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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2004

Commission file number: 1-16735

Penn Virginia Resource Partners, L.P.

Three Radnor Corporate Center, Suite 230

100 Matsonford Road

Radnor, Pennsylvania 19087

Registrant’s telephone number, including area code: (610) 687-8900

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

None

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    x

Indicate by check mark whether registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).    Yes  x    No  ¨

The aggregate market value of common units held by non-affiliates of the registrant was $327,232,978 as of June 30, 2004 (the last business day of its most recently completed second fiscal quarter), based on the last sale price of such units as quoted on the New York Stock Exchange. Shares of common units held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common units or who is otherwise believed by the Company to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of February 24, 2005, 12,338,458 common units and 5,737,410 subordinated units were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

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PENN VIRGINIA RESOURCE PARTNERS, L.P., AND SUBSIDIARIES

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Part I

General

Penn Virginia Resource Partners, L.P. (“the Partnership,” “we,” “our” or “us”) is a Delaware limited partnership formed by Penn Virginia Corporation (“Penn Virginia”) in 2001 to primarily engage in the business of managing coal properties in the United States. We conduct operations in two business segments: coal royalty and land leasing (which includes timber) and coal services (for our lessees and other third party end-users). In 2004, approximately 95 percent of our revenues were attributable to our coal royalty and land leasing operations and approximately five percent of our revenues were attributable to our coal services operations.

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. As of December 31, 2004, we had leased an aggregate of approximately 89 percent of our reserves under 55 leases to 29 different operators who mine coal at 65 mines. Approximately 79 percent of our 2004 coal royalty revenues and 72 percent 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 ton of coal mined and sold. The royalty rates under those leases escalate annually, with pre-established minimum monthly payments (see “Acquisitions and Investments—The Peabody Acquisition” below). Included in our coal royalty and land leasing segment are revenues earned from the sale of standing timber on our properties.

In our coal services segment, we generate revenues from providing fee-based coal preparation and transportation services to our lessees, which enhances their production levels and generates additional coal royalty revenues. In this segment we also earn revenues from third party end-users by owning and operating coal handling facilities through our joint venture with Massey Energy Company (see “Acquisitions and Investments—Coal Handling Joint Venture” below).

Acquisitions and Investments

The Cantera Acquisition

In November 2004, we entered into an agreement to purchase from Cantera Resources Holdings LLC (“Cantera”) a natural gas gathering and processing business with assets in Oklahoma and Texas for $191 million of cash (the “Cantera Acquisition”). Upon closing this acquisition, we will own and operate a set of midstream assets including approximately 3,400 miles of gas gathering pipelines that supply three natural gas processing facilities, which have 160 million cubic feet per day (MMcfd) of total capacity. We anticipate that the Cantera Acquisition will close in the first quarter of 2005. At closing, the Cantera Acquisition will be funded by our credit facility, which we expect to revise and expand concurrent with the closing of the acquisition. We anticipate using a combination of our credit facility and new equity capital to permanently finance this acquisition. As of December 31, 2004, we capitalized $0.7 million for costs related to the Cantera Acquisition. In order to mitigate the risk of price volatility, in January 2005, we entered into notional derivative contracts for approximately 75 percent of the net volume of natural gas liquids expected to be sold from April 2005 through December 2006. As of February 25, 2005, the derivative instruments had an aggregate fair value of $6.7 million, favorable to the counterparty. Upon closing of the Cantera Acquisition, we expect the derivative instruments to qualify as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Until closing the acquisition, the derivative instruments will not qualify for hedge accounting; thus, changes in

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the derivative instruments’ fair value prior to the closing will be recognized in earnings immediately. The fair value of the derivative instruments will change as the market prices of the underlying commodities change. Any settlement of the derivative instruments will be paid or received over the 21-month term of the contracts.

Coal Handling Joint Venture

In July 2004, we acquired from affiliates of Massey Energy Company a 50 percent interest in a joint venture formed to own and operate end-user coal handling facilities. The purchase price was $28.4 million and was funded through the Partnership’s credit facility.

The joint venture owns coal handling facilities which unload shipments and store and transfer coal for three industrial coal consumers in the chemical, paper and lime production industries located in Tennessee, Virginia and Kentucky, respectively. A combination of fixed monthly fees and per ton throughput fees is paid by those consumers under long-term leases expiring between 2007 and 2019. We recognized equity earnings of $0.4 million related to our ownership in the joint venture in 2004. We received a joint venture distribution of approximately $1.0 million during the fourth quarter of 2004 relating to third quarter operations.

Bull Creek Loadout Facility

In January 2004, we completed the construction of a new coal loadout facility for one of our lessees on our Coal River property in West Virginia. The $4.4 million loadout facility is designed for the high-speed loading of 150-car unit trains and became operational on February 1, 2004. This facility generated additional revenues of approximately $0.5 million in 2004, and we believe it resulted in increased coal production of approximately 0.4 million tons from this lessee during 2004.

The Peabody Acquisition

In December 2002, we acquired (the “Peabody Acquisition”) 120 million tons of proven and probable coal reserves (the “Reserves”) located in New Mexico (80 million tons) and West Virginia (40 million tons) from Peabody Energy Corporation (“Peabody”). All of the Reserves were leased back to subsidiaries of Peabody by the Partnership under leases containing the terms described below under “Coal Leases.” The Peabody Acquisition provided geographic diversity by exposing us to new markets in the western United States and in northern Appalachia. The inclusion of Peabody as a significant part of our lessee mix added strength and stability to our lessee group. The acquisition was funded with $72.5 million of cash, 1.53 million common units and 1.23 million class B common units. All of the Class B common units were converted into common units in accordance with their terms, upon the approval of PVR common unitholders in July 2003. In December 2003 and January 2004, Peabody sold 1.15 million of its common units in public offerings sponsored by the Partnership, and, as of December 31, 2004, Peabody held 0.84 million common units.

The Upshur Acquisition

In August 2002, we purchased approximately 16 million tons of proven and probable coal reserves located on the Upshur properties in northern Appalachia for $12.3 million (the “Upshur Acquisition”). The properties, which include approximately 18,000 mineral acres, contain predominantly high sulfur, high BTU coal reserves.

The West Coal River Acquisition

In May 2001, we acquired the Fork Creek property in West Virginia, which we now refer to as our West Coal River property, by purchasing from and leasing back to the operator approximately 53 million tons of coal reserves for $33 million. After this acquisition, the operator filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code, and, in November 2002, we purchased through the bankruptcy proceeding various infrastructure at West Coal River, including a 900 ton per hour coal preparation plant, a unit train loading facility

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and a railroad-granted rebate on coal loaded through the facility for $5.1 million plus the assumption of approximately $3.0 million in reclamation and stream mitigation obligations. We leased this property to another operator in May 2003 and have assigned all reclamation and mitigation liabilities to the new lessee, which has agreed to be responsible for those liabilities. The new lessee began operations in the third quarter of 2003.

