) 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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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

6. Derivative Instruments—(continued)

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, 2009 and 2008 (in thousands):

		Fair values as of December 31, 2009				Fair values as of December 31, 2008
	Balance Sheet Location	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Derivatives not designated as hedging instruments:
Interest rate contracts(1)	Derivative assets/liabilities – current	$	—	$	7,710	$	—	$	5,891
Interest rate contracts(1)	Derivative assets/liabilities – noncurrent		1,266		3,241		—		6,915
Commodity contracts	Derivative assets/liabilities – current		1,331		3,541		30,431		7,694
Commodity contracts	Derivative assets/liabilities – noncurrent		18		1,044		—		—
Total derivatives not designated as hedging instruments		$	2,615	$	15,536	$	30,431	$	20,500
Total fair value of derivative instruments		$	2,615	$	15,536	$	30,431	$	20,500

(1) During 2009 and 2008 we discontinued hedge accounting for various Interest Rate Swaps at different times. By the first quarter of 2009 we discontinued hedge accounting for the remaining Interest Rate Swaps. For presentational purposes all Interest Rate Swaps are shown as not designated as hedging instruments for both periods presented, 2009 and 2008, reflecting their accounting status as of December 31, 2009.

See Note 5, “Fair Value Measurement of Financial Instruments” for a description of how the above financial instruments are valued.

The following table summarizes the effect of the Interest Rate Swaps on our total interest expense for the periods presented (in thousands):

	Year Ended December 31,
Source	2009			2008			2007
Interest on borrowings	$	21,523		$	23,641		$	18,861
Capitalized interest(1)		(226	)		(675	)		(786	)
Interest rate swaps		3,356			1,706			(737	)
Total interest expense	$	24,653		$	24,672		$	17,338

(1) Capitalized interest was primarily related to the construction of our natural gas gathering facilities.

The effects of derivative gains (losses), cash settlements of our natural gas midstream commodity derivatives and cash settlements of the 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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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

6. Derivative Instruments—(continued)

The above hedging activity represents cash flow hedges. As of December 31, 2009, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of December 31, 2009, we did not own derivative instruments containing credit risk contingencies.

7. Property and Equipment

The following table summarizes our property and equipment as of December 31, 2009 and 2008 (in thousands):

	As of December 31,
	2009			2008
Coal properties	$	478,803		$	476,787
Compressor stations		62,701			53,392
Gathering systems		372,550			334,522
Coal services equipment		38,474			38,474
Processing plants		55,948			38,150
Land		20,743			20,985
Oil and gas royalties		36,937			36,937
Timber		87,869			87,869
Other property, plant and equipment		8,045			6,410
Total property, plant and equipment		1,162,070			1,093,526
Accumulated depreciation, depletion and amortization		(261,226	)		(198,407	)
Net property, plant and equipment	$	900,844		$	895,119

8. Equity Investments

In 2004, we acquired a 50% interest in Coal Handling Solutions LLC, a joint venture formed to own and operate end-user coal handling facilities. In 2008, we acquired a 25% member interest in Thunder Creek Gas Services LLC, a joint venture that gathers and transports coalbed methane gas in Wyoming’s Powder River Basin for $51.6 million in cash, after customary closing adjustments. See Note 3, “Acquisitions.” We account for these investments under the equity method of accounting. As of December 31, 2009 and 2008, our equity investment totaled $87.6 million and $78.4 million, which exceeded our portion of the underlying equity in net assets by $18.4 million and $20.2 million. The difference is being amortized to equity earnings over the estimated life of the intangible assets at the time of the acquisition. The intangible assets relate to contracts and customer relationships acquired, which are estimated to be from 12 years to 15 years.

In accordance with the equity method, we recognized equity earnings of $7.3 million in 2009, $4.2 million in 2008 and $1.8 million in 2007, with a corresponding increase in the investment. The joint ventures generally pay to us quarterly distributions of our portion of the joint ventures’ cash flows. We received cash distributions from the joint ventures of $4.7 million in 2009, $4.0 million in 2008 and $1.5 million in 2007. Equity earnings related to the 50% interest in Coal Handling Solutions LLC are included in coal services revenues on our consolidated statements of income, and equity earnings related to the 25% member interest in Thunder Creek are recorded in other revenues on our consolidated statements of income. The equity investments for both joint ventures are included in the equity investments line on our consolidated balance sheets.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

8. Equity Investments —(continued)

Summarized financial data for equity investments is as follows (in thousands):

	As of December 31,
	2009		2008
Current assets	$	32,996	$	27,772
Noncurrent assets	$	214,463	$	191,438
Current liabilities	$	4,898	$	14,152
Noncurrent liabilities	$	5,392	$	3,356

	Year Ended December 31,
	2009		2008		2007
Revenues	$	68,106	$	43,687	$	11,347
Expenses	$	34,916	$	25,204	$	5,637
Net income	$	33,190	$	18,483	$	5,710

9. Goodwill

Goodwill is tested for impairment on an annual basis, at a minimum, and more frequently if a triggering event occurs. Our 2008 annual impairment testing of goodwill and other intangible assets resulted in an impairment to goodwill of approximately $31.8 million in the fourth quarter of 2008. The impairment loss, which was triggered by fourth quarter declines in oil and gas spot and futures prices and a decline in our market capitalization, reduces to zero all goodwill recorded in conjunction with acquisitions made by the natural gas midstream segment in 2008 and prior years.

In determining the fair value of the 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 we currently operate differs from the historical environments that drove the factors used to value and record the acquisition of these business units. There is no goodwill balance as of December 31, 2009 and 2008.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

10. Intangible Assets, net

The following table summarizes our net intangible assets as of December 31, 2009 and 2008 (in thousands):

	As of December 31,
	2009			2008
Contracts and customer relationships	$	104,700		$	106,900
Rights-of-way		4,552			4,552
Total intangible assets		109,252			111,452
Accumulated amortization		(25,511	)		(18,780	)
Intangible assets, net	$	83,741		$	92,672

The contracts and customer relationships and rights-of-way were primarily acquired in the Lone Star acquisition. See Note 3, “Acquisitions.” 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, 2009, 2008 and 2007 was approximately $7.4 million, $5.5 million and $4.1 million. As of December 31, 2009 and 2008, accumulated amortization of intangible assets was $25.5 million and $18.8 million. The following table sets forth our estimated aggregate amortization expense for the next five years and thereafter (in thousands):

Year	Amortization Expense
2010	$	6,791
2011		6,285
2012		5,718
2013		5,499
2014		5,346
Thereafter		54,102
Total	$	83,741

11. Allowance for Prepaid Minimums

We establish provisions for losses on long-term prepaid minimums if we determine that we will not recoup all or part of the outstanding balance. Collectability is reviewed periodically and an allowance is established or adjusted, as necessary, using the specific identification method. The allowance is netted against long-term prepaid minimums on our consolidated balance sheets. The following table presents the activity of our allowance for prepaid minimums for the years ended December 31, 2009, 2008 and 2007 (in thousands):

	Year Ended December 31,
	2009		2008		2007
Balance at beginning of period	$	1,972	$	1,646	$	1,737
Charges to expense		138		326		(91	)
Forfeiture of prepaid minimum		—		—		—
Balance at end of period	$	2,110	$	1,972	$	1,646

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

12. Asset Retirement Obligations

The following table reconciles the beginning and ending aggregate carrying amount of our asset retirement obligations for the years ended December 31, 2009 and 2008, which are recorded in other liabilities on our consolidated balance sheets (in thousands):

	Year Ended December 31,
	2009			2008
Balance at beginning of period	$	1,814		$	2,028
Liabilities incurred		208			—
Accretion expense		(8	)		291
Revision of estimate		—			(505	)
Balance at end of period	$	2,014		$	1,814

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

13. Long-Term Debt

The following table summarizes our long-term debt as of December 31, 2009 and 2008 (in thousands):

	As of December 31,
	2009		2008
Revolver – variable rate of 2.5% and 4.4% at December 31, 2009 and 2008	$	620,100	$	568,100
Total debt		620,100		568,100
Less: Current maturities		—		—
Total long-term debt	$	620,100	$	568,100

We capitalized interest costs amounting to $0.2 million and $0.7 million in the years ended December 31, 2009 and 2008 related to the construction of natural gas processing plants.

Revolver

As of December 31, 2009, net of outstanding indebtedness of $620.1 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $178.3 million on the Revolver. In March 2009, we increased the size of our Revolver from $700.0 million to $800.0 million and secured the Revolver with substantially all of our assets. The Revolver matures in December 2011 and is available to us 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 2009, we incurred commitment fees of $0.5 million on the unused portion of the Revolver. The interest rate under the Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 1.25% if we select the base rate indebtedness option under the Revolver or at a rate derived from LIBOR plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based indebtedness option. The weighted average interest rate on indebtedness outstanding under the Revolver during 2009 was approximately 2.7%. We do not have a public credit rating for the Revolver.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

13. Long-Term Debt—(continued)

The financial covenants under the Revolver require us not to exceed specified ratios. The Revolver prohibits us from making distributions to our partners if any potential default, or event of default, as defined in the Revolver, occurs or would result from the distributions. In addition, the Revolver contains various 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, 2009, we were in compliance with all of our covenants under the Revolver.

Notes

In July 2008, we paid an aggregate of $63.3 million to the holders of the Senior Unsecured Notes due 2013 (the “Notes”) to prepay 100% of the aggregate principal amount of the Notes. This amount consisted of approximately $58.4 million aggregate principal amount outstanding on the Notes, $1.1 million in accrued and unpaid interest on the 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 Notes were repaid with long-term debt under the Revolver. While the Notes were outstanding, we had a public credit rating. However, due to the repayment of the Notes, we have elected not to renew this rating. As of December 31, 2007, we owed $64.0 million under the Notes, the current portion of which was $12.6 million. The Notes bore interest at a fixed rate of 6.02%.

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 (in thousands):

Year	Aggregate Maturities  of Principal Amounts
2010	$	—
2011		620,100
2012		—
2013		—
2014		—
Thereafter		—
Total debt, including current maturities	$	620,100

14. Partners’ Capital and Distributions

As of December 31, 2009, partners’ capital consisted of 51.8 million common units, representing a 98% limited partner interest and a 2% general partner interest. As of December 31, 2009, affiliates of Penn Virginia, in the aggregate, owned a 39% interest in us, consisting of 19.6 million common units and a 2% general partner interest.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

14. Partners’ Capital and Distributions—(continued)

Net Income per Limited Partner Unit

Effective January 1, 2009, we adopted the new accounting standard addressing the computation of earnings per share for master limited partnerships that issue multiple classes of securities that participate in partnerships distributions. Our securities consist of publicly traded common units held by limited partners, a general partner interest and separately transferable incentive distribution rights (“IDRs”). This standard requires earnings or losses for a reporting period to be allocated to our limited partners, our general partner and holders of IDRs using the two-class method to compute earnings per unit. Under this method, our net income (or loss) for a reporting period is reduced (or increased) by the amount that has been or will be distributed to our participating security holders. In the event that our net income exceeds our distributions (or our distributions exceed our net income), such excess undistributed net income (or loss) is allocated to our limited partners and our general partner in the ratio of 98% and 2%, as provided in our partnership agreement.

Also on January 1, 2009, we adopted the new accounting standard which determines whether instruments granted in share-based payments transactions are participating securities. Under this standard, unvested unit-based payment awards that contain non-forfeitable rights to distributions or distribution equivalents are participating securities and, therefore, are included in the computation of net income allocable to limited partners pursuant to the two-class method of computing earnings per unit. During the year ended December 31, 2009, our general partner granted phantom units to employees of our general partner or its affiliates. We have determined that our unvested phantom unit awards contain non-forfeitable rights to distributions and, therefore, are participating securities for purposes of this standard.

Basic and diluted net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner units outstanding during the period. Diluted net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner units outstanding during the period and, when dilutive, phantom units. For the year ended December 31, 2009 the average awards of 151,000 phantom units were excluded from the diluted net income per limited partner unit calculation because the inclusion of these phantom units would have had an antidilutive effect.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

14. Partners’ Capital and Distributions—(continued)

The following table reconciles net income and weighted average units used in computing basic and diluted net income per limited partner unit (in thousands, except per unit data):

	Year Ended December 31,
	2009			2008			2007
				As Adjusted			As Adjusted
Net income	$	65,215		$	104,500		$	56,623
Less:
Distributions payable on account of incentive distribution rights		(24,140	)		(22,067	)		(13,358	)
Distributions payable on account of general partner interest		(1,988	)		(1,903	)		(1,600	)
General partner interest in excess of distributions over earnings allocable to the general partner interest		1,166			255			734
Net income allocable to limited partners and participating securities	$	40,253		$	80,785		$	42,399
Less:
Distributions to participating securities		(664	)		—			—
Participating securities’ allocable share of net income		(210	)		—			—
Net income allocable to limited partners	$	39,379		$	80,785		$	42,399
Weighted average limited partner units, basic and diluted		51,799			49,495			46,103
Net income per limited partner unit, basic and diluted	$	0.76		$	1.63		$	0.92

The foregoing amounts reflect the retroactive application of the two new accounting standards described above on certain previously reported items for the years ended 2008 and 2007.

