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Filed Pursuant to Rule 424(b)(3)

File Numbers:

333-106195

333-106239

We will amend and complete the information in this preliminary prospectus supplement. This preliminary prospectus supplement and the accompanying prospectuses are part of effective registration statements filed with the Securities and Exchange Commission. This preliminary prospectus supplement and the accompanying prospectuses are not offers to sell nor solicitations of offers to buy these securities in any jurisdiction where such offer or sale is not permitted.

Subject to Completion, dated March 9, 2005

PROSPECTUS SUPPLEMENT

(To Prospectuses dated June 25, 2003 and August 1, 2003)

3,350,000 Common Units

Representing Limited Partner Interests

We are offering to sell 2,511,842 common units representing limited partner interests with this prospectus supplement and the accompanying prospectus dated June 25, 2003. In addition, Peabody Natural Resources Company, an affiliate of Peabody Energy Corporation, is offering to sell 838,158 common units with this prospectus supplement and the accompanying prospectus dated August 1, 2003.

Our common units are listed on the New York Stock Exchange under the symbol “PVR.” On March 7, 2005, the last reported sales price of our common units on the New York Stock Exchange was $56.40 per common unit.

Investing in the common units involves risk. See “ Risk Factors” beginning on page S-12 of this prospectus supplement and on page 2 of each accompanying prospectus.

We have granted the underwriters a 30-day option to purchase up to an additional 502,500 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 3,350,000 common units in this offering.

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

Lehman Brothers, on behalf of the underwriters, expects to deliver the common units on or about March     , 2005.

Joint Book-Running Managers

March     , 2005

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This document is in three parts. The first part is the prospectus supplement, which describes the terms of this common unit offering. The second and third parts are the accompanying prospectuses, which give more general information, some of which may not apply to this common unit offering. The prospectus dated June 25, 2003 relates to common units offered by us and the prospectus dated August 1, 2003 relates to common units to be offered by the selling unitholder. If the information about the offering varies between this prospectus supplement and the accompanying prospectuses, you should rely on the information in this prospectus supplement. The sections captioned “Where You Can Find More Information” and “Forward-Looking Statements and Associated Risks” in the accompanying prospectuses are superseded in their entirety by the similarly titled sections included in this prospectus supplement.

You should rely only on the information contained or incorporated by reference in this prospectus supplement or the accompanying prospectuses. We have not authorized anyone to provide you with additional or different information. If anyone provides you with additional, different or inconsistent information, you should not rely on it. We and the selling unitholder are offering to sell the common units, and seeking offers to buy the common units, only in jurisdictions where offers and sales are permitted. You should not assume that the information contained in this prospectus supplement or the accompanying prospectuses is accurate as of any date other than the dates shown in these documents or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since such dates.

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Prospectus Supplement

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Prospectus Dated June 25, 2003

Prospectus Dated August 1, 2003

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WHERE YOU CAN FIND MORE INFORMATION

Penn Virginia Resource Partners files annual, quarterly and other reports and other information with the Securities and Exchange Commission. You may read and copy any document we file at the SEC’s public reference room at 450 Fifth Street, N.W., 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.

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 supplement by referring you to those documents. The information incorporated by reference is an important part of this prospectus supplement. Information that Penn Virginia Resource Partners files later with the SEC will automatically update and may replace information in this prospectus supplement and information previously filed with the SEC.

The documents listed below and any future filings we make with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 (excluding any information furnished pursuant to Item 2.02 or Item 7.01 on any Current Report on Form 8-K) are incorporated by reference. They contain important information about us, our financial condition and results of operations.

We make available free of charge on or through our Internet website, www.pvresource.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on our website and not specifically incorporated by reference into this prospectus supplement is not a part of this prospectus supplement.

You may request a copy of any document incorporated by reference in this prospectus supplement, at no cost, by writing or calling us at the following address:

Investor Relations Department

Penn Virginia Resource Partners, L.P.

Three Radnor Corporate Center

100 Matsonford Road

Suite 230

Radnor, Pennsylvania 19087

(610) 687-8900

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SUMMARY

The summary highlights information contained elsewhere in this prospectus supplement and the accompanying prospectuses. It does not contain all of the information that you should consider before making an investment decision. You should read the entire prospectus supplement and each accompanying prospectus carefully, including the historical and pro forma financial statements and notes to those financial statements included or incorporated by reference in this prospectus supplement. Please read “Risk Factors” beginning on page S-12 of this prospectus supplement and beginning on page 2 of each accompanying prospectus for more information about important risks that you should consider before buying our common units. Unless the context otherwise indicates, the information presented in this prospectus supplement assumes that the underwriters do not exercise their option to purchase additional common units.

In this prospectus supplement, unless the context otherwise indicates, the terms “Penn Virginia Resource Partners” and “we,” “us,” “our” and similar terms mean Penn Virginia Resource Partners, together with Penn Virginia Operating Co. LLC and our other consolidated subsidiaries, and give effect to the Cantera acquisition. The term “Penn Virginia” means, depending on the context, Penn Virginia Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole, but excluding Penn Virginia Resource Partners and its operating subsidiaries. The term “Cantera” means the mid-continent division of Cantera Natural Gas, LLC. In connection with the Cantera acquisition, the assets of the mid-continent division of Cantera Natural Gas, LLC were contributed to Cantera Gas Resources, LLC, which is now owned and operated by our subsidiary, PVR Midstream LLC.

Unless otherwise indicated, pro forma financial results presented in this prospectus supplement give effect to the Cantera acquisition, the offering of common units by us and the use of proceeds therefrom. For a complete description of the adjustments we have made to arrive at the pro forma financial results we present in this prospectus supplement, please read the unaudited pro forma condensed combined financial statements included in this prospectus supplement.

Penn Virginia Resource Partners, L.P.

We are a Delaware limited partnership formed by Penn Virginia Corporation in 2001 primarily to engage in the business of managing coal properties in the United States. We conduct operations in two business segments: coal royalty, land leasing and coal services (for our lessees and other third party end-users) and natural gas midstream. In 2004, approximately 95% of our revenues were attributable to our coal royalty and land leasing operations and approximately 5% of our revenues were attributable to our coal services operations. We purchased our midstream segment on March 3, 2005 through the acquisition of Cantera Gas Resources, LLC. See “Recent Developments.”

In our coal royalty and land leasing operations, 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 do not operate any mines. As of December 31, 2004, our properties contained approximately 558 million tons of proven and probable coal reserves located on 241,000 acres in Virginia, West Virginia, New Mexico and eastern Kentucky. In 2004, our lessees produced 31.2 million tons of coal from our properties and paid us coal royalty revenues of $69.6 million, for an average gross coal royalty per ton of $2.23. As of December 31, 2004, we had leased an aggregate of approximately 89% of our reserves under 55 leases to 29 different operators who mine coal at 65 mines. Approximately 79% of our 2004 coal royalty revenues and 72% of our 2003 coal royalty revenues were derived from coal mined on our properties and sold by our lessees multiplied by a royalty rate per ton resulting from the higher of a percentage of the gross sales price or a fixed price per ton of coal, with pre-established minimum monthly or annual rental payments. The balance of our 2004 and 2003 coal royalty revenues was derived from coal mined on two of our properties under leases containing fixed royalty rates per

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ton of coal mined and sold. The royalty rates under those leases escalate annually, with pre-established minimum monthly payments. Included in our coal royalty and land leasing operations are revenues earned from the sale of standing timber on our properties. In our coal services operations, we generate revenues from providing fee-based coal preparation and transportation services to our lessees, which enhance their production levels and generate additional coal royalty revenues. We also earn revenues from third party end-users by owning and operating coal handling facilities through our joint venture with Massey Energy Company.