Business Strategy

Our principal business strategies are to:

Coal Leases

The Partnership earns most of its coal royalty revenues under long-term leases that generally require our lessees to make royalty payments to us based on the higher of a percentage of the gross sales price or a fixed price per ton of coal they sell. Approximately 79 percent of our 2004 coal royalty revenues and 72 percent of our 2003 coal royalty revenues were collected under this type of variable rate lease. The balance of our coal royalty revenues are earned under two long term leases with affiliates of Peabody that require the lessees to make royalty payments to us based on fixed royalty rates which escalate annually through 2014. A typical lease either expires upon exhaustion of the leased reserves, which is the case with the two Peabody leases, or has a five to ten-year base term, with the lessee having an option to extend the lease for at least five years after the expiration of the base term.

Substantially all of our leases require the lessee to pay minimum rental payments in monthly or annual installments, even if no mining activities are ongoing. These minimum rentals are recoupable, usually over a period from one to three years from the time of payment, against the production royalties owed to the Partnership once coal production commences.

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In addition to the terms described above, substantially all of our leases impose obligations on the lessees to diligently mine the leased coal using modern mining techniques, indemnify us for any damages we incur in connection with the lessee’s mining operations, including any damages we may incur due to our lessee’s failure to fulfill reclamation or other environmental obligations, conduct mining operations in compliance with all applicable laws, obtain our written consent prior to assigning the lease, and maintain commercially reasonable amounts of general liability and other insurance. Substantially all of the leases grant us the right to review all lessee mining plans and maps, enter the leased premises to examine mine workings and conduct audits of lessees’ compliance with lease terms. In the event of a default by a lessee, substantially all of the leases give us the right to terminate the lease and take possession of the leased premises.

Ownership by and Relationship with Penn Virginia Corporation

One of the Partnership’s attributes is its relationship with Penn Virginia, a publicly held energy company based in Radnor, Pennsylvania. Penn Virginia has been engaged in the coal royalty business since 1882 and is also engaged in the exploration, development and production of oil and natural gas. Penn Virginia formed the Partnership in July 2001 to own and operate substantially all of the assets and assume the liabilities relating to Penn Virginia’s coal land management business. The Partnership completed its initial public offering (the “IPO”) of 7,475,000 common units at a price of $21.00 per unit on October 30, 2001. Penn Virginia has a significant interest in the Partnership through its indirect ownership of a 42 percent limited partner interest and the two percent sole general partner interest in us.

Penn Virginia has a history of successfully completing energy acquisitions. The Partnership pursues acquisitions independently and has the opportunity to participate jointly with Penn Virginia in reviewing potential acquisitions. These may include acquisitions of properties containing multiple natural resources, such as oil, natural gas, coal and timber as well as infrastructure related to those resources such as natural gas gathering systems and coal preparation plants and loading facilities. The Partnership would expect to retain all coal reserves and related infrastructure, all timber resources and all natural gas gathering systems acquired in any such joint acquisition and to allocate the remaining purchased assets between the Partnership and Penn Virginia as appropriate after considering each entity’s characteristics and strategies. We expect that our ability to participate in potential acquisitions with, and our access to the experienced management team and industry contacts of, Penn Virginia will benefit us.

Our partnership agreement provides that our general partner, which is an indirect wholly owned subsidiary of Penn Virginia, is restricted by agreement from engaging in any coal-related business activities other than those incidental to its ownership of interests in us. Under an omnibus agreement we entered into with Penn Virginia and our general partner concurrently with the closing of our IPO, Penn Virginia agreed, and caused its controlled affiliates to agree, not to engage in the businesses of (i) owning, mining, processing, marketing or transporting coal, (ii) owning, acquiring or leasing coal reserves or (iii) growing, harvesting or selling timber unless it first offers us the opportunity to acquire such businesses or assets and the board of directors of the general partner, with the concurrence of its conflicts committee, elects to cause us not to pursue such opportunity or acquisition. This restriction did not apply to the assets and businesses retained by Penn Virginia at the closing of the IPO. Under the omnibus agreement, Penn Virginia will be able to purchase any business which includes the purchase of coal reserves, timber and/or infrastructure relating to the production or transportation of coal if the majority value of such business is not derived from owning, mining, processing, marketing or transporting coal or growing, harvesting or selling timber. If Penn Virginia makes any such acquisition, it must offer us the opportunity to purchase the coal reserves, timber and/or related infrastructure following the acquisition.

Concurrently with the closing of the IPO, Penn Virginia also agreed to indemnify us through October 2006 for certain pre-existing tax and environmental liabilities of up to $10 million.

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Partnership Structure and Management

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our subsidiaries through an operating company, Penn Virginia Operating Co., LLC (the “Operating Company”). At February 24, 2005, our Partnership structure was as follows:

Our general partner and its affiliates are entitled to distributions on the general partner interest and on any common units and subordinated units they hold. Additionally, our general partner is entitled to distributions on its incentive distribution rights. Our general partner has sole responsibility for conducting our business and for managing our operations. Our general partner will not receive any management fee or other compensation in connection with its management of our business, but will be entitled to be reimbursed for all direct and indirect expenses incurred on our behalf. See Note 11, “Related Party Transactions—General and Administrative,” in the Notes to Consolidated Financial Statements.

Partnership Distributions

Cash Distributions

We paid cash distributions of $2.12 per common and subordinated unit during the year ended December 31, 2004. For 2005, we expect to make quarterly distributions of $0.5625 ($2.25 annual) or more per common and subordinated unit.

Incentive Distribution Rights

In accordance with the partnership agreement, incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. The minimum quarterly distribution is $0.50 per unit ($2.00 per unit on an annual basis). Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest to an affiliate (other than an individual) or to another entity as part of the merger or consolidation of our general partner with or into such entity or the transfer of all or substantially all of our general partner’s assets to another entity without the prior approval of our unitholders if the transferee agrees to be bound by the provisions of our partnership agreement. Prior to September 30, 2011, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units and subordinated units, voting as separate classes. On or after September 30, 2011, the incentive distribution rights will be freely transferable.

If for any quarter:

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

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution on the common units. In conjunction with the Peabody Acquisition, our general partner issued a special membership interest which entitles Peabody to receive increased percentages, starting at zero and increasing up to 40 percent, of payments we make to our general partner with respect to incentive distribution rights if we purchase additional assets from Peabody in the future. We have not purchased any additional assets from Peabody since closing the Peabody Acquisition in December 2002.

Subordination Period. During the subordination period, which we describe below, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution, plus arrearages in the payment of any minimum quarterly distribution from prior quarters, before any distributions of available cash from operating surplus can be made on the subordinated units.