Subordinated Units

Until May 22, 2007, we had Class B units, a separate class of subordinated units representing limited partner interests in us, which were issued to PVG in connection with PVG’s initial public offering. On May 22, 2007, all of our Class B units automatically converted into common units on a one-for-one basis and no Class B units remain outstanding.

Cash Distributions

We distribute 100% of Available Cash (as defined in our partnership agreement) within 45 days after the end of each quarter to unitholders of record and to our general partner. Available Cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established by our general partner for future requirements. Our general partner has the discretion to establish cash reserves that are necessary or appropriate to (i) provide for the proper

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

14. Partners’ Capital and Distributions—(continued)

conduct of our business, (ii) comply with applicable law, any of our debt instruments or other agreements or (iii) provide funds for distributions to unitholders and our general partner for any one or more of the next four quarters.

According to our partnership agreement, our general partner receives incremental incentive cash distributions if cash distributions exceed certain target thresholds as follows:

	Unitholders		General Partner
Quarterly cash distribution per unit:
First target – up to $0.275 per unit	98	%	2	%
Second target – above $0.275 per unit up to $0.325 per unit	85	%	15	%
Third target – above $0.325 per unit up to $0.375 per unit	75	%	25	%
Thereafter – above $0.375 per unit	50	%	50	%

The following table reflects the allocation of total cash distributions paid by us during the years ended December 31, 2009, 2008 and 2007 (in thousands, except per unit data):

	Year Ended December 31,
	2009		2008		2007
Limited partner units	$	97,382	$	89,207	$	76,536
General partner interest (2%)		1,988		1,820		1,562
Incentive distribution rights		24,140		20,049		11,551
Phantom units		499		—		—
Total cash distributions paid	$	124,009	$	111,076	$	89,649
Total cash distributions paid per limited partner unit	$	1.88	$	1.82	$	1.66

On February 12, 2010, we paid a $0.47 quarterly distribution per unit to unitholders of record on February 2, 2010. This distribution was unchanged from the previous distribution paid on November 13, 2009.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to acquire all of the remaining common units held by unaffiliated persons as of a record date to be selected by our general partner, on at least ten but not more than 60 days’ notice, at a price equal to the greater of (i) the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

15. Related Party Transactions

General and Administrative

Penn Virginia charges us for certain corporate administrative expenses which are allocable to us and our subsidiaries. When allocating general corporate expenses, consideration is given to property and equipment, payroll and general corporate overhead. Any direct costs are paid by us. Total corporate administrative expenses charged to us and our subsidiaries totaled $5.3 million, $5.1 million and $4.2 million for the years ended December 31, 2009, 2008 and 2007. These costs are reflected in general and administrative expenses in our consolidated statements of income. At least annually, our management performs an analysis of general corporate expenses based on time allocations of shared employees and other pertinent factors. Based on this analysis, our management believes that the allocation methodologies used are reasonable.

Accounts Payable — Affiliate

Amounts payable to related parties totaled $7.2 million and $8.0 million as of December 31, 2009 and 2008. The balance primarily relates to amounts due to a wholly owned subsidiary of Penn Virginia, Penn Virginia Oil & Gas, L.P. (“PVOG LP”), related to the natural gas gathering and processing agreement between PVR East Texas Gas Processing, LLC (“PVR East Texas”) and PVOG LP. See “—Gathering and Processing Revenues.” These balances are included in accounts payable on our consolidated balance sheets.

Marketing Revenues

PVOG LP and Connect Energy Services, LLC (“Connect Energy”), our wholly owned subsidiary, are parties to a Master Services Agreement effective September 1, 2006. Pursuant to the Master Services Agreement, PVOG LP and Connect Energy have agreed that Connect Energy 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 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. Under the Master Services Agreement, PVOG LP paid fees to Connect Energy of $1.4 million, $3.0 million and $2.2 million for the years ended December 31, 2009, 2008 and 2007. Marketing revenues are included in other revenues on our consolidated statements of income.

Gathering and Processing Revenues

PVR East Texas and PVOG LP are parties to a natural Gas Gathering and Processing Agreement effective April 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 NGLs to PVOG LP for a $0.3115/MMBtu service fee (with an annual CPI adjustment). The Gas Gathering and Processing Agreement has a primary term of 15 years 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. For the years ended December 31, 2009 and 2008, PVOG LP paid PVR East Texas $4.0 million and $2.3 million in fees pursuant to the Gas Gathering and Processing Agreement. These gathering and processing revenues are recorded in the natural gas midstream line on our consolidated statements of income.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

15. Related Party Transactions—(continued)

In addition to the gathering and processing by PVR East Texas, PVOG LP sells the processed natural gas and NGLs to Connect Energy at PVR’s Crossroads Plant, Connect Energy transports them to the marketing location, and then 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. For the years ended December 31, 2009 and 2008, PVOG LP received and recognized revenue of $ 72.5 million and $127.9 million from Connect Energy in connection with such sales. For the years ended December 31, 2009 and 2008, PVR recorded $72.5 million and $127.9 million of natural gas midstream revenue and $72.5 million 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. We take title to the gas prior to transporting it to third parties.

16. Unit-Based Payments

Long-Term Incentive Plan

Authoritative accounting literature establishes standards for transactions in which an entity exchanges its equity instruments for goods and services. These standards requires us 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.

As of December 31, 2009, the Partnership had the Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan (“LTIP”) which is administered by the Compensation and Benefits Committee (the “Committee”) of our general partner, Penn Virginia Resource GP, LLC, and is intended to promote the interest of the Partnership. The LTIP permitted the grant of awards to employees and directors of our general partner and employees of its affiliates who perform services for us. In January 2009, the LTIP was amended to permit the granting of awards covering an aggregate of 3,000,000 common units to employees and directors of our general partner and employees of its affiliates who perform services for us.

Awards under the LTIP can be in the form of common units, restricted units, unit options, phantom units and deferred common units. We reimburse our general partner for payments made pursuant to the LTIP and recognize compensation cost based on the fair value of the awards over the vesting period.

We recognized a total of $4.8 million, $3.2 million and $2.4 million in the years ended December 31, 2009, 2008 and 2007 of compensation expense related to the granting of common units and deferred common units and the vesting of restricted and phantom units granted under the LTIP. These expenses are recorded on the general and administrative expense line on our consolidated statements of income.

Common Units.    Our general partner granted 1,871 common units at a weighted average grant-date fair value of $15.46 per unit to non-employee directors in 2009. Our 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. Our 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.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

16. Unit-Based Payments—(continued)

Deferred Common Units.    A portion of the compensation to the non-employee directors of our general partner is paid in deferred common units. Each deferred common unit represents one 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.

	Number of Deferred Common Units		Weighted Average Grant-Date Fair Value
Balance at January 1, 2007	38,907		$	25.26
Granted and vested	22,311			26.42
Balance at December 31, 2007	61,218			25.68
Granted and vested	30,951			20.36
Converted to common units	(28,600	)		23.70
Balance at December 31, 2008	63,569			23.98
Granted and vested	35,819			15.62
Balance at December 31, 2009	99,388			20.97

In 2008, 28,600 deferred common units converted to common units. The aggregate intrinsic value of deferred common units converted to common units in 2008 and 2006 was $0.7 million and $0.2 million. The fair value of the deferred common units is calculated based on the grant-date unit price.

Restricted Units.    Restricted units vest upon terms established by the Committee. In addition, all restricted units will vest upon a change of control of our general partner or Penn Virginia. If a grantee’s employment with, or membership on the board of directors of, our general partner terminates for any reason, the grantee’s unvested restricted units will be automatically forfeited unless, and to the extent that, the Committee provides otherwise. Distributions payable with respect to restricted units may, in the Committee’s discretion, be paid directly to the grantee or held by our general partner and made subject to a risk of forfeiture during the applicable restriction period. Restricted units generally vest over a three-year period, with one-third vesting in each year.

The following table summarizes the status of our nonvested restricted units as of December 31, 2009 and changes during the year then ended:

	Nonvested Restricted Units		Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2009	221,855		$	26.93
Granted	—			—
Vested	(128,106	)		27.19
Forfeit	(940	)		26.36
Nonvested at December 31, 2009	92,809		$	26.57

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

16. Unit-Based Payments—(continued)

At December 31, 2009, we had $1.2 million of total unrecognized compensation cost related to nonvested restricted units. We expect to reimburse our general partner for that cost over a weighted- average period of 0.3 years. The total grant-date fair value of restricted units that vested in 2009, 2008 and 2007 was $3.5 million, $1.9 million and $1.2 million.

Phantom Units.    A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the Committee, the cash equivalent of the value of a common unit. The Committee determines the time period over which phantom units granted to employees and directors will vest. In addition, all phantom units will vest upon a change of control of our general partner or Penn Virginia. If a director’s membership on the board of directors of our general partner terminates for any reason, or an employee’s employment with our general partner and its affiliates terminates for any reason other than retirement after reaching age 62 and completing 10 years of consecutive service, the grantee’s phantom units will be automatically forfeited unless, and to the extent, the Committee provides otherwise. In 2009, 354,792 phantom unit grants were made under our LTIP. This was the first year for phantom unit grants and 2,379 phantom units were forfeited in 2009. Phantom units generally vest over a three-year period, with one-third vesting in each year. The Committee, in its discretion, may grant tandem distribution equivalent rights with respect to phantom units. A distribution equivalent right is a right to receive an amount in cash equal to, and 30 days after, the cash distributions made with respect to a common unit during the period such phantom unit is outstanding. Payments of distribution equivalent rights associated with units that are expected to vest are recorded as capital distributions; however, payments associated with units that are not expected to vest are recorded as compensation expense.

The following table summarizes the status of our nonvested phantom units as of December 31, 2009 and changes during the year then ended:

	Nonvested Phantom Units		Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2009	—		$	—
Granted	354,792			11.59
Vested	(75,410	)		11.59
Forfeit	(2,379	)		11.59
Nonvested at December 31, 2009	277,003		$	11.59

At December 31, 2009, we had $2.3 million of total unrecognized compensation cost related to nonvested phantom units. The total grant-date fair value of restricted units that vested in 2009 was $0.9 million.

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

17. Commitments and Contingencies

Rental Commitments

Operating lease rental expense in the years ended December 31, 2009, 2008 and 2007 was $7.5 million, $4.5 million and $2.6 million. The following table sets forth our minimum rental commitments for the next five years under all non-cancelable operating leases in effect at December 31, 2009 (in thousands):

Year	Minimum  Rental Commitments
2010	$	4,243
2011		3,413
2012		3,017
2013		2,971
2014		2,893
Thereafter		7,943
Total minimum payments	$	24,480

Our rental commitments primarily relate to equipment and building leases and leases of coal reserve-based properties which we sublease, or intend to sublease, to third parties. The obligation with respect to leased properties which we sublease 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. We believe that the future rental commitments with regard to this subleased property cannot be estimated with certainty.

Firm Transportation Commitments

As of December 31, 2009, we 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 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, 2009 for the next five years and thereafter (in thousands):

Year	Firm Transportation Commitments
2010	$	13,103
2011		5,694
2012		4,508
2013		4,033
2014		3,321
Thereafter		1,661
Total firm transportation commitments	$	32,320

F-39

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

17. Commitments and Contingencies—(continued)

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

Our operations and those of our 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 our 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 us against any and all future environmental liabilities. We regularly visit our coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Our management believes that our operations and those of our lessees comply with existing laws and regulations and does not expect any material impact on our financial condition or results of operations.

As of December 31, 2009 and 2008, our environmental liabilities were $1.0 million and $1.2 million, which represents our best estimate of the liabilities as of those dates related to our coal and natural resource management and natural gas midstream businesses. We have 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 we do not operate any mines and do not employ any coal miners, we are not subject to such laws and regulations. Accordingly, we have not accrued any related liabilities.

18. Comprehensive Income

Comprehensive income represents changes in partners’ capital during the reporting period, including net income and charges directly to partners’ capital which are excluded from net income. The following table sets forth the components of comprehensive income for the periods presented (in thousands):

	Year Ended December 31,
	2009			2008			2007
Net income	$	65,215		$	104,500		$	56,623
Unrealized holding losses on derivative activities		(506	)		(4,039	)		(2,599	)
Reclassification adjustment for derivative activities		3,356			7,186			3,859
Comprehensive income	$	68,065		$	107,647		$	57,883

F-40

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

18. Comprehensive Income—(continued)

Included in the comprehensive income balance at December 31, 2009 is $1.4 million of losses relating to Interest Rate Swaps on which we discontinued hedge accounting. The $1.4 million loss will be recognized in earnings through the end of 2011 as the hedged transactions settle. See Note 6, “Derivative Instruments.”