Recent Developments

Acquisition of Natural Gas Midstream Business

On March 3, 2005, we completed our acquisition of Cantera Gas Resources, LLC, a midstream gas gathering and processing company with primary locations in the mid-continent area of Oklahoma and the panhandle of Texas. With the closing of the acquisition, we own and operate a significant set of midstream assets that include approximately 3,400 miles of gas gathering pipelines and three natural gas processing facilities, which have 160 million cubic feet per day (MMcfd) of total capacity. Our midstream business derives revenues primarily from gas processing and gas purchase contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. We believe the acquisition will establish a platform for future growth in the natural gas midstream sector and will diversify our cash flows into another long-lived asset base. In addition, we expect the acquisition to be accretive to distributable cash flow on a per unit basis.

The total purchase price for the acquisition was approximately $191 million, which we funded with a $110 million term loan and with borrowings under our revolving credit facility. We intend to use the proceeds from our sale of common units in this offering to repay in full our term loan and to reduce outstanding indebtedness under our revolving credit facility.

After giving effect to our acquisition of Cantera, our pro forma earnings before interest, taxes, depreciation, depletion and amortization, or EBITDA, for 2004 would have been $88.9 million, compared to our historical EBITDA for 2004 of $59.2 million. For a discussion of EBITDA and a reconciliation of EBITDA to net income and cash flows from operating activities, please read “Non-GAAP Financial Measure” on page S-11 of this prospectus supplement.

The midstream operations currently include three gas gathering and processing systems and one stand-alone gas gathering system. The systems in total are currently gathering volumes in excess of 135 MMcfd, and the gas plants are processing an estimated 113 MMcfd and producing approximately 9,200 barrels per day of natural gas liquids (NGLs).

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These midstream operations generate revenues from a variety of gas contracts. In 2004, approximately 52% of the volumes were processed under gas purchase / keep-whole contracts, 34% were processed under percentage of proceeds contracts, and 14% were processed under fee-based gathering contracts. A majority of the gas purchase / keep-whole and percentage of proceeds contracts include fee-based components such as gathering and compression charges. There is also a processing fee floor included in many of the gas purchase / keep-whole contracts that ensures a minimum processing margin should the actual margins fall below the floor.

In addition to the four midstream systems, we also acquired Cantera’s natural gas marketing business, which aggregates third-party volumes and sells them into intrastate pipelines and at market hubs accessed by various interstate pipelines. For the year ended December 31, 2004, this business generated approximately $2.1 million in net revenue.

Increase in Quarterly Distribution to Unitholders

On March 3, 2005, the board of directors of our general partner announced the declaration of a regular quarterly cash distribution of $0.62 per unit payable May 13, 2005, to unitholders of record on May 3, 2005. This cash distribution represents an increase in our quarterly cash distribution of $0.0575 per unit, or 10.2%, to an indicated annual cash distribution level of $2.48 per unit.

Business Strategies

With our acquisition of Cantera, we will continue to operate as a diversified, growth-oriented master limited partnership with a focus on increasing the amount of cash available for distribution per common unit. We believe that by pursuing independent operating and growth strategies for our coal and midstream businesses, we will be well-positioned to achieve our objectives. In addition, the Cantera acquisition provides us with profitable assets associated with long-lived reserves, and establishes a solid platform for growth in the midstream business.

Coal Business Strategies

The principal strategies for our coal business are:

Pursue coal reserve acquisition opportunities.    We have been engaged in the coal land management business in Appalachia since 1882. We intend to continue to actively pursue opportunities to expand our eastern reserves through acquisition of additional coal reserves and development of our existing properties. We are also considering ways to continue to expand geographically by evaluating acquisition opportunities in several coal basins, including the Illinois basin.

Expand our coal services operations.    Coal infrastructure projects are typically long-lived, fee-based assets that generally produce steady and predictable cash flows, and, therefore, are attractive to master limited partnerships. In 2004, we put the Bull Creek loadout facility into service and entered into a coal handling joint venture with Massey Energy, which has allowed us to invest in fee-based, coal-related infrastructure projects involving end users of coal in the chemical, paper and lime production industries in Tennessee, Virginia and Kentucky. We intend to continue to look for growth opportunities in our coal services operations.

Midstream Business Strategies

The principal strategies for our midstream business are:

Grow through acquisitions.    We intend to pursue strategic acquisitions of midstream assets in our current areas of operation, which may provide us opportunities for operational efficiencies and the potential for increased utilization and expansion of our existing and acquired assets. We will also pursue midstream

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asset acquisition opportunities in other regions of the United States with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas. We believe our affiliation with Penn Virginia Corporation, an energy company engaged in the exploration, development and production of oil and natural gas in Appalachia and the Gulf Coast, will provide us with opportunities to purchase other midstream assets.

Enhance cash flows from existing assets.    Our systems have excess capacity which provides us with opportunities to increase our gathering and processing volumes with minimal incremental cost. We intend to increase the cash flows from our existing asset base by adding new volumes of natural gas and undertaking additional initiatives to enhance utilization. We also intend to leverage our existing infrastructure and existing customer relationships by constructing and expanding systems to meet new or increased demand for midstream services.

Reduce commodity price risk.    We intend to increase the percentage of our midstream business conducted with third parties under arrangements which cap the risk of exposure to changes in the prices of natural gas and NGLs. For example, we intend that our future gas purchase/keep-whole arrangements will provide a floor mechanism that will allow us to recover a fee from a customer at any time the fractional value of processing that customer’s gas falls below a certain level. This mechanism eliminates keep-whole risk and provides a revenue floor. We also intend to use commodity price risk management tools available in the financial markets to mitigate commodity price risk. For example, we entered into notional derivative contracts for 75% of the net volume of NGLs we expect to sell from April 2005 through December 2006.

Partnership Structure

Our operations are conducted through, and our operating assets are owned by, our operating subsidiaries. We own our operating subsidiaries through our operating company, Penn Virginia Operating Co., LLC. Upon consummation of this offering of common units (including the offering by the selling unitholder) and the Cantera acquisition:

Our general partner and its affiliates are entitled to distributions on the general partner interest and on any common units or subordinated units they hold. Additionally, our general partner is entitled to distributions, if any, on its incentive distribution rights. Our general partner has sole responsibility for conducting our business and for managing our operations. Our general partner does not receive any management fee or other compensation in connection with its management of our business but is entitled to be reimbursed for all direct and indirect expenses incurred on our behalf.