Definition of Subordination Period. The subordination period will continue until the first day of any quarter beginning after September 30, 2006, in which each of the following events occur:

Early Conversion of Subordinated Units. Before the end of the subordination period, 50 percent of the subordinated units, or up to 3,824,940 subordinated units were eligible for conversion into common units on a one-for-one basis immediately after the distribution of available cash to partners in respect of any quarter ending on or after:

The early conversions occur if at the end of the applicable quarter each of the following three tests are met:

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Because we met these financial tests at September 30, 2004, 25 percent of the subordinated units converted to common units on November 12, 2004.

Subordinated Units

The subordinated units are a separate class of limited partner interests in our partnership, and the rights of holders of subordinated units to participate in distributions to limited partners differ from, and are subordinated to, the rights of the holders of common units as set forth above under “Partnership Distributions—Subordination Period.” If we liquidate during the subordination period, in some circumstances, holders of outstanding common units will be entitled to receive more per unit in liquidating distributions than holders of outstanding subordinated units. The per unit difference will be dependent upon the amount of gain or loss recognized by us in liquidating our assets. Following conversion of the subordinated units into common units, all units will be treated the same upon liquidation of our partnership. Holders of subordinated units will sometimes vote as a single class together with the holders of common units and sometimes vote as a class separate from the holders of common units and, as in the case of holders of common units, will have very limited voting rights. During the subordination period, common units and subordinated units each vote separately as a class on the following matters:

The subordinated units are not entitled to vote on approval of the withdrawal of our general partner or the transfer by our general partner of its general partner interest or incentive distribution rights. Removal of our general partner requires:

Under our partnership agreement, our general partner generally will be permitted to effect amendments to our partnership agreement that do not materially adversely affect unitholders without the approval of any unitholders.

Limited Call Right

If at any time persons other than our general partner and its affiliates do not own more than 20 percent of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then current market price of the common units.

Certain Conflicts of Interest

Our general partner has a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates in state statutes and judicial decisions and is commonly referred to as a “fiduciary” duty. However,

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because our general partner is an indirect, wholly owned subsidiary of Penn Virginia, our general partner’s officers and directors also have fiduciary duties to manage our general partner’s business in a manner beneficial to shareholders of Penn Virginia. Certain officers and directors of our general partner have significant relationships with, and responsibilities to, Penn Virginia. As a result of these relationships, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, on the other hand.

In connection with the Peabody Acquisition, Peabody designated one director to serve on the Board of Directors of our general partner. This director has fiduciary duties to Peabody as well as those he has to the Partnership and our general partner as a director of our general partner. Conflicts of interest may arise for this designee as a result of these relationships.

Limits on Fiduciary Responsibilities

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

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

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

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

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

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

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Competition

The coal industry is intensely competitive primarily as a result of the existence of numerous producers. Our lessees compete with coal producers in various regions of the United States for domestic sales. The industry has undergone significant consolidation which has led to some of the competitors of our lessees having significantly larger financial and operating resources than most of our lessees. Our lessees primarily compete with both large and small producers in Appalachia as well as in the western United States. Our lessees compete on the basis of coal price at the mine, coal quality (including sulfur content), transportation cost from the mine to the customer and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain are also affected by demand for electricity, demand for metallurgical coal, access to transportation, environmental and government regulations, technological developments and the availability and price of alternative fuel supplies, including nuclear, natural gas, oil and hydroelectric power. Demand for our low sulfur coal and the prices our lessees will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances which permit the high sulfur coal to meet federal Clean Air Act requirements.

Risks Inherent in Our Business

Our business involves several inherent risks. These risks include:

Business Related Risks

Regulatory and Legal Risks

General Regulation. Our lessees are obligated to conduct mining operations in compliance with all applicable federal, state and local laws and regulations. These laws and regulations include matters involving the

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discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation and restoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining, water pollution, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife protection, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws and management of electrical equipment containing polychlorinated biphenyls, or PCBs. Because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, we do not believe violations by our lessees can be eliminated completely. However, none of the violations to date, or the monetary penalties assessed, have been material to us or, to our knowledge, to our lessees. We do not currently expect that future compliance will have a material adverse effect on us.

While it is not possible to quantify the costs of compliance by our lessees with all applicable federal and state laws, those costs have been and are expected to continue to be significant. The lessees post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. We do not accrue for such costs because our lessees are contractually liable for all costs relating to their mining operations, including the costs of reclamation and mine closure. However, we do require some smaller lessees to deposit into escrow certain funds for reclamation and mine closure costs or post performance bonds for these costs. Although the lessees typically accrue adequate amounts for these costs, their future operating results would be adversely affected if they later determined these accruals to be insufficient. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.

In addition, the utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities which could affect demand for coal mined by our lessees. The possibility exists that new legislation or regulations may be adopted which may have a significant impact on the mining operations of our lessees or their customers’ ability to use coal and may require us, our lessees or their customers to change operations significantly or incur substantial costs.

Clean Air Act. The Clean Air Act affects the end-users of coal and could significantly affect the demand for our coal and reduce our coal royalty revenues. The Clean Air Act and corresponding state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides and other compounds emitted from industrial boilers and power plants, including those that use our coal. These regulations together constitute a significant burden on coal customers and stricter regulation could further adversely impact the demand for and price of our coal, resulting in lower coal royalty revenues.

In July 1997, the U.S. Environmental Protection Agency (the “EPA”) adopted more stringent ambient air quality standards for particulate matter and ozone. Particulate matter includes small particles that are emitted during the combustion process. Nitrogen oxides are naturally occurring byproducts of coal combustion that lead to the formation of ozone. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA’s position, although it remanded the EPA’s ozone implementation policy for further consideration. Details regarding the new particulate standard itself are still subject to judicial challenge. These ozone restrictions will require electric power generators to further reduce nitrogen oxide emissions. Further reduction in the amount of particulate matter that may be emitted by power plants could also result in reduced coal consumption by electric power generators. Future regulations regarding ozone, particulate matter and other ambient air standards could restrict the market for coal and the development of new mines by our lessees. This in turn may result in decreased production by our lessees and a corresponding decrease in our coal royalty revenues.

The Clean Air Act also imposes standards on sources of hazardous air pollutants. These standards have not yet been extended to coal mining operations. However, on January 30, 2004, the EPA proposed regulations to control emissions of mercury, a hazardous air pollutant, from power plants that combust coal, as well as nitrogen oxides and sulfur dioxide, which are also power plant pollutants, in 29 states. Like other environmental regulations, these standards and future standards could result in a decreased demand for coal.