19. Segment Information

Our operating segments represent components of our business 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 coal and natural resource management operations and our natural gas midstream operations. Accordingly, our reportable segments are as follows:

• Coal and Natural Resource Management — Our coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. Our coal reserves are primarily located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. We also earn 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.

• Natural Gas Midstream — Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. We own and operate natural gas midstream assets located in Oklahoma and Texas. Our 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, we own 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. We also own 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.

The following table presents a summary of certain financial information relating to our segments as of and for the years ended December 31, 2009, 2008 and 2007 (in thousands):

	Revenues						Operating income
	2009		2008		2007		2009			2008			2007
Coal and natural resource management(1)	$	144,600	$	153,327	$	111,639	$	87,528		$	96,296		$	68,811
Natural gas midstream(2)		512,104		728,253		437,806		20,774			18,946			48,914
Consolidated totals	$	656,704	$	881,580	$	549,445	$	108,302		$	115,242		$	117,725
Interest expense								(24,653	)		(24,672	)		(17,338	)
Other								1,280			(2,907	)		1,804
Derivatives								(19,714	)		16,837			(45,568	)
Consolidated net income							$	65,215		$	104,500		$	56,623

F-41

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

19. Segment Information—(continued)

	Additions to property and equipment						DD&A expenses
	2009		2008		2007		2009		2008		2007
Coal and natural resource management	$	2,252	$	27,270	$	177,960	$	31,330	$	30,805	$	22,690
Natural gas midstream		78,425		304,758		47,080		38,905		27,361		18,822
Consolidated totals	$	80,677	$	332,028	$	225,040	$	70,235	$	58,166	$	41,512

	Total assets at December 31,
	2009		2008		2007
Coal and natural resource management(3)	$	574,258	$	600,418	$	610,866
Natural gas midstream(4)		633,802		618,402		320,413
Consolidated totals	$	1,208,060	$	1,218,820	$	931,279

(1) Our coal and natural resource management segment’s revenues for the years ended December 31, 2009, 2008 and 2007 include $1.7 million, $1.8 million and $1.8 million of equity earnings related to our 50% interest in Coal Handling Solutions LLC. See Note 8, “Equity Investments” for a further description.

(2) Our natural gas midstream segment’s revenues for the year ended December 31, 2009 and 2008 include $5.3 million and $2.4 million of equity earnings related to our 25% member interest in Thunder Creek that we acquired in 2008 for $51.6 million. See Note 3, “Acquisitions” for a further description of this acquisition and Note 8, “Equity Investments” for a further description of this segment’s equity investment. Operating income for the year ended December 31, 2008 included a noncash impairment charge of $31.8 million related to the reduction in the value of natural gas midstream goodwill. See Note 9, “Goodwill” for further discussion of this impairment.

(3) Total assets at December 31, 2009, 2008 and 2007 for the coal and natural resource management segment included equity investment of $21.0 million, $23.4 million and $25.6 million related to our 50% interest in Coal Handling Solutions LLC. See Note 8, “Equity Investments” for a further description.

(4) Total assets at December 31, 2009 and 2008 for the natural gas midstream segment included equity investment of $59.8 million and $55.0 million related to our 25% member interest in Thunder Creek that we acquired in 2008. Total assets for the year ended December 31, 2008 include the effects of the Lone Star acquisition. See Note 3, “Acquisitions” and Note 8, “Equity Investments” for a further description. Total assets at December 31, 2007 for the natural gas midstream segment included goodwill of $7.7 million.

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

For the year ended December 31, 2009, two customers of our natural gas midstream segment accounted for $109.5 million and $75.4 million, or 17% and 11%, of our total consolidated net

F-42

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

19. Segment Information—(continued)

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.

For the year ended December 31, 2008, two of our natural gas midstream segment customers accounted for $194.9 million and $93.8 million, or 22% and 11%, of our total consolidated net revenues. For the year ended December 31, 2007, three customers of our natural gas midstream segment accounted for approximately $109.2 million, $61.0 million and $60.5 million, or 20%, 11% and 11%, of our total consolidated net revenues.

Supplemental Quarterly Financial Information (Unaudited, in thousands except unit data)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2009
Revenues	$	156,759	$	149,419	$	155,625	$	194,901
Operating income	$	21,927	$	21,393	$	27,816	$	37,166
Net income	$	9,468	$	13,322	$	18,824	$	23,601
Basic and diluted net income per limited partner unit(1)	$	0.06	$	0.13	$	0.24	$	0.33
Weighted average number of units outstanding, basic and diluted		51,799		51,799		51,799		51,799
2008
Revenues	$	156,814	$	276,505	$	285,276	$	162,985
Operating income (loss)(2)	$	31,234	$	44,329	$	40,023	$	(344	)
Net income	$	34,540	$	9,471	$	44,552	$	15,937
Basic and diluted net income per limited partner unit(1)	$	0.64	$	0.08	$	0.73	$	0.19
Weighted average number of units outstanding, basic and diluted		46,106		48,581		51,663		51,799

(1) The sum of the quarters may not equal the total of the respective year’s net income per limited partner unit due to applying the two-class method of calculating net income per limited partner unit. The 2008 basic and diluted net income per limited partner unit amounts have been recast give application of new accounting standards. See Note 2, “Summary of Significant Accounting Policies.”

(2) Operating income in 2008 included a loss on the impairment of goodwill of $31.8 million that we recorded in the fourth quarter of 2008. See Note 9, “Goodwill.”

F-43

PROSPECTUS

PENN VIRGINIA RESOURCE PARTNERS, L.P.

PENN VIRGINIA RESOURCE FINANCE CORPORATION

COMMON UNITS

DEBT SECURITIES

We may offer and sell the common units, representing limited partner interests of Penn Virginia Resource Partners, L.P., and, together with Penn Virginia Resource Finance Corporation, debt securities described in this prospectus from time to time in one or more classes or series and in amounts, at prices and on terms to be determined by market conditions at the time of our offerings. Penn Virginia Resource Finance Corporation may act as co-issuer of the debt securities, and other subsidiaries of Penn Virginia Resource Partners, L.P. may guarantee the debt securities.

We may offer and sell these securities to or through one or more underwriters, dealers and agents, or directly to purchasers, on a continuous or delayed basis. This prospectus describes the general terms of these common units and debt securities and the general manner in which we will offer the common units and debt securities. The specific terms of any common units and debt securities we offer will be included in a supplement to this prospectus. The prospectus supplement will also describe the specific manner in which we will offer the common units and debt securities.

Our principal executive offices are located at Four Radnor Corporate Center, Suite 200, 100 Matsonford Road, Radnor, Pennsylvania 19087. Our telephone number is (610) 687-8900.

Investing in our common units and the debt securities involves risks. Limited partnerships are inherently different from corporations. You should carefully consider the risk factors described under “Risk Factors” beginning on page 1 of this prospectus before you make an investment in our securities.

Our common units are traded on the New York Stock Exchange under the symbol “PVR.” We will provide information in the prospectus supplement for the trading market, if any, for any debt securities we may offer.

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 April 16, 2010.

TABLE OF CONTENTS

ABOUT THIS PROSPECTUS	1
WHO WE ARE	1
RISK FACTORS	1
WHERE YOU CAN FIND MORE INFORMATION	2
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE	2
FORWARD-LOOKING STATEMENTS	3
USE OF PROCEEDS	4
RATIO OF EARNINGS TO FIXED CHARGES	5
DESCRIPTION OF DEBT SECURITIES	5
DESCRIPTION OF THE COMMON UNITS	14
CASH DISTRIBUTION POLICY	18
MATERIAL PROVISIONS OF OUR PARTNERSHIP AGREEMENT	21
MATERIAL INCOME TAX CONSEQUENCES	31
PLAN OF DISTRIBUTION	50
LEGAL MATTERS	51
EXPERTS	51

In making your investment decision, you should rely only on the information contained or incorporated by reference in this prospectus. We have not authorized anyone to provide you with any other information. If anyone provides you with different or inconsistent information, you should not rely on it.

You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus. You should not assume that the information contained in the documents incorporated by reference in this prospectus is accurate as of any date other than the respective dates of those documents. Our business, financial condition, results of operations and prospects may have changed since those dates.

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ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we have filed with the Securities and Exchange Commission, or the SEC, using a “shelf” registration process. Under this shelf registration process, we may sell, over time, the common units or debt securities described in this prospectus in one or more offerings. This prospectus generally describes Penn Virginia Resource Partners, L.P., Penn Virginia Resource Finance Corporation, the common units, debt securities and the guarantees of the debt securities. Each time we sell common units or debt securities with this prospectus, we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add to, update or change information in this prospectus. Before you invest in our securities, you should carefully read this prospectus and any prospectus supplement and the additional information described under the headings “Where You Can Find More Information” and “Incorporation of Certain Documents by Reference.” To the extent information in this prospectus is inconsistent with information contained in a prospectus supplement, you should rely on the information in the prospectus supplement. You should read both this prospectus and any prospectus supplement, together with additional information described under the headings “Where You Can Find More Information” and “Incorporation of Certain Documents by Reference,” and any additional information you may need to make your investment decision.

WHO WE ARE

Penn Virginia Resource Partners, L.P. is a publicly traded Delaware limited partnership formed by Penn Virginia Corporation (NYSE: PVA) in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. Both in its current limited partnership form and in its previous corporate form, it has managed coal properties since 1882. Penn Virginia Resource Partners, L.P. currently conducts operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream.

Penn Virginia Resource Finance Corporation was incorporated under the laws of the State of Delaware on September 16, 2009, is wholly owned by Penn Virginia Resource Partners, L.P. and has no material assets or any liabilities other than as a co-issuer of debt securities. Its activities are limited to co-issuing debt securities and engaging in other activities incidental thereto.

As used in this prospectus, “we,” “us,” “our” and “Penn Virginia Resource Partners” mean Penn Virginia Resource Partners, L.P. and, where the context requires, our consolidated subsidiaries. References to “our general partner” mean Penn Virginia Resource GP, LLC and references to “Finance Co” mean Penn Virginia Resource Finance Corporation.

Our website address iswww.pvresource.com. The information contained in our website is not part of this prospectus.

For additional information as to our business, properties and financial condition please refer to the documents cited in “Where You Can Find More Information.”

RISK FACTORS

An investment in our securities involves a significant degree of risk. You should carefully consider the risk factors and all of the other information included in this prospectus, any prospectus supplement and the documents we have incorporated by reference into this prospectus and any prospectus supplement, including those in Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2009, or our 2009 Annual Report, as updated by annual, quarterly and other reports and documents we file with the SEC

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after the date of this prospectus and that are incorporated by reference herein, in evaluating an investment in the securities. If any of these risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that event, we may be unable to pay distributions to our unitholders, or pay interest on, or the principal of, any debt securities. In that event, the trading price of the common units could decline or you could lose all or part of your investment. When we offer and sell any securities pursuant to a prospectus supplement, we may include additional risk factors relevant to such securities in the prospectus supplement.

WHERE YOU CAN FIND MORE INFORMATION

Penn Virginia Resource Partners files annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file at the SEC’s public reference room at 110 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information on their public reference room. Our SEC filings are also available at the SEC’s website athttp://www.sec.gov. You can also obtain information about us at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

The SEC allows Penn Virginia Resource Partners to “incorporate by reference” the information it has filed with the SEC. This means that Penn Virginia Resource Partners 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 Resource Partners 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, as amended, or Exchange Act (excluding any information furnished and not filed with the SEC) 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, 2009, filed March 1, 2010.

• Current Reports on Form 8-K filed February 19, 2010, March 9, 2010, March 24, 2010 and March 31, 2010, January 5, 2009, January 15, 2009, February 24, 2009 and March 31, 2009.

• The description of the limited partnership units contained in the Registration Statement on Form 8-A, initially filed October 16, 2001, and any subsequent amendment thereto filed for the purpose of updating such description.

We make available free of charge on or through our Internet website,www.pvresource.com, our Annual Reports 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.

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 Resource Partners, L.P.

Four Radnor Corporate Center, Suite 200

100 Matsonford Road

Radnor, Pennsylvania 19087

Tel: (610) 687-8900

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FORWARD-LOOKING STATEMENTS

Some of the information included in this prospectus and the documents we incorporate by reference contains “forward-looking statements.” 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 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, or NGLs, and coal;

• our ability to access external sources of capital;

• any impairment writedowns of our assets;

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

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

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

• the extent to which the amount and quality of actual production of our coal differs from estimated recoverable coal reserves;

• our ability to generate sufficient cash from our businesses to maintain and pay the quarterly distribution to our general partner and our unitholders;

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

• operating risks, including unanticipated geological problems, incidental to our coal and natural resource management or natural gas midstream business;

• our 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;

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

• the ability of our lessees to produce sufficient quantities of coal on an economic basis from our 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 lessees’ mining operations and related coal infrastructure projects and new processing plants in our natural gas midstream business;

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

• the timing of receipt and availability of necessary governmental permits by us or our lessees;

• hedging results;

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• 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 and permissible levels of mining runoff;

• uncertainties relating to the outcome of current and future litigation regarding mine permitting and the effects of recent regulatory guidance on permitting under the Clean Water Act;

• uncertainties regarding Penn Virginia Corporation’s continued equity interest in the holding company of our general partner and its future business relationship with us;

• 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); and

• other risks set forth in Item 1A, “Risk Factors” in our 2009 Annual Report and the other documents incorporated by reference herein.