The chart on the following page depicts the organization and ownership of Penn Virginia Resource Partners after giving effect to the offering of the common units (including the offering by the selling unitholder) and the Cantera acquisition.

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The Offering

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Summary Historical and Pro Forma Financial Data

The following table shows summary historical financial data for Penn Virginia Resource Partners. The following table also sets forth pro forma financial data and reflects our historical results as adjusted on a pro forma basis to give effect to the consummation of the Cantera acquisition, our sale of 2,511,842 common units in this offering and the use of proceeds from this offering as if these transactions had occurred as of January 1, 2004 for income statement purposes and December 31, 2004 for balance sheet purposes. The summary unaudited pro forma financial data do not purport to be indicative of the results of operations or the financial position that would have occurred had the Cantera acquisition and the offering occurred on the dates indicated, nor do they purport to be indicative of future results of operations or financial position.

The summary historical financial information for Penn Virginia Resource Partners as of and for the years ended December 31, 2002, 2003 and 2004 was derived from our audited financial statements. The summary pro forma financial information for the year ended December 31, 2004 was derived from the unaudited pro forma financial statements included elsewhere in this prospectus supplement. For a discussion of the assumptions and specific adjustments used in preparing the summary pro forma financial data, please read the pro forma financial statements included elsewhere in this prospectus supplement. The summary historical and pro forma financial and operating data should be read in conjunction with (1) the historical financial statements and related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” appearing in our Annual Report on Form 10-K for the year ended December 31, 2004, which is incorporated by reference into this prospectus supplement, (2) the historical financial statements and related notes for Cantera Natural Gas, LLC—Mid Continent Division and “Results of Operations of Cantera Natural Gas, LLC—Mid Continent Division” contained in this prospectus supplement and (3) our pro forma financial statements and related notes contained in this prospectus supplement, as well as the other financial and operating data included or incorporated by reference in this prospectus supplement.

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Non-GAAP Financial Measure

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

We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation, depletion and amortization expense.

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

EBITDA is also a financial measurement that, with certain negotiated adjustments, is reported to our banks and is used to compute our financial covenants under our credit facilities. EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Our EBITDA may not be comparable to EBITDA or similarly titled measures of other entities, as other entities may not calculate EBITDA in the same manner as we do. We have reconciled EBITDA to net income and cash flows from operating activities.

The following table presents a reconciliation of the non-GAAP financial measure of EBITDA to the GAAP financial measures of net income and cash flows from operating activities, in each case, on a historical basis and pro forma as adjusted for this offering and the application of the net proceeds, as applicable, for each of the periods indicated.

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RISK FACTORS

An investment in our common units involves a high degree of risk. You should carefully consider the following risk factors together with all of the other information included in, or incorporated by reference into, this prospectus supplement when evaluating an investment in our common units. If any of the following risks were to occur, our business, financial condition or results of operations could be adversely affected. In that case, the trading price of our common units could decline and you could lose all or part of your investment.

These risks relate principally to the Cantera transaction and the operations of our midstream business. For information concerning the risks related to our coal business and other risks, please read the risk factors included under the caption “Risk Factors” beginning on page 2 of each accompanying prospectus and in Item 1 of our Annual Report on Form 10-K for the year ended December 31, 2004 incorporated by reference herein.

The amount of cash we will be able to distribute on our common units principally will depend upon the amount of cash we generate from our midstream operations and our existing coal business.

Under the terms of our partnership agreement, we must pay our general partner’s expenses and set aside any cash reserve amounts before making a distribution to our unitholders. Following the acquisition of Cantera, the amount of cash we will be able to distribute on our common units principally will depend upon the amount of cash we generate from our midstream operations and our existing coal business. The amount of cash we will generate will fluctuate from quarter to quarter based on, among other things:

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

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You should also be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record profits.

We may be unable to successfully integrate the operations of our midstream business with our operations and to realize all of the anticipated benefits of the acquisition of Cantera.

Prior to the Cantera acquisition, we had not been engaged in the midstream business. The acquisition involves the integration of two companies in separate lines of business that previously have operated independently, which is a complex, costly and time-consuming process. Failure to timely and successfully integrate our midstream business may have a material adverse effect on our business, financial condition or results of operations. The difficulties of integrating our midstream business include, among other things:

We operate in distinct business segments that require different operating strategies and different managerial expertise. While we intend to operate each of these two business segments independently by management experienced in such segments, we cannot assure you that this approach will be successful.

The diversion of management’s attention and any delays or difficulties encountered in connection with the integration of the midstream operations, such as unanticipated liabilities or costs, could harm our business, results of operations, financial condition or prospects. Furthermore, the integration may not result in the realization of the full benefits we anticipate from the acquisition.

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

In order to maintain or increase throughput levels on our gathering systems and asset utilization rates at our processing plants, we must continually contract for new natural gas supplies. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity creating new gas supply near our gathering 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 the 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 the cost of capital.

A substantial portion of our 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 access new supplies of natural gas by

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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.

The profitability of our 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 now subject to significant risks due to fluctuations in commodity prices. During the year ended December 31, 2004, Cantera 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—percentage-of-proceeds and keep-whole arrangements.

Virtually all of the natural gas gathered at the Crescent System and the Hamlin System is contracted under percentage-of-proceeds arrangements. The natural gas gathered on Beaver System is contracted 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 upon an index price for the gas and the price received for the NGLs. Under these percentage-of-proceeds arrangements, revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have a material adverse effect on our results of operations. 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 results of operations.

In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2004, the NYMEX settlement price for natural gas for the prompt month contract ranged from a high of $7.98 per million Btu (MMBtu), to a low of $5.08 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon Cantera’s average NGLs composition during the year ended December 31, 2004 ranged from a high of approximately $0.85 per gallon to a low of approximately $0.57 per gallon.

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 fluctuate with changes in market and economic conditions, and other factors, including:

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We encounter competition from other midstream companies.

We experience competition in all of our midstream markets. Competition is based on many factors, including geographic proximity to production, costs of connection, available capacity, rates and access to markets. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, process, transport and market natural gas. The Beaver System competes with natural gas gathering and processing systems owned by Duke Energy Field Services, LLC. The Crescent System competes with natural gas gathering and processing systems owned by Duke Energy Field Services LLC and Mustang Fuel Corp. The Hamlin System competes with natural gas gathering and processing systems owned by West Texas Gas Processing. Many of our competitors have greater financial resources and access to larger natural gas supplies than we do.

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

Cantera Gas Company, or CGC, a wholly owned subsidiary of PVR Midstream LLC, owns and operates an 11-mile interstate natural gas pipeline which, pursuant to the Natural Gas Act of 1938, or NGA, is subject to the jurisdiction of the Federal Energy Regulatory Commission, or FERC. FERC has granted CGC 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. FERC has determined that CGC will have to comply with the filing requirements if the natural gas company ever desires to apply for blanket transportation authority to transport third-party gas on the 11-mile pipeline. We cannot assure you that the FERC will maintain these waivers.