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In addition to EPA proposals, various members of Congress have proposed so-called multi-pollutant bills, which could regulate nitrogen oxides, sulfur dioxide and other emissions, including carbon dioxide, from power plants that combust coal, and the regulation of greenhouse gases that might contribute to global warming could occur either pursuant to regulatory changes under the Clean Air Act, regulations by states or future U.S. treaty obligations. Moreover, a number of states have proposed to regulate emissions of mercury and are proposing in some cases to set limits on emissions of carbon dioxide and in other cases to implement a cap and trade program to reduce emissions of carbon dioxide. The uncertainty about the regulation of mercury and carbon dioxide in particular is substantial, as a number of lawsuits have been filed challenging both proposals by EPA for a cap-and trade program for mercury and EPA’s conclusion that carbon dioxide is not covered by the Clean Air Act. While the details of proposed initiatives to regulate air emissions vary, and the outcome of the legislative, regulatory and judicial disputes cannot be resolved, there is certainly a movement toward increased regulation of emissions of pollutants from the combustion of fossil fuels, including coal. If such initiatives are enacted into law, power plants could choose to shift away from coal as a fuel source to meet these requirements.

Surface Mining Control and Reclamation Act of 1977. The Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) and similar state statutes impose on mine operators the responsibility of restoring the land to its original state and compensating the landowner for types of damages occurring as a result of mining operations, and require mine operators to post performance bonds to ensure compliance with any reclamation obligations. Regulatory authorities may attempt to assign the liabilities of our lessees to us if any of our lessees are not financially capable of fulfilling those obligations. In conjunction with mining the property, our lessees are contractually obligated under the terms of their leases to comply with all state and local laws, including SMCRA, with obligations including the reclamation and restoration of the mined areas by grading, shaping and reseeding the soil. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan.

CERCLA. We could become liable under federal and state Superfund and waste management statutes if our lessees are unable to pay environmental cleanup costs. The Comprehensive Environmental Response, Compensation and Liability Act, known as CERCLA or “Superfund,” and similar state laws create liabilities for the investigation and remediation of releases and threatened releases of hazardous substances into the environment and damages to natural resources. As a landowner, we are potentially subject to liability for these investigation and remediation obligations.

Surface Mining Valley Fills. Over the course of the last several years, opponents of surface mining have filed three lawsuits challenging the legality of permits authorizing the construction of valley fills for the disposal of coal mining overburden under federal and state laws applicable to surface mining activities. Although two of these challenges were successful in the United States District Court for the Southern District of West Virginia (the “District Court”), the United States Court of Appeals for the Fourth Circuit overturned both of those decisions in Bragg v. Robertson in 2001 and Kentuckians for The Commonwealth V. Rivenburgh in 2003.

A ruling on July 8, 2004, which was made by the District Court in connection with a third lawsuit, may impair our lessees’ ability to obtain permits that are needed to conduct surface mining operations. In this case, Ohio Valley Environmental Coalition v. Bulen, the District Court determined that the Army Corps of Engineers (the “Corps”) violated the Clean Water Act (“the Clean Water Act”) and other federal statutes when it issued Nationwide Permit 21 (“NWP21”). This ruling is currently on appeal, but no decision has been issued by the appeals court as of yet.

In January of 2005, Kentucky Riverkeepers, Inc. and several other groups filed suit in federal district court in Kentucky challenging the legality of Nationwide Permit 21, and seeking to enjoin the Corps from issuing any general permits thereunder for fills associated with coal mining in Kentucky. Should the district court hearing this case follow the reasoning of Ohio Valley Environmental Coalition v. Bulen and similarly enjoin the Corps from issuing general permits for coal mining under that general permit, companies seeking permits under Section 404 of the Clean Water Act in Kentucky may have to file for individual permits that may result in increases in coal mining costs. We do not have a substantial amount of reserves in Kentucky and do not expect that our lessees would be affected significantly by the outcome in this case.

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West Virginia Anti-degradation Policy. A September 2003 decision by the District Court in Ohio Valley Environmental Coalition v. Whitman vacated the EPA’s approval of the State of West Virginia’s anti-degradation implementation policy, which applies to discharges into waters that have been designated as high quality waters by the State. The District Court determined that the State’s policy did not comply with the requirements of the CWA. The West Virginia anti-degradation policy had included a number of exceptions, including one for parties holding general CWA permits, from anti-degradation review requirements. The District Court ruled that this exemption and certain other provisions of the West Virginia anti-degradation policy were not consistent with the requirements of the CWA. The EPA Region III subsequently sent a letter to the West Virginia Department of Environmental Protection approving portions of its plan, denying approval of other portions pending further study, and recommending the removal of other provisions of the plan. The West Virginia Department of Environmental Protection is reportedly reviewing this letter. Our lessees seek permits to discharge into high quality waters under a new policy which does not include such an exception. As a result of this decision, permit applications will likely be required to undergo the public and intergovernmental scrutiny associated with an anti-degradation review, which may either delay the issuance or reissuance of CWA permits, require the use of more costly control measures or lead to the denial of these permits. The delay, denial or added costs of complying with these permits may increase the costs of coal production, potentially reducing our royalty revenues.

Mine Health and Safety Laws. The operations of our lessees are subject to stringent health and safety standards that have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. However, since we do not operate any mines and do not employ any coal miners, we are not subject to such laws and regulations. The Mine Health and Safety Act of 1969 resulted in increased operating costs and reduced productivity. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive health and safety standards on all mining operations. In addition, as part of the Mine Health and Safety Acts of 1969 and 1977, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease.

Mining Permits and Approvals. Numerous governmental permits or approvals are required for mining operations. In connection with obtaining these permits and approvals, our lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations.

In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically, our lessees submit the necessary permit applications between 12 and 24 months before they plan to begin mining a new area. In our experience, permits generally are approved within 12 months after a completed application is submitted. In the past, our lessees have generally obtained their mining permits without significant delay. Our lessees have obtained or applied for permits to mine a majority of the reserves that are currently planned to be mined over the next five years. Our lessees are also in the planning phase for obtaining permits for the additional reserves planned to be mined over the following five years. However, there are no assurances that they will not experience difficulty in obtaining mining permits in the future.

Timber Regulations. Our timber operations are subject to federal, state and local laws and regulations, including those related to the environment, protection of endangered species, foresting activities and health and safety. We believe we are managing our timberlands in substantial compliance with applicable federal and state regulations.

See also Item 7A, “Quantitative and Qualitative Disclosures about Market Risk,” for a discussion of interest rate risk.

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Employees and Labor Relations

We have no employees. To carry out our operations, our general partner and its affiliates employed 32 employees who directly supported our operations at December 31, 2004. The general partner considers current employee relations to be favorable.

Available Information

The Partnership’s internet address is www.pvresource.com. We make available free of charge on or through our Internet website, our Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics and Audit Committee Charter, and we will provide copies of such documents to any unitholder who so requests. We also make available free of charge on or through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, 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 Securities and Exchange Commission.

Title to Property

Of the 558 million tons of proven and probable coal reserves we controlled as of December 31, 2004, we owned the mineral interests and the majority of related surface rights to 519 million tons, or 93 percent, and we lease the remaining 39 million tons, or seven percent, from unaffiliated third parties. In addition to the royalties we receive from our coal business, we also earn revenues from the sale of timber. See the following “Timber” section. At December 31, 2004, we owned 114,500 surface acres of timberland containing 167 Mbf of timber inventory.