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 and in the documents incorporated by reference herein. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus, including those described in the “Risk Factors” section of this prospectus. We will not update these statements unless the securities laws require us to do so.

USE OF PROCEEDS

Except as otherwise provided in the applicable prospectus supplement, we will use the net proceeds we receive from the sale of the securities for general partnership purposes, which may include the repayment of indebtedness, the acquisition of businesses and other capital expenditures and additions to working capital.

Any specific allocation of the net proceeds of an offering of securities to a specific purpose will be determined at the time of the offering and will be described in a prospectus supplement.

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RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our historical consolidated ratio of earnings to fixed charges for the periods indicated:

	Year Ended December 31,
	2005	2006	2007	2008	2009
Ratio of earnings to fixed charges	4.7x	4.8x	3.8x	4.9x	3.3x

For purposes of calculating the ratio of earnings to fixed charges:

• “earnings” represent the aggregate of income from continuing operations (before adjustment for equity earnings), fixed charges and distributions from equity investment, less capitalized interest; and

• “fixed charges” represent interest expense (including amounts capitalized), amortization of debt costs and the portion of rental expense representing the interest factor.

DESCRIPTION OF DEBT SECURITIES

When used in this section “Description of Debt Securities,” the terms “we,” “us,” “our” and “issuers” refer jointly to Penn Virginia Resource Partners and Finance Co, and the terms “Penn Virginia Resource Partners” and “Finance Co” refer strictly to Penn Virginia Resource Partners, L.P. and Penn Virginia Resource Finance Corporation, respectively.

The following is a description of the terms of the debt securities, which may be either senior debt securities or subordinated debt securities, and which we collectively refer to as the debt securities. The descriptions below relating to the debt securities and the indentures are summaries of the anticipated provisions thereof, do not purport to be complete and are subject to, and are qualified in their entirety by reference to, all of the provisions of the applicable indenture and any applicable U.S. federal income tax considerations as well as any applicable modifications of or additions to the general terms described below in the applicable prospectus supplement. The applicable prospectus supplement may also state that any of the terms set forth herein are inapplicable to such series of debt securities.

If we offer senior debt securities, we will issue them under a senior indenture. If we offer subordinated debt securities, we will issue them under a subordinated indenture. A form of each indenture is filed as an exhibit to the registration statement of which this prospectus is a part. We have not restated either indenture in its entirety in this description. You should read the relevant indenture because it, and not this description, controls your rights as holders of the debt securities. Capitalized terms used in the summary have the meanings specified in the indentures.

General

The debt securities will be:

• our direct general obligations;

• either senior debt securities or subordinated debt securities; and

• issued under separate indentures (which may be existing indentures) among us, the guarantors and a trustee that we will name in the related prospectus supplement.

The term “Trustee” as used in this prospectus shall refer to the trustee under either of the above indentures. The debt securities will be governed by the provisions of the related indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939.

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Penn Virginia Resource Partners may issue debt securities in one or more series, and Finance Co may be a co-issuer of one or more series of debt securities. Finance Co was incorporated under the laws of the State of Delaware on September 16, 2009, is wholly owned by Penn Virginia Resource Partners and has no material assets or any liabilities other than as a co-issuer of debt securities. Its activities are limited to co-issuing debt securities and engaging in other activities incidental thereto.

Specific Terms of Each Series of Debt Securities

The indenture does not limit the total amount of debt securities that may be issued. Debt securities under the indenture may be issued from time to time in separate series, up to the aggregate amount authorized for each such series.

We will prepare a prospectus supplement and either a supplemental indenture or a resolution of the board of directors of the general partner and the board of directors of Finance Co, and accompanying officers’ certificates relating to any series of debt securities that we offer, which will include specific terms relating to some or all of the following:

• whether Finance Co will be a co-issuer of the debt securities;

• the guarantors of the debt securities, if any;

• whether the debt securities are senior or subordinated debt securities and, if subordinated debt securities, the specific subordination provision applicable thereto;

• whether the debt securities are secured or unsecured;

• the form and title of the debt securities;

• the total principal amount of the debt securities and any limit on such total principal amount;

• the price at which we will issue the debt securities;

• the date or dates on which the debt securities may be issued;

• the portion of the principal amount which will be payable if the maturity of the debt securities is accelerated;

• any right the issuer 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 analogous provision, or option of the holder thereof, that would obligate the issuer to repurchase, repay or otherwise redeem the debt securities, and the period or periods within which, the price or prices at which, and the other terms and conditions upon which such debt securities will be repurchased, repaid or redeemed;

• whether the debt securities are entitled to the benefits of any guarantees by subsidiary guarantors;

• whether the debt securities may be issued in amounts other than $1,000 each or multiples thereof;

• deletions from, modifications of or additions to the events of default or covenants with respect to debt securities of the series, whether or not such events of default or covenants are consistent with the events of default or covenants described herein; and

• any other terms of the series of debt securities and any additions, deletions or modifications to the applicable indenture.

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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;

• 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.

Interest payments may be made 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.

Any funds paid to a paying agent for the payment of amounts due on any debt securities that remain unclaimed for two years will be returned to the issuer, and the holders of the debt securities must look only to the issuer for payment after that time.

Guarantees

If specified in the prospectus supplement respecting a series of debt securities, the subsidiaries of Penn Virginia Resource Partners specified in the prospectus supplement will fully and unconditionally guarantee to each holder and the Trustee, on a joint and several basis, the due and punctual payment of principal of, premium, if any, and interest on the debt securities of that series when and as the same become due and payable, whether at maturity, upon redemption or repurchase, by declaration of acceleration or otherwise, and will execute a notation of guarantee as further evidence of their guarantee. If a series of debt securities is guaranteed, such series will be guaranteed by substantially all subsidiaries other than (i) subsidiaries that are minor and (ii) Finance Co, if it is a co-issuer of such debt securities. The applicable prospectus supplement will describe any limitation on the maximum amount of any particular guarantee and the conditions under which guarantees may be released.

The guarantees will be general and unsecured obligations of the guarantors. Guarantees of subordinated debt securities will be subordinated to the senior indebtedness of the guarantors on the same basis as the subordinated debt securities are subordinated to the senior indebtedness of Penn Virginia Resource Partners.

Covenants

Reports

The indenture contains the following covenant for the benefit of the holders of all series of debt securities:

So long as any debt securities are outstanding, Penn Virginia Resource Partners will:

• for as long as it is required to file information with the SEC pursuant to the Exchange Act, file with the Trustee, within 15 days after it is required to file with the SEC, copies of the annual report and of the information, documents and other reports which it is required to file with the SEC pursuant to the Exchange Act;

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• if it is not required to file information with the SEC pursuant to the Exchange Act, file with the Trustee, within 15 days after it would have been required to file with the SEC, financial statements and a Management’s Discussion and Analysis of Financial Condition and Results of Operations, both comparable to what it would have been required to file with the SEC had it been subject to the reporting requirements of the Exchange Act; and

• if it is required to furnish annual or quarterly reports to our unitholders pursuant to the Exchange Act, file with the Trustee any annual report or other reports sent to unitholders generally.

A series of debt securities may contain additional financial and other covenants. The applicable prospectus supplement will contain a description of any such covenants that are added to the indenture specifically for the benefit of holders of a particular series.

Events of Default, Remedies and Notice

Events of Default

Each of the following events will be an “Event of Default” under the indenture with respect to a series of debt securities:

• default in any payment of interest on any debt securities of that series when due that continues for 30 days;

• default in the payment of principal of or premium, if any, on any debt securities of that series when due at its stated maturity, upon redemption, upon required repurchase or otherwise;

• default in the payment of any sinking fund payment on any debt securities of that series when due;

• failure by the issuer or, if the series of debt securities is guaranteed by a guarantor, the guarantor, to comply for 60 days after notice with the other agreements contained in the indenture, any supplement to the indenture or any board resolution authorizing the issuance of that series;

• certain events of bankruptcy, insolvency or reorganization of the issuer or, if the series of debt securities is guaranteed, of the guarantors; or

• if the series of debt securities is guaranteed by the 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

— the guarantor denies or disaffirms its obligations under the indenture or its guarantee.

Exercise of Remedies

If an Event of Default, other than an Event of Default described in the fifth bullet point above, occurs and is continuing, the Trustee or the holders of at least 25% in principal amount of the outstanding debt securities of that series may declare the entire principal of, premium, if any, and accrued and unpaid interest, if any, on all the debt securities of that series to be due and payable immediately.

A default under the fourth bullet point above will not constitute an Event of Default until the Trustee or the holders of at least 25% in principal amount of the outstanding debt securities of that series notify us and, if the series of debt securities is guaranteed by guarantors, the guarantors, of the default and such default is not cured within 60 days after receipt of notice.

If an Event of Default described in the fifth bullet point above occurs and is continuing, the principal of, premium, if any, and accrued and unpaid interest on all outstanding debt securities of all series will become immediately due and payable without any declaration of acceleration or other act on the part of the Trustee or any holders.

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The holders of a majority in principal amount of the outstanding debt securities of a series may:

• waive all past defaults, except with respect to nonpayment of principal, premium or interest; and

• rescind any declaration of acceleration by the Trustee or the holders with respect to the debt securities of that series, but only if:

— rescinding the declaration of acceleration would not conflict with any judgment or decree of a court of competent jurisdiction; and

— all existing Events of Default have been cured or waived, other than the nonpayment of principal, premium or interest on the debt securities of that series that have become due solely by the declaration of acceleration.

If an Event of Default occurs and is continuing, the Trustee will be under no obligation, except as otherwise provided in the indenture, 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 costs, liability or expense. No holder may pursue any remedy with respect to the indenture or the debt securities of any series, except to enforce the right to receive payment of principal, premium or interest when due, unless:

• such holder has previously given the Trustee notice that an Event of Default with respect to that series is continuing;

• holders of at least 25% in principal amount of the outstanding debt securities of that series have requested that the Trustee pursue the remedy;

• such holders have offered the Trustee reasonable indemnity or security against any cost, liability or expense;

• the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of indemnity or security; and

• the holders of a majority in principal amount of the outstanding debt securities of that series have not given the Trustee a direction that, in the opinion of the Trustee, is inconsistent with such request within such 60-day period.

The holders of a majority in principal amount of the outstanding debt securities of a series have the right, subject to certain restrictions, to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any right or power conferred on the Trustee with respect to that series of debt securities. The Trustee, however, may refuse to follow any direction that:

• conflicts with law;

• is inconsistent with any provision of the indenture;

• the Trustee determines is unduly prejudicial to the rights of any other holder; or

• would involve the Trustee in personal liability.

Notice of Event of Default

Within 30 days after the occurrence of an Event of Default, we are required to give written notice to the Trustee and indicate the status of the default and what action we are taking or propose to take to cure the default. In addition, we are required to deliver to the Trustee, within 120 days after the end of each fiscal year, a compliance certificate indicating that we have complied with all covenants contained in the indenture or whether any default or Event of Default has occurred during the previous year.

If an Event of Default occurs and is continuing and is known to the Trustee, the Trustee must mail to each holder a notice of the Event of Default by the later of 90 days after the Event of Default occurs or 30 days after

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the Trustee knows of the Event of Default. Except in the case of a default in the payment of principal, premium or interest with respect to any debt securities, the Trustee may withhold such notice, but only if and so long as the board of directors, the executive committee or a committee of directors or responsible officers of the Trustee in good faith determines that withholding such notice is in the interests of the holders.

Amendments and Waivers

The issuer may amend the indenture without the consent of any holder of debt securities to:

• cure any ambiguity, omission, defect or inconsistency;

• convey, transfer, assign, mortgage or pledge any property to or with the Trustee;

• provide for the assumption by a successor of our obligations under the indenture;

• add guarantors with respect to the debt securities;

• change or eliminate any restriction on the payment of principal of, or premium, if any, on, any debt securities;

• secure the debt securities;

• add covenants for the benefit of the holders or surrender any right or power conferred upon the issuer, the co-issuer or any guarantor;

• make any change that does not adversely affect the rights of any holder;

• add or appoint a successor or separate Trustee; or

• comply with any requirement of the SEC in connection with the qualification of the indenture under the Trust Indenture Act.