Our natural gas gathering facilities generally are exempt from FERC’s jurisdiction under the NGA, but FERC regulation nevertheless could significantly affect our gathering business and the market for our services. In recent years, 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 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.

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. See “Acquisition of Natural Gas Midstream Business—Regulation of our Midstream Business.”

Texas and Oklahoma administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, as amended, or NGPSA, which requires certain pipelines to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. In response to recent pipeline accidents, Congress and the Department of Transportation, or DOT, have recently instituted heightened

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pipeline safety 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. See “Acquisition of Natural Gas Midstream Business—Regulation of our Midstream Business”

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

Our midstream business involves hazardous substances and may be adversely affected by 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 Cantera or locations to which it has sent wastes for disposal. Various governmental authorities have the power to enforce compliance with these regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Liability may be incurred without regard to fault for the remediation of contaminated areas. Private parties, including the owners of properties through which our gathering systems pass, may also have the right to pursue legal action to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage.

There is inherent risk of the incurrence of environmental costs and liabilities in our midstream business due to our handling of natural gas and other petroleum products, air emissions related to our midstream operations, historical industry operations, waste disposal practices and Cantera’s prior use of natural gas flow meters containing mercury. In addition, 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. Furthermore, insurance may not provide sufficient coverage in the event an environmental claim is made.

Our midstream business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might adversely affect its products and activities, including gathering, compression, treating, processing and transportation, as well as waste management and air emissions. Federal and state agencies could also impose additional safety requirements, any of which could affect our profitability. See “Acquisition of Natural Gas Midstream Business—Environmental Matters Relating to our Midstream Business.”

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

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

These risks could result in substantial losses due to personal injury and/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 midstream operations are concentrated in Texas and

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Oklahoma, and a natural disaster or other hazard affecting these areas could have a material adverse effect on our operations. We are not fully insured against all risks incident to our 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 operations and financial condition.

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

One of the ways we may grow our midstream business is through the construction of additions to existing gathering, compression and processing systems. The construction of a new gathering system or pipeline or the expansion of an existing pipeline, by adding additional horsepower or pump stations or by adding a second pipeline within an existing right of way, 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. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted 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 may not be able to attract enough natural gas to achieve our expected investment return, which could adversely affect our financial position or results of operations.

We are exposed to the credit risk of our midstream customers, and an increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

Risks of nonpayment and nonperformance by our midstream customers are a major concern in our midstream business. Several participants in the energy industry have been receiving heightened scrutiny from the financial markets in light of the collapse of Enron Corp. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We depend on a limited number of customers for a significant portion of our midstream revenue. For the year ended December 31, 2004, four customers represented 19.5% (BP Canada Energy Marketing), 15.3% (Conoco Phillips), 13.0% (Tenaska Marketing Ventures) and 10.0% (OGE Energy Resources) of total midstream revenue. Any increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.

The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets we serve.

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

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 midstream facilities. Similarly, if additional shippers begin transporting volumes of residue gas and NGLs on interconnecting pipelines, our allocations in these pipelines would be reduced. Any reduction in volumes gathered and processed in our facilities would adversely affect our revenues and cash flow.

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We may not be able to fully execute our growth strategy and our results of operations may be adversely affected if we do not successfully integrate the businesses we acquire or if we substantially increase our indebtedness and contingent liabilities.

Our strategy contemplates growth through the development and acquisition of a wide range of midstream and coal assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively and diversify our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating, potential joint ventures, stand alone projects or other transactions that we believe will present opportunities to realize synergies and increase our market positions in the coal and midstream businesses.

We may require substantial new capital to finance the future development and acquisition of assets and businesses. Limitations on our access to capital will impair our ability to execute this strategy. Expensive capital will limit our ability to develop or acquire accretive assets.

Similar to the risks associated with integrating our midstream operations with our coal operations, we may be unable to integrate successfully businesses we acquire in the future. We may incur substantial expenses or encounter delays or other problems in connection with our growth strategy that could negatively impact our results of operations, cash flows and financial condition. Moreover, acquisitions and business expansions involve numerous risks, including:

If consummated, any acquisition or investment would also likely result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation, depletion and amortization expenses. As a result, our capitalization and results of operations may change significantly following an acquisition. A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our business.

Derivative instruments expose us to risks of financial loss in a variety of circumstances.

We use derivative instruments in an effort to reduce our exposure to fluctuations in the prices of natural gas and NGLs. Our derivative instruments expose us to risks of financial loss in a variety of circumstances, including when:

Derivative instruments may limit our ability to realize increased revenue from increases in the prices for natural gas and NGLs.

We account for our derivative transactions pursuant to Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS 133 requires us to record each hedging transaction as an asset or liability measured at its fair value. We must also measure the effectiveness of our hedging position in relation to the underlying commodity being hedged, and we will be required to record the ineffective portion of the hedge in our net income for that period. This accounting treatment could result in significant fluctuations in net income and partners’ capital from period to period.

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USE OF PROCEEDS

We plan to use (i) the net proceeds from the sale of 2,511,842 common units in this offering of approximately $134.1 million (after deducting underwriting discounts and commissions and estimated offering expenses), or approximately $161.2 million if the underwriters exercise their right to purchase additional common units, and (ii) the $2.7 million capital contribution from our general partner to maintain its 2% interest in us to repay in full our $110 million term loan and to reduce outstanding indebtedness under our revolving credit facility.

On March 3, 2005, we borrowed $110 million under our term loan and $92.3 million under our revolving credit facility to fund the acquisition of Cantera. The term loan matures on March 3, 2010 and currently bears interest at a rate of 4.51%. Indebtedness under our revolving credit facility currently bears interest at a rate of 4.51%. Please read “Results of Operations of Cantera Natural Gas, LLC—Mid Continent Division—Financing and Sources of Liquidity” for a description of our credit agreement.

We will not receive any proceeds from the sale of common units by the selling unitholder.

An affiliate of RBC Capital Markets, an underwriter participating in this offering, is a lender to us under our $110 million term loan and our revolving credit facility and will receive a share of the repayment of those loans from the net proceeds of this offering. See “Underwriting.”

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ACQUISITION OF NATURAL GAS MIDSTREAM BUSINESS

Substantially all of the information presented below regarding Cantera’s operations is based on information provided to us by Cantera in connection with the acquisition. For a description of our coal business, please read our Annual Report on Form 10-K for the year ended December 31, 2004 incorporated by reference into this prospectus supplement.

Overview

On March 3, 2005, we completed our acquisition of Cantera Gas Resources, LLC, a midstream gas gathering and processing company with primary locations in the mid-continent area of Oklahoma and the panhandle of Texas. With the closing of the acquisition, we now own and operate a significant set of midstream assets that include approximately 3,400 miles of gas gathering pipelines and three natural gas processing facilities, which have total capacity of 160 million MMcfd. The midstream business derives revenues primarily from gas processing and gas purchase contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In 2004, Cantera’s three gas plants processed an estimated 105 MMcfd and produced approximately 8,800 barrels per day of NGLs. In addition to our acquisition of the gathering systems and natural gas processing facilities, we also acquired Cantera’s natural gas marketing business, which aggregates third-party volumes and sells them into intrastate pipelines and at market hubs accessed by various interstate pipelines.