Coal Reserves and Production

As of December 31, 2004, we had approximately 558 million tons of proven and probable coal reserves located on 241,000 acres in Virginia, West Virginia, New Mexico and eastern Kentucky. Our reserves are located on six separate properties:

Reserves are coal tons that can be economically extracted or produced at the time of determination considering legal, economic and technical limitations. All of the estimates of our reserves are classified as proven and probable reserves. Proven and probable reserves are defined as follows:

Proven Reserves—Proven reserves are reserves for which: (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling; and (b) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined, that the size, shape, depth and mineral content of reserves are well-established.

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Probable Reserves—Probable reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are more widely spaced or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

In areas where geologic conditions indicate potential inconsistencies related to coal reserves, we perform additional exploration to ensure the continuity and mineability of the coal reserves. Consequently, sampling in those areas involves drill holes or channel samples that are spaced closer together than those distances cited above.

Our lessees mine coal using both underground and surface methods. Our lessees currently operate 24 surface mines and 41 underground mines. Approximately 64 percent of the coal produced from our properties in 2004 came from underground mines and 36 percent came from surface mines. Most of our lessees use the continuous mining method in all of their underground mines located on our properties. In continuous mining, main airways and transportation entries are developed and remote-controlled continuous miners extract coal from “rooms,” leaving “pillars” to support the roof. Shuttle cars transport coal to a conveyor belt for transportation to the surface. In several underground mines, our lessees use two continuous miners running at the same time, also known as a supersection, to improve productivity and reduce unit costs.

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

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

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

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The following maps show the locations of our properties.

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The following table sets forth actual coal royalty revenues we have received and the amount of minimum rentals we would have received if our lessees had not produced any coal with respect to each of our properties. Revenues in the table set forth below reflect revenues actually recognized during the period presented. Minimum rentals reflect amounts we would have been entitled to receive had no coal been mined during the periods presented. Any amounts received from minimum rentals are recorded as deferred income, and not as revenues, at the time of receipt until the payment has been recouped by the lessee or the lessee fails to meet its minimum production for certain predetermined time periods.

The following table sets forth production data and reserve information with respect to each of our six properties:

Of the 558.1 million tons of proven and probable coal reserves to which we had rights as of December 31, 2004, we owned the mineral interests and the related surface rights to 382.1 million tons, or 68.5 percent, and we owned only the mineral interests to 136.5 million tons, or 24.5 percent. We lease the mineral rights to the remaining 39.5 million tons, or 7.0 percent, from unaffiliated third parties and, in turn, sublease these reserves to our lessees. For the reserves we lease from third parties, we pay royalties to the owner based on the amount of coal produced from the lease reserves. Additionally, in some instances, we purchase surface rights or otherwise compensate surface right owners for mining activities on their properties. In 2004, our expenses to third-party surface and mineral owners aggregated $6.0 million.

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The following table sets forth the coal reserves we own and lease with respect to each of our coal properties as of December 31, 2004:

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

We classify low sulfur coal as coal with a sulfur content of less than 1.0 percent, medium sulfur coal as coal with a sulfur content between 1.0 percent and 1.5 percent and high sulfur coal as coal with a sulfur content of greater than 1.5 percent. Compliance coal is that portion of low sulfur coal that meets compliance standards for the Clean Air Act. As of December 31, 2004, approximately 31.8 percent of our reserves met compliance standards for the Clean Air Act. There were no compliance reserves in the reserves acquired in the Peabody Acquisition. The following table sets forth our estimate of the sulfur content and the typical clean coal quality of our recoverable coal reserves at December 31, 2004.

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The following table shows the reserves we lease to mine operators by property.

The Wise Property

The Wise property consists of 103,000 acres located in Wise and Lee Counties, Virginia, and Letcher and Harlan Counties, Kentucky. We own 66,000 acres in fee and own the mineral interests in an additional 37,000 acres. We first acquired the majority of this property in 1882, and the first lease entered into with a lessee for a portion of this property was in 1902. As of December 31, 2004, the property included 204 million tons of coal reserves and related infrastructure, including a unit train loadout facility capable of loading 4,500 tons of coal per hour that can sample, blend and load coal into unit trains of up to 108 railcars within a four-hour period.

As of December 31, 2004, we had leased 81.5 percent of the Wise property reserves pursuant to 26 separate leases. Production from the property totaled 10.0 million tons for the year ended December 31, 2004, and was shipped to our lessees’ customers via truck, the Norfolk Southern railroad and the CSX railroad.

The Coal River Property

The Coal River property consists of 84,000 acres located in Boone, Fayette, Kanawha, Lincoln and Raleigh Counties, West Virginia. We own 53,000 acres in fee, the mineral interests to 19,000 acres and lease 12,000 acres from third parties. We acquired rights to this property pursuant to four acquisitions between 1996 and 2002, and the first lease we entered into with a lessee for this property was in 1996. As of December 31, 2004, the Coal River property included 194 million tons of proven and probable coal reserves in West Virginia and related infrastructure and other assets, including a coal loading dock on the Kanawha River, a 900-ton per hour coal preparation plant and a unit train loading facility. In January 2004, we completed the construction of a new coal loadout facility for one of our lessees on our Coal River property in West Virginia. The $4.4 million loadout facility is designed for the high-speed loading of 150-car unit trains and became operational on February 1, 2004.

As of December 31, 2004, we had leased 88.9 percent of the Coal River property reserves pursuant to nine leases. Production from the property totaled 7.8 million tons for the year ended December 31, 2004, and was shipped to our lessees’ customers via truck, barge and the CSX railroad.

The New Mexico Property

The New Mexico property consists of over 4,000 acres located in McKinley County, New Mexico. We acquired the mineral interests to this property in December 2002 in connection with the Peabody Acquisition. As of December 31, 2004, the New Mexico property included approximately 68 million tons of proven and probable coal reserves.

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As of December 31, 2004, we had leased all of the New Mexico property reserves to Peabody. Production from the property totaled 5.5 million tons for the year ended December 31, 2004, and was shipped to our lessee’s customers via the Burlington Northern Santa Fe railroad.

The Northern Appalachia Property

The Northern Appalachia property consists of over 18,000 acres of mineral interests located in Barbour, Harrison, Lewis, Monongalia and Upshur Counties, West Virginia. We acquired the mineral interests to this property through the Upshur Acquisition in August 2002 and the Peabody Acquisition in December 2002. As of December 31, 2004, the Northern Appalachia property included approximately 44 million tons of proven and probable coal reserves.

As of December 31, 2004, we had leased substantially all of the Northern Appalachia property reserves pursuant to eight leases. Production from the property totaled 5.6 million tons for the year ended December 31, 2004, and was shipped to our lessees’ customers via truck, barge and the CSX and Norfolk Southern railroads.