In addition, the issuer may amend the indenture if the holders of a majority in principal amount of all debt securities of each series that would be affected then outstanding under the indenture consent to it. The issuer may not, however, without the consent of each holder of outstanding debt securities of each series that would be affected, amend the indenture to:

• reduce the percentage in principal amount of debt securities of any series whose holders must consent to an amendment;

• reduce the rate of or extend the time for payment of interest on any debt securities;

• reduce the principal of or extend the stated maturity of any debt securities;

• reduce the premium payable upon the redemption of any debt securities or change the time at which any debt securities may or shall be redeemed;

• make any debt securities payable in other than U.S. dollars;

• in the case of any subordinated debt security, make any change in the subordination provisions that adversely affects the rights of any holder under these provisions;

• impair the right of any holder to receive payment of premium, principal or interest with respect to such holder’s debt securities on or after the applicable due date;

• impair the right of any holder to institute suit for the enforcement of any payment with respect to such holder’s debt securities;

• release any security that has been granted in respect of the debt securities;

• make any change in the amendment provisions which require each holder’s consent;

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• in the case of any subordinated debt security, make any change in the subordination provisions that limits or terminates the benefits applicable to any holder of senior indebtedness of Penn Virginia Resource Partners;

• make any change in the waiver provisions; or

• release a guarantor or modify such guarantor’s guarantee in any manner adverse to the holders.

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. After an amendment under the indenture becomes effective, the issuer is required to mail to all holders a notice briefly describing the amendment. The failure to give, or any defect in, such notice, however, will not impair or affect the validity of the amendment.

The holders of a majority in aggregate principal amount of the outstanding debt securities of each affected series, on behalf of all such holders, and subject to certain rights of the Trustee, may waive:

• compliance by the issuer, the co-issuer or a guarantor with certain restrictive provisions of the indenture; and

• any past default under the indenture, subject to certain rights of the Trustee under the indenture;

except that such majority of holders may not waive a default: (i) in the payment of principal, premium or interest or (ii) in respect of a provision that under the indenture cannot be amended without, in the case of either (i) or (ii), the consent of all holders of the series of debt securities that is affected.

Defeasance

At any time, the issuer may terminate, with respect to debt securities of a particular series, all of its obligations under such series of debt securities and the indenture, which we call a “legal defeasance.” If the issuer decides to make a legal defeasance, however, the issuer may not terminate its obligations:

• relating to the defeasance trust;

• to register the transfer or exchange of the debt securities;

• to replace mutilated, destroyed, lost or stolen debt securities; or

• to maintain a registrar and paying agent in respect of the debt securities.

If the issuer exercises its legal defeasance option, any guarantee will terminate with respect to that series of debt securities.

At any time the issuer may also effect a “covenant defeasance,” which means it has elected to terminate its obligations under:

• covenants applicable to a series of debt securities and described in the prospectus supplement applicable to such series, other than as described in such prospectus supplement;

• the bankruptcy provisions with respect to the guarantors, if any; and

• the guarantee provision described under “Events of Default” above with respect to a series of debt securities.

The legal defeasance option may be exercised notwithstanding a prior exercise of the covenant defeasance option. If the legal defeasance option is exercised, payment of the affected series of debt securities may not be accelerated because of an Event of Default with respect to that series. If the covenant defeasance option is

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exercised, payment of the affected series of debt securities may not be accelerated because of an Event of Default specified in the fourth, fifth (with respect only to a guarantor (if any)) or sixth bullet points under “—Events of Default” above or an Event of Default that is added specifically for such series and described in a prospectus supplement.

In order to exercise either defeasance option, the issuer must:

• irrevocably deposit in trust with the Trustee money or certain U.S. government obligations for the payment of principal, premium, if any, and interest on the series of debt securities to redemption or maturity, as the case may be;

• comply with certain other conditions, including that no default has occurred and is continuing after the deposit in trust; and

• deliver to the Trustee an opinion of counsel to the effect that holders of the series of debt securities will not recognize income, gain or loss for federal income tax purposes as a result of such 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 IRS, or other change in applicable federal income tax law.

No Personal Liability

None of the past, present or future partners, incorporators, managers, members, directors, officers, employees, unitholders or stockholders of either issuer, the general partner of Penn Virginia Resource Partners or any guarantor will have any liability for the obligations of the issuers or any guarantors under either indenture or the debt securities or for any claim based on such obligations or their creation.

By accepting a debt security, each holder will be deemed to have waived and released all such liability. This waiver and release are part of the consideration for our issuance of the debt securities. This waiver may not be effective, however, to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

Provisions Relating only to the Senior Debt Securities

The senior debt securities will rank equally in right of payment with all of our other senior and unsubordinated debt. The senior debt securities will be effectively subordinated, however, to all of our secured debt to the extent of the value of the collateral for that debt. We will disclose the amount of our secured debt in the prospectus supplement.

Provisions Relating only to the Subordinated Debt Securities

Subordinated Debt Securities Subordinated to Senior Indebtedness

The subordinated debt securities will rank junior in right of payment to all of the Senior Indebtedness of Penn Virginia Resource Partners. “Senior Indebtedness” will be defined in a supplemental indenture or authorizing resolutions respecting any issuance of a series of subordinated debt securities, and the definition will be set forth in the prospectus supplement.

Payment Blockages

The subordinated indenture will provide that no payment of principal, interest and any premium on the subordinated debt securities may be made in the event:

• we or our property is involved in any voluntary or involuntary liquidation or bankruptcy;

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• we fail to pay the principal, interest, any premium or any other amounts on any Senior Indebtedness of Penn Virginia Resource Partners within any applicable grace period or the maturity of such Senior Indebtedness is accelerated following any other default, subject to certain limited exceptions set forth in the subordinated indenture; or

• any other default on any Senior Indebtedness of Penn Virginia Resource Partners occurs that permits immediate acceleration of its maturity, in which case a payment blockage on the subordinated debt securities will be imposed for a maximum of 179 days at any one time.

No Limitation on Amount of Senior Debt

The subordinated indenture will not limit the amount of Senior Indebtedness that Penn Virginia Resource Partners may incur, unless otherwise indicated in the applicable prospectus supplement.

Book Entry, Delivery and Form

A series of debt securities may be issued in the form of one or more global certificates deposited with a depositary. We expect that The Depository Trust Company, New York, New York, or “DTC,” will act as depositary. If a series of debt securities is issued in book-entry form, one or more global certificates will be issued and deposited with or on behalf of DTC and physical certificates will not be issued to each holder. A global security may not be transferred unless it is exchanged in whole or in part for a certificated security, except that DTC, its nominees and their successors may transfer a global security as a whole to one another.

DTC will keep a computerized record of its participants, such as a broker, whose clients have purchased the debt securities. The participants will then keep records of their clients who purchased the debt securities. Beneficial interests in global securities will be shown on, and transfers of beneficial interests in global securities will be made only through, records maintained by DTC and its participants.

DTC advises us that it is:

• a limited-purpose trust company organized under the New York Banking Law;

• a “banking organization” within the meaning of the New York Banking Law;

• a member of the United States Federal Reserve System;

• a “clearing corporation” within the meaning of the New York Uniform Commercial Code; and

• a “clearing agency” registered under the provisions of Section 17A of the Exchange Act.

DTC is owned by a number of its participants and by the New York Stock Exchange, Inc., The American Stock Exchange, Inc. and the Financial Industry Regulatory Authority, or FINRA. The rules that apply to DTC and its participants are on file with the SEC.

DTC holds securities that its participants deposit with DTC. DTC also records the settlement among participants of securities transactions, such as transfers and pledges, in deposited securities through computerized records for participants’ accounts. This eliminates the need to exchange certificates. Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations.

Principal, premium, if any, and interest payments due on the global securities will be wired to DTC’s nominee. The issuer, the Trustee and any paying agent will treat DTC’s nominee as the owner of the global securities for all purposes. Accordingly, the issuer, the Trustee and any paying agent will have no direct responsibility or liability to pay amounts due on the global securities to owners of beneficial interests in the global securities.

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It is DTC’s current practice, upon receipt of any payment of principal, premium, if any, or interest, to credit participants’ accounts on the payment date according to their respective holdings of beneficial interests in the global securities as shown on DTC’s records. In addition, it is DTC’s current practice to assign any consenting or voting rights to participants, whose accounts are credited with debt securities on a record date, by using an omnibus proxy.

Payments by participants to owners of beneficial interests in the global securities, as well as voting by participants, will be governed by the customary practices between the participants and the owners of beneficial interests, as is the case with debt securities held for the account of customers registered in “street name.” Payments to holders of beneficial interests are the responsibility of the participants and not of DTC, the Trustee or us.

Beneficial interests in global securities will be exchangeable for certificated securities with the same terms in authorized denominations only if:

• DTC notifies the issuer that it is unwilling or unable to continue as depositary or if DTC ceases to be a clearing agency registered under applicable law and a successor depositary is not appointed by the issuer within 90 days; or

• the issuer determines not to require all of the debt securities of a series to be represented by a global security and notifies the Trustee of the decision.

The Trustee

A separate trustee may be appointed for any series of debt securities. We may maintain banking and other commercial relationships with the Trustee and its affiliates in the ordinary course of business, and the Trustee may own debt securities.

Governing Law

The indenture and the debt securities will be governed by, and construed in accordance with, the laws of the State of New York.

DESCRIPTION OF THE COMMON UNITS

The common units represent limited partner interests in Penn Virginia Resource Partners, L.P. that entitle the holders to participate in our cash distributions and to exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units, holders of subordinated units and our general partner in and to partnership distributions, together with a description of the circumstances under which subordinated units convert into common units, see “Cash Distribution Policy” in this prospectus.

Our outstanding common units are listed on the New York Stock Exchange under the symbol “PVR.”

The transfer agent and registrar for our common units is American Stock Transfer & Trust Company.

Status as Limited Partner or Assignee

Except as described under “— Limited Liability,” the common units will be fully paid, and the unitholders will not be required to make additional capital contributions to us.

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Transfer of Common Units

Each purchaser of common units offered by this prospectus must execute a transfer application. By executing and delivering a transfer application, the purchaser of common units:

• becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;

• automatically requests admission as a substituted limited partner in our partnership;

• agrees to be bound by the terms and conditions of, and executes, our partnership agreement;

• represents that he has the capacity, power and authority to enter into the partnership agreement;

• grants powers of attorney to officers of the general partner and any liquidator of our partnership as specified in the partnership agreement; and

• makes the consents and waivers contained in the partnership agreement.

An assignee will become a substituted limited partner of our partnership for the transferred common units upon the consent of our general partner and the recording of the name of the assignee on our books and records. The general partner may withhold its consent in its sole discretion.

Transfer applications may be completed, executed and delivered by a purchaser’s broker, agent or nominee. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders’ rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired, the purchaser has the right to request admission as a substituted limited partner in our partnership for the purchased common units. A purchaser of common units who does not execute and deliver a transfer application obtains only:

• the right to assign the common unit to a purchaser or transferee; and

• the right to transfer the right to seek admission as a substituted limited partner in our partnership for the purchased common units.

Thus, a purchaser of common units who does not execute and deliver a transfer application:

• will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application; and

• may not receive some federal income tax information or reports furnished to record holders of common units.

Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units

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plus his share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by the limited partners as a group:

• to remove or replace the general partner;

• to approve some amendments to our partnership agreement; or

• to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under Delaware law, to the same extent as the general partner. This liability would extend to persons who transact business with us and who reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we have found no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if after the distribution all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of our partnership, exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to our partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and which could not be ascertained from our partnership agreement.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, shall be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner shall distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

Please see “Material Provisions of Our Partnership Agreement—Board of Directors of General Partner; Nomination and Election; Meetings of Limited Partners” for a description of the rights of certain unaffiliated unitholders to nominate and elect members of the board of directors of our general partner at meetings.

Other than the removal of directors of our general partner, any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy shall constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum shall be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in our partnership, although additional limited partner interests having special voting rights could be issued. However, if at any time any

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person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates or a person or group who acquires the units with the prior approval of the board of directors, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, the person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as otherwise provided in the partnership agreement, subordinated units will vote together with common units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a common unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:

• a current list of the name and last known address of each partner;

• a copy of our tax returns;

• information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

• copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments and powers of attorney under which they have been executed;

• information regarding the status of our business and financial condition; and

• any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or which we are required by law or by agreements with third parties to keep confidential.

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CASH DISTRIBUTION POLICY

Distributions of Available Cash

General.    Within approximately 45 days after the end of each quarter, Penn Virginia Resource Partners will distribute all available cash to unitholders of record on the applicable record date.