The following table set forth below contains information regarding the four midstream systems:

Midstream Industry Overview

The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets. It consists of natural gas gathering, dehydration, compression, treating, processing and transportation and NGL fractionation and transportation. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

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The following diagram illustrates the natural gas gathering, dehydration, compression, treating, processing, fractionation and transportation processes. Of these services, we provide natural gas gathering, dehydration, compression, processing, transportation and related services to our customers.

Demand for natural gas.    Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or the EIA, total domestic consumption of natural gas is expected to increase by over 2.5% per annum, on average, to 26.2 trillion cubic feet, or Tcf, by 2010, from an estimated 21.9 Tcf consumed in 2003, representing approximately 24% of all total end-user energy requirements by 2010. During the last five years, the United States has on average consumed approximately 22.6 Tcf per year, with average domestic production of approximately 24.1 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

Natural gas reserves and production.    According to the EIA, as of December 31, 2003, operators in the United States had 189 Tcf of dry natural gas reserves and 7.5 BBbls of NGL reserves. Texas has the largest amount of natural gas reserves of any state, accounting for approximately 24.2% of the United States’ dry natural gas reserves and approximately 33.7% of its NGL reserves. Oklahoma has the 7th largest amount of dry natural gas reserves of any state, accounting for approximately 8.1% of the United States’ dry natural gas reserves, and has the 6th largest amount of NGLs, accounting for approximately 9.2% of its NGL reserves. Driven by growth in natural gas demand, domestic onshore natural gas production is projected to increase from 18.9 Tcf per year to 20.5 Tcf per year between 2004 and 2010. According to the EIA, in 2003, Texas was the largest state in terms of domestic natural gas production, with approximately 26.3% of total natural gas production, and Oklahoma was the 4th largest state, with approximately 7.8% of total natural gas production.

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 throughput volume. 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.

Natural gas gathering.    The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from the wells and transport it to larger pipelines for further transportation.

Natural gas compression.    Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Specifically, lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to gathering systems and continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly more difficult to deliver the remaining production in the ground against a higher pressure in the gathering system. Field compression is typically used to lower the pressure of a gathering system.

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Natural gas dehydration.    Some produced natural gas is saturated with water, which must be removed because the combination of natural gas and water can form ice that can plug the pipeline gathering and transportation system. Water in a natural gas stream can also cause corrosion when combined with carbon dioxide or hydrogen sulfide in natural gas and condensed water in the pipeline can raise pipeline pressure. To avoid these potential issues and to meet downstream pipeline and end-user gas quality standards, natural gas is dehydrated to remove the excess water.

Natural gas treating.    Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations is high in carbon dioxide, hydrogen sulfide or certain other contaminants. Treating plants remove contaminants from natural gas to ensure that it meets pipeline quality specifications. We do not currently treat natural gas.

Natural gas processing.    Some natural gas produced by a well does not meet pipeline quality specifications or is not suitable for commercial use and must be processed to remove the NGLs. In addition, some natural gas produced by a well, while not required to be processed, can be processed to take advantage of favorable processing margins. Natural gas processing involves the separation of natural gas and a mixed NGL stream.

Natural gas fractionation.    NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane and natural gasoline. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Isobutane is primarily used to enhance the octane content of motor gasoline. Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient in synthetic rubber), as a blendstock for motor gasoline and to derive isobutane through isomerization. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock. We do not own or operate fractionation facilities.

Natural gas transportation.    Natural gas transportation pipelines receive natural gas from gathering systems and other mainline transportation pipelines and deliver the natural gas to industrial end-users, utilities and other pipelines.

Description of our Midstream Operations

The midstream operations we acquired from Cantera currently include three gas gathering and processing systems and one standalone gas gathering system, including: (1) the Beaver/Perryton gathering and processing facilities in the Texas/Oklahoma panhandle area, (2) the Crescent gathering and processing facilities in central Oklahoma, (3) the Hamlin gathering and processing facilities in west-central Texas, and (4) the Arkoma gathering system in eastern Oklahoma.

The Beaver/Perryton System

General.    The Beaver/Perryton System is a natural gas gathering system stretching over eight counties in the Anadarko Basin of the panhandle of Texas and Oklahoma. The system consists of approximately 1,160 miles of natural gas gathering pipelines, ranging in size from two to 16 inches in diameter, and the Beaver natural gas processing plant. Included in the system is an 11-mile, 10-inch diameter, FERC-jurisdictional residue line, which connects the Beaver processing plant with ANR Pipeline Company’s system. No third-party products are transported on the FERC-jurisdictional residue line. The Beaver/Perryton System is comprised of several major gathering systems that gather gas, directly or indirectly, to the Beaver plant in Beaver County, Oklahoma. Seventeen compressor stations are operating across the Beaver/Perryton System.

The Beaver/Perryton System includes the Beaver, Perryton, Spearman, Wolf Creek/Kiowa Creek and Ellis systems. These gathering systems are located in Beaver, Ellis and Harper counties in Oklahoma and Ochiltree, Lipscomb, Hansford, Hutchinson and Roberts counties in Texas.

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The Beaver natural gas processing plant has 100 MMcfd of inlet gas capacity. The plant is capable of relatively high ethane recovery, and is instrumented to allow for unattended operations 16 hours per day.

Natural Gas Supply.    The supply in the Beaver/Perryton System comes from approximately 178 producers pursuant to 416 contracts. The average gas quality on the Beaver/Perryton System for 2004 was 3.01 gallons of NGLs per delivered Mcf.

Markets for Sale of Natural Gas and NGLs.    The residue gas from the Beaver plant can be delivered into 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 Koch Hydrocarbon’s pipeline system for transportation to and fractionation at Koch’s Conway fractionator.

The Crescent System

General.    The Crescent System is a natural gas gathering system stretching over nine counties within central Oklahoma’s Sooner Trend. The system consists of approximately 1,670 miles of natural gas gathering pipelines, ranging in size from two to 10 inches in diameter, and the Crescent gas processing plant located in Logan County, Oklahoma. Sixteen compressor stations are operating across the Crescent system.

The Crescent plant is a NGL recovery plant with current capacity of approximately 28 MMcfd, which can be expanded to 40 MMcfd with installation of additional compression. 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.    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 245 producers pursuant to 390 contracts. The average gas quality on the Crescent System for 2004 was 5.28 gallons of NGLs per delivered Mcf.

Markets for Sale of Natural Gas and NGLs.    The Crescent plant’s connection to the Enogex and ONEOK Gas Transportation pipelines for residue gas and the Koch Hydrocarbon pipeline for NGLs give the Crescent system access to a variety of market outlets.