The Spruce Laurel Property

The Spruce Laurel property consists of 12,000 acres located in Boone and Logan Counties, West Virginia. We own 10,000 acres in fee and lease 2,000 acres from third parties. We first acquired the rights to this property in 1963. As of December 31, 2004, the Spruce Laurel property included approximately 46 million tons of proven and probable coal reserves.

As of December 31, 2004, we had leased all of the Spruce Laurel property reserves pursuant to eight leases. Production from the Spruce Laurel property was 1.9 million tons for the year ended December 31, 2004, and was shipped to our lessees’ customers via a belt line and the CSX railroad.

The Buchanan Property

The Buchanan property consists of 20,000 acres located in Buchanan County, Virginia. We own the mineral interests to 6,500 acres, and we lease the mineral rights to 13,400 acres from third parties. We first acquired the rights to this property in 1997. As of December 31, 2004, the Buchanan property included approximately 1.3 million tons of coal reserves.

As of December 31, 2004, we had leased all of the Buchanan property reserves pursuant to three leases. Production from the Buchanan property was 0.4 million tons for the year ended December 31, 2004, and was shipped to our lessees’ customers via the Norfolk Southern railroad and via truck.

Timber

The Partnership’s approximately 167 Mbf of timber inventory only includes timber that can be harvested and is greater than 12 inches in diameter. Our timberlands are located on our Wise, Spruce Laurel and Coal River properties and contain various hardwood species, including red oak, white oak, yellow poplar and black cherry. In 2004, we sold 2.6 Mbf of timber, which generated timber revenues of $0.7 million. Timber is sold in a competitive bid process involving sales of standing timber on individual parcels and, from time to time, on a contract basis where independent contractors harvest and sell the timber. Timber revenues are recognized when the timber has been sold or harvested by the independent contractors. Title and risk of loss pass to the independent contractors upon the execution of the contract. In addition, if the contractors do not harvest the timber within the specified time period, the title of the timber reverts back to the Partnership with no refund of original payment.

Coal Preparation and Transloading Facilities

In our coal services segment, we generate revenues from fees we charge to our lessees for the use of our coal preparation and transloading facilities. The facilities provide efficient methods to enhance lessee production

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levels and exploit our reserves. Historically, the majority of these fees have been generated by our unit train loadout facility on our Wise property, which accommodates 108 car unit trains that can be loaded in approximately four hours. Some of our lessees utilize the unit train loadout facility to reduce the delivery costs incurred by their customers. The coal service facility we purchased in November 2002 on our West Coal River property in West Virginia (formerly referred to as “Fork Creek”) began operations late in the third quarter of 2003. In the first quarter of 2004, we placed into service a newly constructed coal loadout facility for another lessee in West Virginia for $4.4 million.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. See Item 1, “Business, Risks Inherent in Our Business,” for a more detailed discussion of our material environmental obligations.

There were no matters submitted to a vote of security holders during the fourth quarter of 2004.

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Part II

Market Information

Our common units are listed on the New York Stock Exchange, Inc. (the “Exchange”) under the symbol “PVR.” The high and low sales prices (composite transactions) in 2004 and 2003, respectively, were as follows:

The quarterly cash distributions paid in 2003 and 2004 were as follows:

We issued subordinated units in October 2001, all of which are held by two affiliates of our general partner. There is no established public trading market for these units.

Equity Holders

As of February 24, 2005, there were approximately 8,000 holders of our common units and two holders of our subordinated units.

Distributions

For the year ended December 31, 2004, the Partnership paid cash distributions of $2.12 per common and subordinated unit. For 2005, we expect to pay distributions of at least $2.25 per common unit and subordinated unit.

If cash distributions per unit exceed $0.55 in any quarter, our general partner will receive a higher percentage of the cash we distribute in excess of that amount in increasing percentages up to 50 percent. See Item 1, “Business, Partnership Distributions, Incentive Distribution Rights.” The board of directors has declared a cash distribution payable in February 2005 for the fourth quarter of 2004 of $0.5625 per unit, exceeding the $0.55 threshold.

There is no guarantee that we will pay quarterly cash distributions on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default under our credit facility. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

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On October 30, 2001, the Partnership completed its initial public offering whereby the Partnership became the successor to the business of the Penn Virginia Coal Business (predecessor). For the purposes of this selected financial data, the Partnership refers to the Penn Virginia Coal Business for the periods prior to October 30, 2001, and to Penn Virginia Resource Partners, L.P. for the periods subsequent to October 30, 2001. The following selected historical financial information was derived from the financial statements of the Partnership as of December 31, 2004, 2003, 2002, 2001 and 2000, and for the five years then ended. The selected financial data should be read in conjunction with the combined financial statements, including the notes thereto, and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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The following review of the financial condition and results of operations of Penn Virginia Resource Partners, L.P. should be read in conjunction with the Consolidated Financial Statements and Notes thereto.

Overview

Penn Virginia Resource Partners, L.P. is a Delaware limited partnership formed by Penn Virginia Corporation in 2001 to primarily engage in the business of managing coal properties and related assets in the United States. Penn Virginia contributed its coal properties and related assets to the Partnership and, effective with the closing of its initial public offering in October 2001, our common units began trading publicly on the New York Stock Exchange.

Both in our current limited partnership form and in our previous corporate form, we have managed coal properties since 1882. We conduct operations in two business segments: coal royalty and land leasing (which includes timber), and coal services (for lessees and other third-party end-users). In 2004, approximately 95 percent of our revenues were attributable to our coal royalty and land leasing operations and approximately five percent of our revenues were attributable to our coal services operations.

Our coal reserves, coal infrastructure and timber assets are located on the following six properties:

In our coal royalty and land leasing operations, we enter into long-term leases with experienced, third-party mine operators for 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. As of December 31, 2004, we leased an aggregate of approximately 89 percent of our reserves under 55 leases to 29 different operators who mine coal at 65 mines. Approximately 79 percent of our 2004 coal royalty revenues and 72 percent of our 2003 coal royalty revenues were based on the higher of a percentage of the gross sales price or a fixed price per ton of coal our lessees sell, with pre-established minimum monthly or annual rental payments. The balance of our 2004 and 2003 coal royalty revenues was derived from fixed royalty rate leases, which escalate annually, with pre-established minimum monthly payments (see “Acquisitions and Investments—The Peabody Acquisition” following). In managing our properties, we actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We also derive revenues from minimum rental payments. Minimum rental payments are initially deferred and are recognized as minimum rental revenues when our lessees fail to meet specified production levels for certain predetermined periods. The recoupment period on most of our leases generally ranges from one to three years. During 2004, we recognized $0.8 million of minimum rental revenues.