Definition of Available Cash.    Available cash generally means, for each fiscal quarter:

• all cash on hand at the end of the quarter;

• less the amount of cash reserves that the general partner determines in its reasonable discretion is necessary or appropriate to:

— provide for the proper conduct of our business;

— comply with applicable law, any of our debt instruments or other agreements; or

— provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

• plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

Operating Surplus and Capital Surplus

General.    All cash distributed to unitholders will be characterized either as operating surplus or capital surplus. We distribute available cash from operating surplus differently than available cash from capital surplus.

Definition of Operating Surplus.    For any period, operating surplus generally means:

• our cash balance on the closing date of our initial public offering; plus

• $15.0 million (as described below); plus

• all of our cash receipts since the closing of our initial public offering, excluding cash from borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus

• working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for that quarter; less

• all of our operating expenses since the closing of our initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less

• the amount of cash reserves that the general partner deems necessary or advisable to provide funds for future operating expenditures.

Definition of Capital Surplus.    Capital surplus will generally be generated only by:

• borrowings other than working capital borrowings;

• sales of debt and equity securities; and

• sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

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Characterization of Cash Distributions.    We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus. As reflected above, operating surplus includes $15.0 million in addition to our cash balance on the closing date of our initial public offering, cash receipts from our operations and cash from working capital borrowings. This amount does not reflect actual cash on hand at closing that is available for distribution to our unitholders. Rather this amount permits us to make limited distributions of cash from non-operating sources, such as assets sales, issuances of securities and long-term borrowings, which would otherwise be considered distributions of capital surplus. Any distributions of capital surplus would trigger certain adjustment provisions in our partnership agreement as described below. See “— Distributions from Capital Surplus” and “— Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.”

Distributions of Available Cash from Operating Surplus

Penn Virginia Resource Partners will make distributions of available cash from operating surplus for any quarter in the following manner:

• First, 98% to all unitholders, pro rata, and 2% to the general partner until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution of $0.275 for that quarter; and

• Thereafter, in the manner described in “— Incentive Distribution Rights” below.

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. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, to an affiliate of the holder (other than an individual) or to another entity as part of the merger or consolidation of such holder with or into such entity or the transfer of all or substantially all of its assets to another entity without the prior approval of the unitholders; provided that the transferee agrees to be bound by the provisions of the partnership agreement of Penn Virginia Resource Partners. Prior to September 30, 2011, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after September 30, 2011, the incentive distribution rights will be freely transferable.

If for any quarter we have distributed available cash from operating surplus to the unitholders in an amount equal to the minimum quarterly distribution, then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

• First, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.275 per unit for that quarter (the “first target distribution”);

• Second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.325 per unit for that quarter (the “second target distribution”);

• Third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives a total of $0.375 per unit for that quarter (the “third target distribution”); and

• Thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

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Distributions from Capital Surplus

Penn Virginia Resource Partners will make distributions of available cash from capital surplus, if any, in the following manner:

• First, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in the initial public offering, an amount of available cash from capital surplus equal to the initial public offering price;

• Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

The partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from the initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the unrecovered initial unit price. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero and we will make all future distributions from operating surplus, with 50% being paid to the holders of units and 50% to the general partner.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjustments made upon a distribution of available cash from capital surplus, we will adjust the following proportionately upward or downward, as appropriate, if any combination or subdivision of units should occur:

• the minimum quarterly distribution;

• the target distribution levels; and

• the unrecovered initial unit price.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates. For example, if we became subject to a maximum marginal federal, and effective state and local income tax rate of 38%, then the minimum quarterly distribution and the target distributions levels would each be reduced to 62% of their previous levels.

Distributions of Cash Upon Liquidation

General.    If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance

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with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

Manner of Adjustment.    If we liquidate, we would allocate any loss to the general partner and each unitholder as follows:

• First, 98% to the holders of common units who have positive balances in their capital accounts in proportion to those positive balances and 2% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and

• Thereafter, 100% to the general partner.

Adjustments to Capital Accounts Upon the Issuance of Additional Units.    We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive interim adjustments to the capital accounts, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or distributions of property or upon liquidation in a manner which results, to the extent possible, in the capital account balance of the general partner equaling the amount which would have been in its capital account if no earlier positive adjustments to the capital accounts had been made.

MATERIAL PROVISIONS OF OUR PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The following provisions of our partnership agreement are summarized elsewhere in this prospectus:

• distributions of our available cash are described under “Cash Distribution Policy;”

• allocations of taxable income and other tax matters are described under “Material Income Tax Consequences;” and

• rights of holders of common units are described under “Description of The Common Units.”

Purpose

Our purpose is to engage in any business activities that may be engaged in by our subsidiaries or that are approved by our general partner.

Our general partner is authorized in general to perform all acts deemed necessary to carry out our purposes and to conduct our business.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder and executes and delivers a transfer application, grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to make certain amendments, and consents and waivers under, our partnership agreement.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for the consideration and on the terms and conditions established by our general partner in its sole discretion without the approval of any limited partners.

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It is possible that we will fund acquisitions through the issuance of additional limited partner units or other equity securities. Holders of any additional limited partner units issued by us will be entitled to share equally with the then-existing holders of limited partner units, the general partner interest and other securities in our distributions of available cash. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of limited partner units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, in the sole discretion of our general partner, have special voting rights to which the limited partner units are not entitled.

Board of Directors of General Partner; Nomination and Election; Meetings of Limited Partners

Pursuant to our partnership agreement, our limited partners other than our general partner and those limited partners holding an interest in our general partner and their respective affiliates (the “Unaffiliated Limited Partners”) have the right to vote in the election of three independent directors (the “Class A Directors”) to the board of directors of our general partner. Penn Virginia GP Holdings, L.P. has the right to appoint the three directors other than the Class A Directors (the “Class B Directors”) to the board of directors of our general partner.

Our partnership agreement provides that an annual meeting of the limited partners for the election of the Class A Directors to the board of directors of our general partner will be held in June of each year beginning in 2011 or at such other date and time as may be fixed from time to time by our general partner. Notice of the annual meeting will be given not less than 10 days nor more than 60 days prior to the date of such meeting.

The Unaffiliated Limited Partners will vote together as a single class for the election of Class A Directors to the board of directors of our general partner. The Unaffiliated Limited Partners entitled to vote will elect by a plurality of the votes cast at such meeting persons to serve as Class A Directors on the board of directors of our general partner who are nominated in accordance with the provisions of our partnership agreement. The exercise by an Unaffiliated Limited Partner of the right to elect the Class A Directors and any other rights afforded to such Unaffiliated Limited Partner under our partnership agreement will be in such Unaffiliated Limited Partner’s capacity as a limited partner of us and is not intended to cause an Unaffiliated Limited Partner to be deemed to be taking part in the management and control of our business and affairs.

With respect to the election of Class A Directors to the board of directors of our general partner, our general partner and those limited partners holding an interest in our general partner or their respective affiliates will not be entitled to vote units that are otherwise entitled to vote at any meeting of the limited partners. If our general partner has provided at least 30 days advance notice of any meeting at which Class A Directors are to be elected, then the limited partners holding outstanding units (other than our general partner and those limited partners holding an interest in our general partner or any of their respective affiliates) that attend such meeting shall constitute a quorum, and if our general partner has provided less than 30 days advance notice of any such meeting, then limited partners holding a majority of the outstanding units (other than our general partner and those limited partners holding an interest in our general partner or their respective affiliates) shall constitute a quorum.

The number of directors constituting the board of directors of our general partner is six. The number of Class A Directors on the board of directors of our general partner is three and may be changed to such other number as shall be set forth in the limited liability company agreement of our general partner. Until such time as a Triggering Resolution (as defined below) has been adopted, each Class A Director shall be elected to serve a term of one year to expire at the next annual meeting.

With respect to any matter requiring approval of the board of directors of our general partner (but not any matter requiring approval of only a specific class of directors), in the event of a tie vote, the board of directors of

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our general partner has delegated to Penn Virginia Corporation the authority to break the tie vote (which authority Penn Virginia Corporation may, in its sole discretion, delegate to any direct or indirect wholly owned subsidiary of Penn Virginia Corporation other than PVG GP, LLC); provided, however, that Penn Virginia Corporation shall not have such tie breaking authority at any time after either a majority of the Class A Directors or a majority of the Class B Directors have provided 10 days prior written notice of their election to terminate Penn Virginia Corporation’s tie breaking authority.

Each Class A Director will serve for a term ending as provided in our partnership agreement. By resolution (a “Triggering Resolution”) of the board of directors of our general partner (including a majority of the Class A Directors), and without the consent of any other person, the Class A Directors may be divided into three groups, Group I, Group II, and Group III. The Class A Director designated in the Triggering Resolution to Group I shall serve for an initial term that expires at the annual meeting of limited partners held immediately following the Triggering Resolution, the Class A Director designated in the Triggering Resolution to Group II shall serve for an initial term that expires at the second annual meeting of limited partners held following the Triggering Resolution, and the Class A Director designated in the Triggering Resolution to Group III shall serve for an initial term that expires at the third annual meeting of limited partners held following the Triggering Resolution. At each succeeding annual meeting beginning with the first annual meeting after a Triggering Resolution, successors to the group of directors whose term expires at that annual meeting will be elected for a three-year term.

Any vacancy in a Class A Director on the board of directors of our general partner (including, without limitation, any vacancy caused by an increase in the number of Class A Directors on the board of directors of our general partner) may only be filled by a person nominated for election by a majority of the remaining Class A Directors (or if there are no Class A Directors, a majority of the Class B Directors) and consented to (such consent not to be unreasonably withheld or delayed) by a majority of the remaining directors, with such person being thereafter deemed elected. Any Class A Director elected to fill a vacancy not resulting from an increase in the number of Class A Directors shall have the same remaining term as that of his predecessor.

A Class A Director may be removed only at a meeting of the limited partners upon the affirmative vote of limited partners (other than our general partner and those limited partners holding an interest in our general partner or any of their respective affiliates) holding a majority of the outstanding units (other than our general partner and those limited partners holding an interest in our general partner or any of their respective affiliates); provided, however, that a Class A Director may only be removed if, at the same meeting, limited partners holding a majority of the outstanding units nominate a replacement Class A Director (and any such nomination shall not be subject to the nomination procedures otherwise set forth in our partnership agreement), and limited partners (other than our general partner and those limited partners holding an interest in our general partner or any of their respective affiliates) holding a majority of the outstanding units (other than our general partner and those limited partners holding an interest in our general partner or any of their respective affiliates) also vote to elect a replacement Class A Director, and, provided, further, that following a Triggering Resolution, a Class A Director may only be removed for cause.

Nominations of persons for election of Class A Directors to the board of directors of our general partner may be made at an annual meeting of the limited partners only pursuant to our general partner’s notice of meeting (or any supplement thereto) (a) by or at the direction of a majority of the Class A Directors (or, if there are no Class A Directors at that time, by or at the direction of a majority of the Class B Directors) or (b) by a limited partner, or a group of limited partners, that holds or beneficially owns, and has continuously held or beneficially owned without interruption for the prior 18 months, 5% of the outstanding units (in either case, a “Limited Partner Group”) if each member of the Limited Partner Group was a record holder at the time the notice provided for in our partnership agreement is delivered to our general partner, and if the Limited Partner Group complies with the notice procedures set forth in our partnership agreement.

For any nominations brought before an annual meeting by a Limited Partner Group, the Limited Partner Group must give timely notice thereof in writing to our general partner. The notice must contain certain

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information as described in our partnership agreement. To be timely, a Limited Partner Group’s notice must be delivered to our general partner not later than the close of business on the 90th day, nor earlier than the close of business on the 120th day, prior to the first anniversary of the preceding year’s annual meeting (provided, however, that in the event that the date of the annual meeting is more than 30 days before or more than 70 days after such anniversary date, notice by the Limited Partner Group must be so delivered not earlier than the close of business on the 120th day prior to such annual meeting and not later than the close of business on the later of the 90th day prior to such annual meeting or the 10th day following the day on which public announcement of the date of such meeting is first made by us or our general partner). For purposes of the 2011 annual meeting, the first anniversary of the preceding year’s annual meeting will be deemed to be June 30, 2011. The public announcement of an adjournment or postponement of an annual meeting will not commence a new time period (or extend any time period) for the giving of a Limited Partner Group’s notice as described above.

In the event that the number of Class A Directors to be elected to the board of directors of our general partner is increased effective after the time period for which nominations are due under our partnership agreement and there is no public announcement by us or our general partner naming the nominees for the additional directorships at least 100 days prior to the first anniversary of the preceding year’s annual meeting, a Limited Partner Group’s notice will also be considered timely, but only with respect to nominees for the additional directorships, if it is delivered to our general partner not later than the close of business on the 10th day following the day on which such public announcement is first made by us or our general partner.

Nominations of persons for election as a Class A Director to the board of directors of our general partner also may be made at a special meeting of limited partners at which Class A Directors are to be elected in accordance with the provisions of our partnership agreement.