The Hamlin System

General.    The Hamlin System is a natural gas gathering system stretching over 10 counties in West Central Texas. The system consists of approximately 515 miles of natural gas gathering pipelines, ranging in size from two to 12 inches in diameter, and the Hamlin natural gas processing plant located in Fisher County, Texas. Nine compressor stations are operating across the system.

Natural Gas Supply.    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 98 producers pursuant to 118 contracts. The average gas quality on the Hamlin System for 2004 was 8.45 gallons of NGLs per delivered Mcf.

Markets for Sale of Natural Gas and NGLs.    The Hamlin System delivers the residue gas from the Hamlin System into the Enbridge or Atmos pipelines. NGLs from the Hamlin plant are tendered into a line operated by TEPPCO.

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The Arkoma System

General.    The Arkoma System is a stand-alone gathering operation in southeastern Oklahoma’s Arkoma Basin and is comprised of three separate gathering systems, two of which are 100% owned with the third system being 33% owned. We operate and maintain all three systems. The Arkoma System consists of a total of approximately 78 miles of natural gas gathering pipelines, ranging in size from three to 12 inches in diameter. Three compressor stations are operating across the Arkoma System.

Natural Gas Supply.    The supply on the Arkoma System comes from approximately 21 producers pursuant to 31 contracts.

Markets for Sale of Natural Gas and NGLs.    The Arkoma System lines deliver gas into the Ozark, Noram and NGPL pipelines.

Natural Gas Marketing

We also acquired Cantera’s natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems such as Enogex and ONEOK and at market hubs accessed by various interstate pipelines. The largest third-party customer is Chesapeake Energy Corp. with volumes contracted through 2007. Revenue from this business does not generate qualifying income for a master limited partnership, but we do not expect it to have an impact on our tax status, as it represents an insignificant percentage of our operating income. For the year ended December 31, 2004, this business generated approximately $2.1 million in net revenue.

Employees

To carry out our midstream operations, we employ approximately 75 people. We are not a party to any collective bargaining agreements.

Competition

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:

We experience competition in all of our midstream markets. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, process, transport and market natural gas. The Beaver System competes with natural gas gathering and processing systems owned by Duke Energy Field Services, LLC. The Crescent System competes with natural gas gathering and processing systems owned by Duke Energy Field Services LLC and Mustang Fuel Corp. The Hamlin System competes with natural gas gathering and processing systems owned by West Texas Gas Processing. Many of our competitors have greater financial resources and access to larger natural gas supplies than we do. Please read, “Risk Factors—We encounter competition from other midstream companies.”

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Regulation of our Midstream Business

Regulation by FERC of Interstate Natural Gas Pipeline

Cantera Gas Company, or CGC, a wholly owned subsidiary of PVR Midstream LLC, is subject to FERC jurisdiction under the NGA as the owner and operator of an 11-mile interstate natural gas pipeline located in Beaver County, Oklahoma. Although FERC has granted CGC a waiver 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, we cannot assure you that the FERC will maintain these waivers. A change in circumstances with respect to the character of service on CGC’s FERC-jurisdictional pipeline, such as the use of the pipeline to provide transportation service to a third-party or the sale of the Beaver Plant, could result in the reinstatement of the filing requirements applicable to conventional natural gas companies, including the requirement to file a FERC tariff governing service on the FERC-jurisdictional pipeline. CGC’s tariff would be required to reflect rates and terms and conditions of service that satisfy the “just and reasonable” and nondiscriminatory standards set forth under the NGA. CGC would also be required to either comply with, or seek exemptions from, FERC regulations and policies governing natural gas companies that provide open access natural gas transportation service.

FERC’s regulation also influences certain aspects of our business. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce, and its authority to regulate those services includes:

In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines into which our gathering pipelines deliver. We cannot assure you of FERC’s continuation of this approach, however, as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

Gathering Pipeline Regulation

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We now own a number of pipeline facilities in Texas and Oklahoma that we believe meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some instances, nondiscriminatory take requirements and complaint-based rate regulation.

In Texas, our gathering facilities are subject to regulation by the Railroad Commission of Texas, or TRRC, under the Texas Utilities Code. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including certain gathering facilities, are just and reasonable and not discriminatory. The rates we charge for gathering services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.

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Our operations in Oklahoma are regulated by the Oklahoma Corporation Commission through a complaint-based procedure. Under the Oklahoma Corporation Commission’s regulations, we are prohibited from charging any unduly discriminatory fees for our gathering services and in certain circumstances are required to provide open access natural gas gathering for a fee.

We are subject to state ratable take and common purchaser statutes in Texas and Oklahoma. The 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 are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. 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.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed 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. For example, the TRRC’s regulations governing transportation and gathering services performed by gatherers prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of 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 access and rate discrimination. 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 operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Sales of Natural Gas

The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers.

Pipeline Safety

Texas and Oklahoma administer federal pipeline safety standards under the NGPSA, as amended, which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Consistent with the Pipeline Safety Improvement Act of 2002, which amended the NGPSA in part, the DOT has developed new regulations, effective January 14, 2004, that establish mandatory inspections for all natural gas transmission pipelines in high-consequence areas within 10 years. The new regulations require pipeline operators to implement integrity management programs, including more frequent inspections, and other safety protections in areas where the consequences of potential pipeline accidents

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pose the greatest risk to life and property. Failure to comply with these federal pipeline safety requirements may result in the imposition of administrative, civil and criminal remedies. Substantial portions of our gathering facilities are exempt from the NGPSA, as amended, under the rural gathering exemption. The portions of our facilities that are exempt include those portions located outside of cities, towns or any area designated as residential or commercial, such as a subdivision or shopping center. We cannot assure you that the rural gathering exemption will be retained in its current form in the future.

Environmental Matters Relating to Our Midstream Business

The operation of pipelines, plants and other facilities for gathering, compressing, treating, processing or transporting natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or prohibit our business activities that affect the environment in many ways, such as:

In most instances, the environmental laws and regulations affecting our midstream operations relate to the potential release of substances or waste products into the air, water or soils and include measures to control or prevent the release of substances or waste products to the environment. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulation and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions and federally authorized citizen suits. 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 other waste products to the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.

The following is a discussion of certain environmental and safety concerns that relate to the midstream natural gas and NGLs industry. It is not intended to constitute a complete discussion of all applicable federal, state and local laws and regulations, or specific matters, to which we may be subject.

Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations govern emissions of pollutants into the air resulting from our activities, for example in relation to our processing plants and compressor stations, and also impose procedural requirements on how we conduct our 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

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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. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“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 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.

Our operations could incur liability under the Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA and also known as Super Fund, and comparable state laws regardless of our fault, in connection with the disposal or other release of hazardous substances or wastes, including those arising out of historical operations conducted by Cantera, Cantera’s predecessors or third parties on properties formerly owned by Cantera. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of “hazardous substance,” in the course of its ordinary operations Cantera has generated and we will generate wastes that may fall within the definition of a “hazardous substance.” 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 to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment. If we were to incur liability under CERCLA, we could be subject to joint and several liability for the costs of cleaning up hazardous substances, for damages to natural resources and for the costs of certain health studies.