Included in our coal royalty and land leasing segment are revenues earned from the sale of standing timber on our properties. As of December 31, 2004, we owned approximately 114,500 surface acres of timberland

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containing approximately 167 Mbf of inventory. In 2004, we sold 2.6 Mbf of timber, which generated revenues of $0.7 million. The timber revenues we receive are dependent on harvest levels and the species and quality of timber harvested. Our harvest levels in any given year will depend upon a number of factors, including anticipated mining activity, timber maturation and market conditions. Any timber, which would otherwise be removed due to lessee mining operations, is harvested in advance to prevent loss of the resource.

In our coal services segment, we generate revenues from providing fee-based coal preparation and transportation services to our lessees which enhances their production levels and generates additional coal royalty revenues, and through our coal handling facility joint venture with Massey Energy Company (see “Acquisitions and Investments—Coal Handling Joint Venture”). Historically, the majority of these fees have been generated by our unit train loadout facility, which accommodates 108 car unit trains that can be loaded in approximately four hours. Some of our lessees utilize the unit train loadout facility to reduce the delivery costs incurred by their customers. The coal service facility we purchased in November 2002 on our West Coal River property in West Virginia (formerly referred to as “Fork Creek”) began operations late in the third quarter of 2003. In addition, we completed construction of a coal loadout facility for another lessee in West Virginia for $4.4 million in February 2004 (see “Bull Creek Loadout Facility” following). Our coal services revenues totaled $3.4 million for 2004. We expect the operations of the West Coal River infrastructure and the Bull Creek facility to increase coal services revenues to over $4.1 million in 2005.

We account for our investment in the coal handling joint venture with Massey Energy under the equity method of accounting. In 2004, the original cash investment of $28.4 million was capitalized. In accordance with the equity method, we recognized equity earnings of $0.4 million in 2004 with a corresponding increase in the investment. We received cash distributions of approximately $1.0 million from the joint venture in 2004 which were recorded as a reduction of the investment.

Our revenues and the profitability of our coal royalty and land leasing operations are largely dependent on the production of coal from our reserves by our lessees. The coal royalty revenues we receive are affected by changes in coal prices and our lessees’ supply contracts and, to a lesser extent, by fluctuations in the spot market prices for coal. The prevailing price for coal depends on a number of factors, including demand, the price and availability of alternative fuels, overall economic conditions and governmental regulations.

Royalty expenses that we incur in our coal business consist primarily of lease payments on property which we lease from third parties and sublease to our lessees. Our lease payment obligations vary based on the production from these properties. Of the 558 million tons of proven and probable coal reserves to which we had rights as of December 31, 2004, we owned the mineral interests to 519 million tons and leased the mineral rights to 39 million tons. With respect to the 39 million tons that we lease, we are granted mining rights in exchange for per ton royalty payments. We also incur costs related to lease administration and property maintenance as well as technical and support personnel.

2004 Performance

Our coal royalty revenues increased 38 percent from $50.3 million in 2003 to $69.6 million in 2004. This increase was a result of an increase in coal production by 4.7 million tons, or 18 percent, combined with a 17 percent increase in the average gross royalties per ton from $1.90 in 2003 to $2.23 in 2004. These increases were primarily due to an increase in production at our Coal River property related to a longwall mining operation started by one of our lessees in the first quarter of 2004. This longwall operation increased production by 2.6 million tons and added $5.6 million in revenues in 2004. The addition of a mine operator and a new mine by another of our Coal River lessees contributed approximately 0.7 million tons of coal production, or $3.1 million of revenues. Increased demand drove a coal sales price increase in the region, which in turn resulted in a seven percent increase in our average gross royalty per ton on the Coal River property, from $2.42 per ton in 2003 to $2.60 per ton in 2004. Revenues at the Wise property increased by $5.9 million primarily as a result of a 19 percent increase in the average royalty rate from $2.29 per ton in 2003 to $2.72 per ton in 2004. Revenues from

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the Spruce Laurel property increased by $1.9 million, primarily the result of increased coal sales prices fueled by stronger demand in the region. The higher royalty rates received from our lessees resulted in a 23 percent increase in the average gross royalty per ton on the Spruce Laurel property, from $2.07 per ton in 2003 to $2.54 per ton in 2004.

As part of our coal land management business, we own approximately 167 Mbf of standing timber. We generally sell cutting rights to various contractors who cut in advance of a mining project. Timber revenues in 2004 were $0.7 million, down from $1.0 million in 2003.

Coal prices, especially in central Appalachia where the majority of our production is located, have increased significantly since the beginning of 2003. The price increase stems from several causes including increased electricity demand and decreasing coal production in central Appalachia.

We also collect fees and railroad rebates related to our ownership of the coal preparation plant and coal loading facility on the West Coal River property. This new facility and several smaller modular coal preparation plants are resulting in additional coal services revenues, supplementing revenues from the Shober loading facility in Virginia. We also spent approximately $4.4 million to construct a third large-scale coal loading facility on our Coal River property, which began operating in February 2004. Coal services revenues increased to $3.4 million in 2004 from $2.1 million in 2003, and are expected to increase to over $4.1 million in 2005. We believe that these types of fee-based infrastructure assets provide good investment and cash flow opportunities for the Partnership, and we continue to look for additional investments of this type as well as other primarily fee-based assets, including oil and gas midstream assets.

We were able to take advantage of other growth opportunities in 2004 by acquiring from affiliates of Massey Energy Company for $28.4 million a 50 percent interest in a joint venture formed to own and operate end-user coal handling facilities. The joint venture is pursuing additional projects to build and operate coal handing facilities for industrial customers.

In November 2004, we entered into the Cantera Acquisition agreement to purchase a natural gas gathering and processing business with assets in Oklahoma and Texas from Cantera for $191 million of cash. With the closing of this acquisition, we will own and operate a set of midstream assets including approximately 3,400 miles of gas gathering pipelines that supply three natural gas processing facilities, which have 160 MMcfd of total capacity. We anticipate the acquisition will close in the first quarter of 2005.

Economic and Industry Factors

The United States relies significantly on coal as a primary fuel source. Coal is used as a fuel source for about half of domestic electricity generation and represents approximately 85 percent of fossil fuel reserves in the United States. As environmental regulations evolve, we expect the coal industry to become increasingly environmentally friendly, and we are optimistic, therefore, that coal will continue to play a vital role in the generation of electricity. Most of our lessees have favorable transportation options to their customers, which are mostly major utilities.

We are not an operating company and do not employ any coal miners. There are several key distinctions between our coal royalty business and a coal operating business which include:

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Our lessees are obligated to conduct mining operations in compliance with all applicable federal, state and local laws and regulations. Because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, we do not believe violations by our lessees can be eliminated completely. None of our lessees’ violations to date, or the monetary penalties assessed, have had a material adverse effect on us or, to our knowledge, on our lessees. We do not currently expect that future compliance will have a material adverse effect on us.

While it is not possible to quantify the costs of compliance by our lessees with all applicable federal and state laws, those costs have been and are expected to continue to be significant. The lessees post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closings, including the cost of treating mine water discharge when necessary. We do not accrue for such costs because our lessees are contractually liable for all costs relating to their mining operations, including the costs of reclamation and mine closure. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.