Only such persons who are nominated in accordance with the procedures set forth in our partnership agreement will be eligible to be elected at an annual or special meeting of limited partners to serve as Class A Directors. Notwithstanding the foregoing, unless otherwise required by law, if each member of the Limited Partner Group (or a qualified representative of each member of the Limited Partner Group) does not appear at the annual or special meeting of limited partners to present a nomination, such nomination shall be disregarded notwithstanding that proxies in respect of such vote may have been received by us or our general partner.

In addition to the provisions described above and in our partnership agreement, a limited partner must also comply with all applicable requirements of the Exchange Act; provided, however, that any references in our partnership agreement to the Exchange Act or the rules promulgated thereunder are not intended to and do not limit any requirements applicable to nominations pursuant to our partnership agreement, and compliance with our partnership agreement is the exclusive means for a limited partner to make nominations.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. To adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a majority of the common units. These voting provisions are referred to as a “unit majority.”

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Prohibited Amendments

Without the consent of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates), our partnership agreement may not be amended to:

• enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected;

• enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld in its sole discretion;

• change the term of the partnership;

• provide that the partnership is not dissolved upon an election to dissolve the partnership by our general partner that is approved by a unit majority; or

• give any person the right to dissolve the partnership other than our general partner’s right to dissolve the partnership with the approval of a unit majority.

No Unitholder Approval

Our general partner may generally make amendments to the partnership agreement without the approval of any limited partner or assignee to reflect:

• a change in our name, the location of our principal place of business, the registered agent or registered office;

• the admission, substitution, withdrawal or removal of partners in accordance with the partnership agreement;

• a change that, in the sole discretion of our general partner, is necessary or advisable to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor PVR Finco LLC nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

• an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or our directors, officers, agents or trustees, from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulations currently applied or proposed;

• an amendment that in the discretion of our general partner is necessary or advisable for the authorization of additional limited or general partner interests;

• any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

• an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of the partnership agreement;

• any amendment that, in the discretion of our general partner, is necessary or advisable for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

• a change in our fiscal year or taxable year and related changes; and

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• any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to the partnership agreement without the approval of any limited partner or assignee if those amendments, in the discretion of our general partner:

• do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;

• are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

• are necessary or advisable to facilitate the trading of our limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which our limited partner interests are or will be listed for trading, compliance with any of which our general partner deems to be in the best interests of us and our limited partners;

• are necessary or advisable for any action taken by our general partner relating to splits or combinations of units under the provisions of the partnership agreement; or

• are required to effect the intent of the provisions of the partnership agreement or are otherwise contemplated by the partnership agreement.

Opinion of Counsel and Unitholder Approval

Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in us being treated as an entity for federal income tax purposes if one of the amendments described above under “— No Unitholder Approval” should occur. No other amendments to the partnership agreement will become effective without the approval of holders of at least 90% of the units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any limited partner in the partnership or cause us or our subsidiaries to be taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously taxed as such).

Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

The partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of its assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of our assets or the assets of its subsidiaries;provided that our general partner may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon the encumbrances above without that approval. Furthermore, provided that conditions specified in the partnership agreement are satisfied, our general partner may merge the partnership or any of its subsidiaries into, or convey some or all of their assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. Unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a merger or consolidation, a sale of substantially all of our assets or any other transaction or event.

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Without the approval of a unit majority, our general partner is prohibited from consenting on our behalf to any amendment to the limited liability company agreement of PVR Finco LLC, or taking any action on our behalf permitted to be taken by a member of PVR Finco LLC, in each case that would adversely affect the limited partners (or any particular class of limited partners) in any material respect.

Termination and Dissolution

We will continue as a limited partnership until terminated under the partnership agreement. We will dissolve upon:

• the election of our general partner to dissolve the partnership, if approved by the holders of a unit majority;

• the sale, exchange or other disposition of all or substantially all of the assets and properties of the partnership and its subsidiaries;

• the entry of a decree of judicial dissolution of the partnership; or

• the withdrawal or removal of our general partner or any other event that results in its ceasing to be general partner other than by reason of a transfer of its general partner interest in accordance with the partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a majority of the outstanding common units may also elect, within specific time limitations, to reconstitute the partnership and continue its business on the same terms and conditions described in the partnership agreement by forming a new limited partnership on terms identical to those in the existing partnership agreement and having as general partner an entity approved by a unit majority, subject to receipt by us of an opinion of counsel to the effect that:

• the action would not result in the loss of limited liability of any limited partner; and

• neither the partnership, the reconstituted limited partnership, nor its operating company would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon dissolution of the partnership, unless it is reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that the liquidator deems necessary or desirable in its judgment, liquidate our assets and apply the proceeds of the liquidation as provided in “— Cash Distribution Policy — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of the General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as general partner of the partnership prior to September 30, 2011 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after September 30, 2011, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of the partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interests without the approval of the unitholders. See “— Transfer of General Partner Interests.”

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Upon the withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest, the holders of a majority of the outstanding common units may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 180 days after that withdrawal, the holders of a majority of the outstanding common units agree in writing to continue our business and to appoint a successor general partner. See “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 ²/3% of the outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units.

The partnership agreement also provides that if Penn Virginia Resource GP, LLC is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:

• any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

• our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates the partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. If the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the above-described option is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner for our benefit.

Transfer of General Partner Interests

Except for a transfer by our general partner of all, but not less than all, of its general partner interest to:

• an affiliate of our general partner (other than an individual); or

• another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

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our general partner may not transfer all or any part of its general partner interest to another person prior to September 30, 2011 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume the rights and duties of our general partner, agree to be bound by the provisions of the partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters. Our general partner and its affiliates may at any time, however, transfer units to one or more persons, other than our partnership, without unitholder approval.

Transfer of Incentive Distribution Rights

Our general partner or a later holder of the incentive distribution rights may transfer the incentive distribution rights to an affiliate of the holder (other than an individual) or to another entity as part of the merger or consolidation of such holder with or into such entity or the transfer of all or substantially all of its assets to another entity without the prior approval of the unitholders; provided that the transferee agrees to be bound by the provisions of the partnership agreement. Prior to September 30, 2011, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by the general partner or its affiliates. On or after September 30, 2011, the incentive distribution rights will be freely transferable.

Limited Call Right

If at any time persons other than our general partner and its affiliates do not own more than 20% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:

• the highest cash price paid by either our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

• the current market price as of the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market.

Indemnification

Under the partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

• our general partner;

• any departing general partner;

• any person who is or was an affiliate of a general partner or any departing general partner;

• any person who is or was a member, partner, officer, director, employee, agent or trustee of a general partner or any departing general partner or any affiliate of a general partner or any departing general partner; or

• any person who is or was serving at the request of a general partner or any departing general partner or any affiliate of a general partner or any departing general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person.

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Any indemnification under these provisions will only be out of our assets. Our general partner shall not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate indemnification. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under the partnership agreement.

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MATERIAL INCOME TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P. counsel to the general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Penn Virginia Resource Partners, L.P. and PVR Finco LLC.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership —Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

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Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of natural resources, including coal, timber, crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 3% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status as a partnership for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and our operating company will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied include:

(a) Neither we nor the operating company has elected or will elect to be treated as a corporation; and

(b) For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

We believe that these representations have been true in the past and expect that these representations will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were treated as an association taxable as a corporation in any taxable year for which the statute of limitations remains open, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction for such taxable year would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units (as determined on a unit-by-unit basis), or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

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The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Penn Virginia Resource Partners, L.P. will be treated as partners of Penn Virginia Resource Partners, L.P. for federal income tax purposes. Also:

(a) assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and

(b) unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units

will be treated as partners of Penn Virginia Resource Partners, L.P. for federal income tax purposes. As there is no direct or indirect controlling authority addressing the federal tax treatment of assignees of common units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, Vinson & Elkins L.L.P.’s opinion does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in Penn Virginia Resource Partners, L.P.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income.    We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions.    Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

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A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation and depletion recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Basis of Common Units.    A unitholder’s tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying producing properties, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units —Recognition of Gain or Loss.”

Limitations on Deductibility of Losses.    The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such unitholders’ tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership.

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Consequently, any passive losses we generate will be available to offset only our passive income generated in the future and will not be available to offset income from other passive activities or investments (including our investments or a common unitholder’s investments in other publicly traded partnerships) or a unitholder’s salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions.    The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

• interest on indebtedness properly allocable to property held for investment;

• our interest expense attributed to portfolio income; and

• the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders for purposes of the investment interest deduction limitation. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections.    If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain the uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction.    In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of their contribution or certain other

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transactions, referred to in this discussion as the “Contributed Property.” Specifically, allocations of income, gain, loss and deduction, referred to as “Section 704(c) Allocations,” will be made to a unitholder to account for any difference between the tax basis and fair market value of any property contributed to us that exists at the time of such contribution. In addition, in the event we issue additional common units or engage in certain other transactions in the future “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to the general partner and our other unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

• his relative contributions to us;

• the interests of all the partners in profits and losses;

• the interest of all the partners in cash flow; and

• the rights of all the partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales.    A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

• any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

• any cash distributions received by the unitholder as to those units would be fully taxable; and

• all of these distributions would appear to be ordinary income.

Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units —Recognition of Gain or Loss.”

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Alternative Minimum Tax.    Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates.    Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months at the time of disposition) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2011, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8% Medicare tax on certain investment income earned by individuals for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. The tax will be imposed on the lesser of (i) the unitholder’s net income from all investments, and (ii) the amount by which the unitholder’s adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly) or $200,000 (if the unitholder is unmarried).

Section 754 Election.    We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election applies to a purchaser of common units from another unitholder, but it does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Where the remedial allocation method is adopted (which we have generally adopted as to our properties), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property subject to depreciation under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “— Uniformity of Units.”

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization

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position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units —Recognition of Gain or Loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally non-amortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year.    We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization.    The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our partners holding interests in us immediately prior to such offering. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

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To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Coal Income.    Section 631 of the Internal Revenue Code provides special rules by which gains or losses on the sale of coal may be treated, in whole or in part, as gains or losses from the sale of property used in a trade or business under Section 1231 of the Internal Revenue Code. Specifically, Section 631(c) provides that if the owner of coal held for more than one year disposes of that coal under a contract by virtue of which the owner retains an economic interest in the coal, the gain or loss realized will be treated under Section 1231 of the Internal Revenue Code as gain or loss from property used in a trade or business. Section 1231 gains and losses may be treated as capital gains and losses. Please read “— Sales of Coal Reserves or Timberland.” In computing such gain or loss, the amount realized is reduced by the adjusted depletion basis in the coal, determined as described in “— Coal Depletion.” For purposes of Section 631(c), the coal generally is deemed to be disposed of on the day on which the coal is mined. Further, Treasury Regulations promulgated under Section 631 provide that advance royalty payments may also be treated as proceeds from sales of coal to which Section 631 applies and, therefore, such payment may be treated as capital gain under Section 1231. However, if the right to mine the related coal expires or terminates under the contract that provides for the payment of advance royalty payments or such right is abandoned before the coal has been mined, we may, pursuant to the Treasury regulations, file an amended return that reflects the payments attributable to unmined coal as ordinary income and not as received from the sale of coal under Section 631.

Our royalties from coal leases generally will be treated as proceeds from sales of coal to which Section 631 applies. Accordingly, the difference between the royalties paid to us by the lessees and the adjusted depletion basis in the extracted coal generally will be treated as gain from the sale of property used in a trade or business, which may be treated as capital gain under Section 1231. Please read “— Sales of Coal Reserves or Timberland.” Our royalties that do not qualify under Section 631(c) generally will be taxable as ordinary income in the year of sale.

Coal Depletion.    In general, we are entitled to depletion deductions with respect to coal mined from the underlying mineral property. Subject to the limitations on the deductibility of losses discussed above, we generally are entitled to the greater of cost depletion limited to the basis of the property or percentage depletion. The percentage depletion rate for coal is 10%. If Section 631(c) applies to the disposition of the coal, however, we are not eligible for percentage depletion. Please read “— Coal Income.”

Depletion deductions we claim generally will reduce the tax basis of the underlying mineral property. Depletion deductions can, however, exceed the total tax basis of the mineral property. The excess of our percentage depletion deductions over the adjusted tax basis of the property at the end of the taxable year is subject to tax preference treatment in computing the alternative minimum tax. Please read “— Tax Consequences

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of Unit Ownership — Alternative Minimum Tax.” In addition, a corporate unitholder’s allocable share of the amount allowable as a percentage depletion deduction for any property will be reduced by 20% of the excess, if any, of that partner’s allocable share of the amount of the percentage depletion deductions for the taxable year over the adjusted tax basis of the mineral property as of the close of the taxable year.