We currently own or lease, and Cantera has in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although Cantera 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 the properties owned or leased by Cantera or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under Cantera’s control. 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 closure operations to prevent future contamination. Third parties and we have ongoing remediations underway at several sites, but we do not believe that the associated costs will have a material impact on our operations.

Our operations can result in discharges of pollutants to waters. The Federal Water Pollution Control Act of 1972, as amended (“FWPCA”), also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The unpermitted discharge of pollutants such as from spill or leak incidents is prohibited. The FWPCA and

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regulations implemented thereunder also prohibit discharges of fill material and certain other activities in wetlands unless authorized by an appropriately issued permit. 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.

We are subject to the requirements of the Occupational Safety and Health Act, referred to as 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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CANTERA NATURAL GAS, LLC—MID CONTINENT DIVISION

SELECTED HISTORICAL FINANCIAL DATA

The following table sets forth selected historical financial data for Cantera Natural Gas, LLC—Mid Continent Division as of December 31, 2003 and 2004 and for the period from June 25, 2003 (inception) through December 31, 2003 and for year ended December 31, 2004. On July 2, 2003, Cantera purchased all of the shares of CMS Field Services, Inc. (“CMS”) which included all of the CMS assets located in the mid-continent region of the United States. Cantera’s historical financial information for the period from June 25, 2003 (date of inception) to December 31, 2004 has been derived from the historical financial statements of Cantera included in this prospectus supplement. The selected historical financial data should be read in conjunction with those financial statements and the notes thereto as well as “Results of Operations of Cantera Natural Gas, LLC—Mid Continent Division”

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RESULTS OF OPERATIONS OF CANTERA NATURAL GAS, LLC—MID CONTINENT DIVISION

You should read the following discussion of the results of operations of Cantera Natural Gas, LLC—Mid Continent Division in conjunction with the historical and pro forma combined financial statements and notes thereto included elsewhere in this prospectus supplement. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the historical and pro forma financial statements included in this prospectus supplement. For detailed information concerning the results of operations and financial condition of our coal business, please read our Annual Report on Form 10-K for the year ended December 31, 2004 incorporated by reference into this prospectus supplement.

Overview

Historically, the revenue generated by the midstream business we acquired from Cantera was derived from the sale of residue gas, NGLs and condensate, fees collected for gathering and transporting natural gas and NGLs, and marketing of gas for third parties. Cantera’s results were determined primarily by the volumes of natural gas purchased, gathered, compressed, processed and sold through Cantera’s gathering systems and the level of natural gas and NGL prices. Historically, Cantera generated its revenues and its gross margins principally under the following types of contractual arrangements, which we assumed when we acquired Cantera’s business:

Gas purchase / keep-whole arrangements.    Under these arrangements, Cantera generally purchased natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a combination of (1) and (2). It then gathered the natural gas to one of its plants where it was processed to extract the entrained NGLs and sold the produced NGLs to third parties at market prices. Cantera then resold the remaining natural gas to third parties at an index price which typically corresponded 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, Cantera had a reduced volume of gas to sell after processing. Accordingly, under these arrangements, Cantera’s revenues and gross margins increased as the price of NGLs increased relative to the price of natural gas, and its revenues and gross margins decreased as the price of natural gas increased relative to the price of NGLs. In the latter case, Cantera had generally been able to mitigate this exposure in many of its gas purchase / keep-whole arrangements through the inclusion of minimum processing charges within the contracts that ensured that Cantera received a minimum amount of processing revenue thus avoiding low or negative processing margins. The gross margins Cantera realized under the arrangements described in clauses (1) and (3) above also decreased 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, Cantera generally gathered and processed natural gas on behalf of producers, sold the resulting residue gas and NGL volumes at market prices and remitted 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, Cantera’s revenues and gross margins increased as natural gas prices and NGL prices increased, and its revenues and gross margins decreased as natural gas prices and NGL prices decreased.

Fee-based arrangements.    Under fee-based arrangements, Cantera received fees for gathering, compressing and/or processing natural gas. The revenue it earned from these arrangements was directly dependent on the volume of natural gas that flowed through its systems and was independent of commodity prices. To the extent a sustained decline in commodity prices resulted in a decline in volumes, however, its revenues from these arrangements were reduced due to the related reduction in drilling and development of new supply.

In many cases, Cantera provided services under contracts that contain a combination of more than one of the arrangements described above. The terms of its contracts varied 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.

Cantera also derived revenues from its natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems such as Enogex and ONEOK and at market hubs

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accessed by various interstate pipelines. Revenue from this business does not generate qualifying income for a master limited partnership. For the year ended December 31, 2004, this business generated approximately $2.1 million in net revenue.

Cantera realized significant economies of scale because as additional volumes of natural gas moved through its systems, and its incremental operating and administrative costs did not increase materially. Operating expenses are costs directly associated with the operations of a particular asset and include direct labor and supervision, property insurance, ad valorem taxes, repair and maintenance expenses, measurement and utilities. These costs are generally fixed across broad volume ranges. Fuel expense to operate the gathering systems and plants is more variable in nature and is sensitive to changes in volume and commodity prices; however, the cost of fuel related to gathering and in many cases the fuel needed to operate the plants is generally borne by the gas supplying producers.

Cantera’s profitability was affected by volatility in prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market uncertainty. For a discussion of the volatility of natural gas and NGL prices, please read “Risk Factors—Our profitability is dependent upon prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile.” The mix of Cantera’s contractual arrangements described above mitigated exposure to the volatility of natural gas and NGL prices. Gas prices could also affect Cantera’s profitability indirectly by influencing drilling activity and related opportunities for natural gas gathering, compression, processing and marketing.

In order to mitigate commodity price risk to the economics of the Cantera acquisition, in January 2005 we entered into notional derivative contracts for approximately 75% of the net volume of NGLs expected to be sold from April 2005 through December 2006. Prior to closing the Cantera acquisition, the derivative contracts did not qualify for hedge accounting. We are currently evaluating the effectiveness of the derivative contracts in relation to the underlying commodities, and we expect to designate the contracts as cash flow hedges in accordance with Statement of Financial Accounting Standards No. 133 (SFAS 133) “Accounting for Derivative Instruments and Hedging Activities.” The aggregate fair value of the contracts as of March 3, 2005 was approximately $9 million favorable to the counterparty and will be recognized as a reduction of earnings in the first quarter of 2005. If the derivatives qualify for cash flow hedges, SFAS 133 requires us to continue to measure the effectiveness of the derivative contracts in relation to the underlying commodity being hedged, and we will be required to record the ineffective portion of the contracts in our net income for the respective period. This accounting treatment could result in significant fluctuations in net income and partners’ capital. Any cash settlement of the derivative instruments will be paid or received over the 21-month term of the contracts.