In addition, the utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities which could affect demand for our lessees’ coal. The possibility exists that new legislation or regulations may be adopted which may have a significant impact on the mining operations of our lessees or their customers’ ability to use coal and may require us, our lessees or their customers to change operations significantly or incur substantial costs. See Item 1, “Business—Risks Inherent in Our Business.”

Opportunities, Challenges and Risks

Our revenues and profitability will be adversely affected in the future if we are unable to replace or increase our reserves through acquisitions. Our management continues to focus on acquisitions of assets and energy sources necessary to meet the requirements of diverse markets and environmental regulations. Personnel were added in 2003 to evaluate acquisitions of coal reserves and coal industry-related infrastructure as well as the acquisition of oil and gas mid-stream assets.

Coal is the most abundant fossil fuel energy resource in the United States, and it continues to be substantially more economical than other fossil fuel alternatives in generating electricity. Although coal represents fuel for about half of the nation’s electricity, coal combustion emits sulfur dioxide, nitrous oxides and carbon dioxide, all of which are considered pollutants. A challenge for the industry is to continue to reduce emissions while maintaining coal’s cost advantage.

Acquisitions and Investments

Capital expenditures, including noncash items, for each of the three years ended December 31, 2004, were as follows:

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The Cantera Acquisition

In November 2004, we entered into an agreement to purchase from Cantera Resources Holdings LLC a natural gas gathering and processing business with assets in Oklahoma and Texas for $191 million of cash. Upon closing this acquisition, we will own and operate a set of midstream assets including approximately 3,400 miles of gas gathering pipelines that supply three natural gas processing facilities, which have 160 MMcfd of total capacity. We anticipate that the Cantera Acquisition will close in the first quarter of 2005. At closing, the Cantera Acquisition will be funded by our credit facility, which we expect to revise and expand concurrent with the closing of the acquisition. We anticipate using a combination of our credit facility and new equity capital to permanently finance this acquisition. As of December 31, 2004, we capitalized $0.7 million for costs related to the Cantera Acquisition. In order to mitigate the risk of price volatility, in January 2005, we entered into notional derivative contracts for approximately 75 percent of the net volume of natural gas liquids expected to be sold from April 2005 through December 2006. As of February 25, 2005, the derivative instruments had an aggregate fair value of $6.7 million, favorable to the counterparty. Upon closing of the Cantera Acquisition, we expect the derivative instruments to qualify as cash flow hedges in accordance with SFAS No. 133. Until closing the acquisition, the derivative instruments will not qualify for hedge accounting; thus, changes in the derivative instruments’ fair value prior to the closing will be recognized in earnings immediately. The fair value of the derivative instruments will change as the market prices of the underlying commodities change. Any settlement of the derivative instruments will be paid or received over the 21-month term of the contracts.

Coal Handling Joint Venture

In July 2004, we acquired from affiliates of Massey Energy Company a 50 percent interest in a joint venture formed to own and operate end-user coal handling facilities. The purchase price was $28.4 million and was funded through the Partnership’s credit facility.

The joint venture owns coal handling facilities which unload shipments and store and transfer coal for three industrial coal consumers in the chemical, paper and lime production industries located in Tennessee, Virginia and Kentucky, respectively. A combination of fixed monthly fees and per ton throughput fees is paid by those consumers under long-term leases expiring between 2007 and 2019. We recognized equity earnings of $0.4 million related to our ownership in the joint venture in 2004. We received a joint venture distribution of approximately $1.0 million during the fourth quarter of 2004 relating to third quarter operations.

Bull Creek Loadout Facility

In January 2004, we completed the construction of a new coal loadout facility for one of our lessees on our Coal River property in West Virginia. The $4.4 million loadout facility is designed for the high-speed loading of 150-car unit trains and became operational on February 1, 2004, contributing $0.5 million to 2004 coal service revenues. We expect this facility to generate coal service revenues of approximately $0.5 million in 2005.

The Peabody Acquisition

In December 2002, we completed the Peabody Acquisition, acquiring 120 million tons of proven and probable coal reserves located in New Mexico (80 million tons) and West Virginia (40 million tons) from Peabody. All of these reserves were leased back to subsidiaries of Peabody by the Partnership under leases containing the terms described above (See Item 1, “Business—Coal Leases”). The Peabody Acquisition provided geographic diversity by exposing us to new markets in the western United States and in northern Appalachia. The inclusion of Peabody as a significant part of our lessee mix added strength and stability to our lessee group. The acquisition was funded with $72.5 million of cash, 1.53 million common units and 1.23 million class B common units. All of the Class B common units were converted into common units in accordance with their terms, upon the approval of PVR common unitholders in July 2003. In December 2003 and January 2004, Peabody sold 1.15 million of its common units in public offerings sponsored by the Partnership, and, as of December 31, 2004, Peabody held 0.84 million common units.

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The Upshur Acquisition

In August 2002, we completed the Upshur Acquisition, purchasing approximately 16 million tons of proven and probable coal reserves located on the Upshur properties in northern Appalachia for $12.3 million. The properties, which include approximately 18,000 mineral acres, contain predominantly high sulfur, high BTU coal reserves.

The West Coal River Acquisition

In May 2001, we acquired the Fork Creek property in West Virginia, which we now refer to as our West Coal River property, by purchasing from and leasing back to the operator approximately 53 million tons of coal reserves for $33 million. After this acquisition, the operator filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code and, in November 2002, we purchased through the bankruptcy proceeding various infrastructure at West Coal River, including a 900 ton per hour coal preparation plant, a unit train loading facility and a railroad-granted rebate on coal loaded through the facility for $5.1 million plus the assumption of approximately $3.0 million in reclamation and stream mitigation obligations. We leased this property to another operator in May 2003 and have assigned all reclamation and mitigation liabilities to the new lessee, which has agreed to be responsible for those liabilities. The new lessee began operations in the third quarter of 2003.

Critical Accounting Policies and Estimates

Depletion. Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable reserves have been estimated internally by our geologists. Our estimates of coal reserves are updated annually and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. The Partnership estimates its timber inventory using statistical information and data obtained from physical measurements, site maps, photo-types and other information gathering techniques. These estimates are updated annually and may result in adjustments of timber volumes and depletion rates, which are recognized prospectively.

Coal Royalty Revenues. Coal royalty revenues are recognized on the basis of tons of coal sold by our lessees and the corresponding revenues from those sales. Since we do not operate any coal mines, we do not have access to actual production and revenues information until approximately 30 days following the month of production. Therefore, our financial results include estimated revenues and accounts receivable for this 30-day period. Any differences between the actual amounts ultimately received and the original estimates are recorded in the period they become finalized.

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Results of Operations

The following table sets forth our revenues, operating expenses and operating statistics for the years ended December 31, 2004, 2003 and 2002.