Oil and Natural Gas Depletion.    Subject to the limitations on deductibility of losses discussed above (please read “— Tax Consequences of Unit Ownership-Limitations on Deductibility of Losses”), unitholders may be entitled to depletion deductions with respect to our oil and natural gas royalty interests. The deduction is equal to the greater of cost depletion limited to the basis of the property or (if otherwise allowable) percentage depletion.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% of the unitholder’s gross income from the oil and gas property for the taxable year. A unitholder may deduct percentage depletion only to the extent the unitholder’s average daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. A limitation equal to the lower of 65% of taxable income or 100% of taxable income from the property further limits the deduction for the taxable year.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our oil and natural gas interests or the disposition by the unitholder of some or all of his units may be taxed as ordinary income to the extent of recapture of oil and gas depletion.

Although the Internal Revenue Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes. Each unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.

Timber Income.    Section 631 of the Internal Revenue Code provides special rules by which gains or losses on the sale of timber may be treated, in whole or in part, as gains or losses from the sale of property used in a trade or business under Section 1231 of the Internal Revenue Code. Specifically, Section 631(b) provides that if the owner of timber (including a holder of a contract right to cut timber) held for more than one year disposes of that timber under any contract by virtue of which the owner retains an economic interest in the timber, the gain or loss realized will be treated under Section 1231 of the Internal Revenue Code as gain or loss from property used in a trade or business. Section 1231 gains and losses may be treated as capital gains and losses. Please read “— Sales of Coal Reserves or Timberland.” In computing such gain or loss, the amount realized is reduced by the adjusted basis in the timber, determined as described in “— Timber Depletion.” For purposes of Section 631(b), the timber generally is deemed to be disposed of on the day on which the timber is cut (which is generally deemed to be the date when, in the ordinary course of business, the quantity of the timber cut is first definitely determined).

Proceeds we receive from standing timber sales generally will be treated as sales of timber to which Section 631 applies. Accordingly, the difference between those proceeds and the adjusted basis in the timber sold generally will be treated as gain from the sale of property used in a trade or business, which may be treated as capital gain under Section 1231. Please read “— Sales of Coal Reserves and Timberland.” Gains from sale of timber by the Partnership that do not qualify under Section 631 generally will be taxable as ordinary income in the year of sale.

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Timber Depletion.    Timber is subject to cost depletion and is not subject to accelerated cost recovery, depreciation or percentage depletion. Timber depletion is determined with respect to each separate timber account (containing timber located in a timber “block”) and is equal to the product obtained by multiplying the units of timber cut by a fraction, the numerator of which is the aggregate adjusted basis of all timber included in such account and the denominator of which is the total number of timber units in such timber account. The depletion allowance so calculated for the timber cut in a particular period represents the adjusted tax basis of such cut timber for purposes of determining gain or loss on its disposition. The tax basis of the remaining timber in each timber account is reduced by the depletion allowance for cut timber from such account.

Sales of Coal Reserves or Timberland.    If any coal reserves or timberland are sold or otherwise disposed of in a taxable transaction, we will recognize gain or loss measured by the difference between the amount realized (including the amount of any indebtedness assumed by the purchaser upon such disposition or to which such property is subject) and the adjusted tax basis of the property sold. Generally, the character of any gain or loss recognized upon that disposition will depend upon whether our coal reserves or the particular tract of timberland sold are held by us:

• for sale to customers in the ordinary course of business (i.e., we are a “dealer” with respect to that property),

• for use in a trade or business within the meaning of Section 1231 of the Internal Revenue Code or

• as a capital asset within the meaning of Section 1221 of the Internal Revenue Code.

In determining dealer status with respect to coal reserves, timberland and other types of real estate, the courts have identified a number of factors for distinguishing between a particular property held for sale in the ordinary course of business and one held for investment. Any determination must be based on all the facts and circumstances surrounding the particular property and sale in question.

We intend to hold our coal reserves and timberland for the purposes of generating cash flow from coal royalties and periodic harvesting and sale of timber and achieving long-term capital appreciation. Although our general partner may consider strategic sales of coal reserves and timberland consistent with achieving long-term capital appreciation, our general partner does not anticipate frequent sales, nor significant marketing, improvement or subdivision activity in connection with any strategic sales. Thus, the general partner does not believe that we will be viewed as a dealer. In light of the factual nature of this question, however, there is no assurance that our purposes for holding our properties will not change and that our future activities will not cause us to be a “dealer” in coal reserves or timberland.

If we are not a dealer with respect to our coal reserves or our timberland and we have held the disposed property for more than a one year period primarily for use in our trade or business, the character of any gain or loss realized from a disposition of the property will be determined under Section 1231 of the Internal Revenue Code. If we have not held the property for more than one year at the time of the sale, gain or loss from the sale will be taxable as ordinary income.

A unitholder’s distributive share of any Section 1231 gain or loss generated by us will be aggregated with any other gains and losses realized by that unitholder from the disposition of property used in the trade or business, as defined in Section 1231(b) of the Internal Revenue Code, and from the involuntary conversion of such properties and of capital assets held in connection with a trade or business or a transaction entered into for profit for the requisite holding period. If a net gain results, all such gains and losses will be long-term capital gains and losses; if a net loss results, all such gains and losses will be ordinary income and losses. Net Section 1231 gains will be treated as ordinary income to the extent of prior net Section 1231 losses of the taxpayer or predecessor taxpayer for the five most recent prior taxable years to the extent such losses have not previously been offset against Section 1231 gains. Losses are deemed recaptured in the chronological order in which they arose.

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If we are not a dealer with respect to our coal reserves or a particular tract of timberland, and that property is not used in a trade or business, the property will be a “capital asset” within the meaning of Section 1221 of the Internal Revenue Code. Gain or loss recognized from the disposition of that property will be taxable as capital gain or loss, and the character of such capital gain or loss as long-term or short-term will be based upon our holding period in such property at the time of its sale. The requisite holding period for long-term capital gain is more than one year.

Upon a disposition of coal reserves or timberland, a portion of the gain, if any, equal to the lesser of (i) the depletion deductions that reduced the tax basis of the disposed mineral property plus deductible development and mining exploration expenses, or (ii) the amount of gain recognized on the disposition, will be treated as ordinary income to us.

Valuation and Tax Basis of Our Properties.    The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Recent Legislative Developments

The White House recently released President Obama’s budget proposal for the Fiscal Year 2011 (the “Budget Proposal”). Among the changes recommended in the Budget Proposal is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would (i) eliminate current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal and oil and gas properties, (iii) repeal capital gains treatment of coal and lignite royalties, and (iv) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels, or primary products thereof. The passage of any legislation as a result of the Budget Proposal or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available to us, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

Disposition of Common Units

Recognition of Gain or Loss.    Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities attributable to the common units sold. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax

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rate of 15% through December 31, 2010 and 20% thereafter (absent new legislation extending or adjusting the current rate). However, a portion, which will likely be substantial, of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation and depletion recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation and depletion recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 ($1,500 in the case of a married individual filing a separate return) of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

• a short sale;

• an offsetting notional principal contract; or

• a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees.    In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of

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business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements.    A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination.    We will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders receiving two Schedules K-1) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

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Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable methods and useful lives as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units —Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Generally, most of our income less certain allowable deductions allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, cash distributions made quarterly to foreign unitholders will be withheld upon at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS

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and submit that number to its broker or our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures.    We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies

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against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting.    Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b) whether the beneficial owner is:

1. a person that is not a United States person;

2. a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

3. a tax-exempt entity;

(c) the amount and description of units held, acquired or transferred for the beneficial owner; and

(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties.    An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1) for which there is, or was, “substantial authority”; or

(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the

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pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (i) the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or tax basis, (ii) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price or (iii) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). The penalty is increased to 40% in the event of a gross valuation misstatement.

Reportable Transactions.    If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” “or “transaction of interest” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of 6 successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:

• accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties”;

• for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

• in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We own property or do business in several states, most of which impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions

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may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

Tax Consequences of Ownership of Debt Securities

A description of the material federal income tax consequences of the acquisition, ownership and disposition of debt securities will be set forth on the prospectus supplement relating to the offering of debt securities.

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PLAN OF DISTRIBUTION

Under this prospectus, we intend to offer our securities to the public:

• through one or more broker-dealers;

• through underwriters; or

• directly to investors.

We will fix a price or prices of our securities at:

• market prices prevailing at the time of any sale under this registration statement;

• prices related to market prices; or

• negotiated prices.

We may change the price of the securities offered from time to time.

We will pay or allow distributors’ or sellers’ commissions that will not exceed those customary in the types of transactions involved. Broker-dealers may act as agent or may purchase securities as principal and thereafter resell the securities from time to time:

• in or through one or more transactions (which may involve crosses and block transactions) or distributions;

• on the New York Stock Exchange;

• in the over-the-counter market; or

• in private transactions.

Broker-dealers or underwriters may receive compensation in the form of underwriting discounts or commissions and may receive commissions from purchasers of the securities for whom they may act as agents. If any broker-dealer purchases the securities as principal, it may effect resales of the securities from time to time to or through other broker-dealers, and other broker-dealers may receive compensation in the form of concessions or commissions from the purchasers of securities for whom they may act as agents.

To the extent required, the names of the specific managing underwriter or underwriters, if any, as well as other important information, will be set forth in prospectus supplements. In that event, the discounts and commissions we will allow or pay to the underwriters, if any, and the discounts and commissions the underwriters may allow or pay to dealers or agents, if any, will be set forth in, or may be calculated from, the prospectus supplements. Any underwriters, brokers, dealers and agents who participate in any sale of the securities may also engage in transactions with, or perform services for, us or our affiliates in the ordinary course of their businesses. We may indemnify underwriters, brokers, dealers and agents against specific liabilities, including liabilities under the Securities Act.

Offers to purchase securities may be solicited directly by us and the sale thereof may be made by us directly to institutional investors or others, who may be deemed to be underwriters within the meaning of the Securities Act with respect to any resale thereof. The terms of any such sales will be described in the prospectus supplement relating thereto.

We may offer our units into an existing trading market on the terms described in the prospectus supplement relating thereto. Underwriters and dealers who may participate in any at-the-market offerings will be described in the prospectus supplement relating thereto.

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In compliance with FINRA guidelines, the maximum commission or discount to be received by any FINRA member or independent broker dealer may not exceed 8% of the aggregate amount of the securities offered pursuant to this prospectus and any applicable prospectus supplement.

To the extent required, this prospectus may be amended or supplemented from time to time to describe a specific plan of distribution. The place and time of delivery for the securities in respect of which this prospectus is delivered will be set forth in the accompanying prospectus supplement.

In connection with offerings under this shelf registration and in compliance with applicable law, underwriters, brokers or dealers may engage in transactions which stabilize or maintain the market price of the securities at levels above those which might otherwise prevail in the open market. Specifically, underwriters, brokers or dealers may over-allot in connection with offerings, creating a short position in the securities for their own accounts. For the purpose of covering a syndicate short position or stabilizing the price of the securities, the underwriters, brokers or dealers may place bids for the securities or effect purchases of the securities in the open market. Finally, the underwriters may impose a penalty whereby selling concessions allowed to syndicate members or other brokers or dealers for distribution the securities in offerings may be reclaimed by the syndicate if the syndicate repurchases previously distributed securities in transactions to cover short positions, in stabilization transactions or otherwise. These activities may stabilize, maintain or otherwise affect the market price of the securities, which may be higher than the price that might otherwise prevail in the open market, and, if commenced, may be discontinued at any time.

LEGAL MATTERS

The validity of the securities offered in this prospectus will be passed upon for us by Vinson & Elkins L.L.P., New York, New York. Vinson & Elkins L.L.P. will also render an opinion on the material United States federal income tax considerations regarding the securities. If certain legal matters in connection with an offering of the securities made by this prospectus and a related prospectus supplement are passed on by counsel for the underwriters of such offering, that counsel will be named in the applicable prospectus supplement related to that offering.

EXPERTS

The consolidated financial statements of Penn Virginia Resource Partners, L.P. as of December 31, 2009 and 2008 and for each of the years in the three-year period ended December 31, 2009, incorporated by reference herein, and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2009, incorporated by reference herein, have been incorporated by reference herein in reliance upon the reports of KPMG LLP, an independent registered public accounting firm, incorporated by reference herein and upon the authority of said firm as experts in accounting and auditing.

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Penn Virginia Resource Partners, L.P.

Penn Virginia Resource Finance Corporation

$300,000,000

8  ¹/4% Senior Notes due 2018

PROSPECTUS SUPPLEMENT

April 22, 2010

Joint Book-Running Managers

Wells Fargo Securities

BofA Merrill Lynch

J.P. Morgan

RBC Capital Markets

Senior Co-Managers

BB&T Capital Markets

BNP PARIBAS

Mitsubishi UFJ Securities

PNC Capital Markets LLC

Co-Managers

Barclays Capital

BMO Capital Markets

Capital One Southcoast

Comerica Securities

Credit Suisse

SOCIETE GENERALE

TD Securities

UBS Investment Bank

US Bancorp