Results of Operations for the Year Ended December 31, 2004

The following table summarizes components of Cantera’s net margin by operating system for the year ended December 31, 2004 (dollars in millions except per Mcf data):

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Revenues of $285.5 million for 2004 consisted of:

Average realized natural gas sales prices were $5.66 per MMBtu for 2004. In addition, average realized NGL sales prices were $0.683 per gallon for 2004.

Cost of gas purchased of $240.2 million for 2004 consisted of payments to third-party producers for gas purchased under percentage of proceeds and keep whole contracts. The average purchase price for gas in 2004 was $5.01 per MMbtu.

Operating expenses were $11.8 million for the year ended December 31, 2004. Operating expenses are costs directly associated with the operations of Cantera’s assets and include direct labor and supervision, property insurance, ad valorem taxes, repair and maintenance expenses, measurement and utilities. These costs are generally fixed across broad volume ranges. The fuel expense to operate pipelines and plants is more variable in nature and is sensitive to changes in volume and commodity prices; however, a large portion of the fuel cost is generally borne by Cantera’s producers.

General and administrative expenses were $3.9 million for the year ended December 31, 2004. These expenses consist of Cantera’s costs to manage the assets. We expect our general and administrative expenses will differ from this amount due to staffing levels and integration costs.

Depreciation for the year ended December 31, 2004 was $6.0 million. Our depreciation and amortization expense will be significantly greater primarily due to Cantera’s acquisition price.

Capital Requirements

We anticipate that future capital requirements for our midstream business will consist of:

We believe that cash generated from our operations will be sufficient to meet our anticipated maintenance capital expenditures for our midstream business, which we estimate will be approximately $3.0 million to $4.0 million for the remainder of 2005. We anticipate that we will continue to invest significant amounts of capital to construct or acquire midstream assets. To the extent our future capital requirements exceed cash flows from operations, we expect to fund those expenditures with borrowings under our new and expanded credit facility, other debt financing or the issuance of new units.

Cash Flows

Operating Activities.    Cantera’s net cash provided by operating activities was $22.2 million for the year ended December 31, 2004. The net cash provided from operations consisted of net income of $24.1 million and non-cash items of $4.6 million, primarily consisting of depreciation, offset by decreases in working capital of $6.5 million.

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Investing Activities.    Cantera’s net cash used in investing activities was $3.9 million for the year ended December 31, 2004, which included maintenance capital expenditures of $2.9 million and an additional $1.0 million related to the original purchase of its assets from CMS Field Services, Inc. on July 2, 2003.

Financing Activities.    Cantera’s net cash used in financing activities was $18.4 million for the year ended December 31, 2004, which included $18.3 million for repayment of borrowings under an intercompany loan and $0.1 million in payments on a capital lease obligation.

Financing and Sources of Liquidity

Concurrent with the closing of the Cantera acquisition, Penn Virginia Operating Co. LLC, the parent of PVR Midstream LLC and a subsidiary of Penn Virginia Resource Partners, entered into a new unsecured $260 million, five-year credit agreement. The new credit agreement consists of a $150 million revolving credit facility and a $110 million term loan. The term loan and a portion of the revolving credit facility were used to fund the Cantera acquisition and to repay borrowing under our previous credit facility. The revolving credit facility is available for general partnership purposes, including working capital, capital expenditures and acquisitions, and includes a $10 million sublimit for the issuance of letters of credit. We have a one-time option under the revolving credit facility to increase the facility by up to $100 million upon receipt by the credit facility’s administrative agent of commitments from one or more lenders.

Proceeds received from this offering will be used to repay the $110 million term loan and a portion of the amount outstanding under the revolving credit facility. Please read “Use of Proceeds.” Once repaid, the term loan cannot be re-borrowed. In the event proceeds from this offering are not sufficient to repay the term loan, it will be payable as interest only until March 3, 2006, then will be payable in 16 equal quarterly installments plus any accrued interest.

The interest rate under the credit agreement will fluctuate based on Penn Virginia Resource Partners’ ratio of total indebtedness to EBITDA. At our option, interest shall be payable at a base rate plus an applicable margin ranging from 0.00% to 1.00% or a rate derived from the London Interbank Offering Rate plus an applicable margin ranging from 1.00% to 2.00%.

The credit agreement prohibits us from making distributions to unitholders and distributions in excess of available cash if any potential default or event of default, as defined in the credit agreement, occurs or would result from the distribution. In addition, the credit agreement contains various covenants that limit, among other things, our ability to:

The credit agreement also contains covenants requiring us to maintain:

As of December 31, 2004, we were in compliance with the covenants in the credit agreement.

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In conjunction with the closing of the Cantera acquisition, Penn Virginia Operating Co. LLC also amended its $88 million senior unsecured notes to allow us to enter the midstream natural gas business and to increase certain covenant coverage ratios, including the debt to EBITDA test. In exchange for this amendment, we agreed to a 0.25% increase in the fixed interest rate on the notes, from 5.77% to 6.02%. The amendment to the notes also requires that we obtain an annual confirmation of our credit rating, with a 1.00% increase in the interest rate payable on the notes in the event our credit rating falls below investment grade.

The notes prohibit us from making distributions to unitholders and distributions in excess of available cash if any potential default or event of default, as defined in the notes, occurs or would result from the distribution. In addition, the notes contain various covenants, including those shown below, that are similar to those contained in the credit agreement. In connection with the amendment, the debt incurrence test in the notes was converted to a maintenance test. In addition, the covenant requiring that we maintain the ratio of total debt to consolidated EBITDA was amended to provide for a ratio of not more than 3.5:1.0 of total debt to consolidated EBITDA for each of the four most recently completed fiscal quarters, which can be increased to a ratio of not more than 4.0:1.0 for a period of up to two quarters in the event an acquisition permitted by the terms of the notes causes pro forma total debt to consolidated EBITDA to exceed 3.5: 1.0 for each of the four most recently completed fiscal quarters.

As of December 31, 2004, we were in compliance with the covenants in the notes.

Contractual Obligations

We have lease commitments for various compressors that expire at various times through 2005. Total rental expense charged to operations for the year ended December 31, 2004 was $662,000 and future minimum payments at December 31, 2004 under noncancelable operating leases were $36,000.

Under various contracts, we are committed to gather and process natural gas and to transport NGLs. Such contracts are based on market prices and vary in duration from one month to nine years.

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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

As of March 7, 2005, there were 12,338,458 common units outstanding held by approximately 7,900 holders, including common units held in street name. The common units are traded on the New York Stock Exchange under the symbol PVR.

As of March 7, 2005, there were 5,737,410 subordinated units outstanding. The subordinated units are held by affiliates of our general partner and are not publicly traded.

The following table sets forth, for the periods indicated, the high and low sales prices for the common units, as reported on the New York Stock Exchange Composite Transactions Tape, and quarterly cash distributions paid to our unitholders. The last reported sale price of common units on the New York Stock Exchange on March 7, 2005 was $56.40 per unit.

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CAPITALIZATION

The following table sets forth our capitalization as of December 31, 2004 on:

Please read “Use of Proceeds.”