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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, 2003

Commission file number: 1-16735

Penn Virginia Resource Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)

Three Radnor Corporate Center, Suite 230

100 Matsonford Road

Radnor, Pennsylvania 19087

(610) 687-8900

(Address, Including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

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 8,671,213 common units held by non-affiliates of the registrant at February 26, 2004 was $297,422,606, based on the closing price of $34.30 per unit.

As of February 26, 2004, 10,425,988 common units and 7,649,880 subordinated units were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

None

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Part I

General

Penn Virginia Resource Partners, L.P. (“the Partnership”) is a Delaware limited partnership formed by Penn Virginia Corporation (“Penn Virginia”) in July 2001 to primarily engage in the business of managing coal properties in the United States. 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. As of December 31, 2003, our properties contained approximately 588 million tons of proven and probable coal reserves located on 241,000 acres in Virginia, West Virginia, New Mexico and eastern Kentucky. In 2003, our lessees produced 26.5 million tons of coal from our properties and paid us coal royalty revenues of $50.3 million. As of December 31, 2003, we leased an aggregate of approximately 90% of our reserves under 53 leases to 29 different operators who mine coal at 54 mines. We do not operate any mines. Approximately 72% of our 2003 coal royalty revenues and 99% of our 2002 coal royalty revenues were based on the higher of a percentage of the gross sales price or a fixed price per ton of coal they sell, with pre-established minimum monthly or annual rental payments. The balance of our 2003 and 2002 coal royalty revenues was derived from fixed royalty rate leases, which escalate annually, with pre-established minimum monthly payments (see “The Peabody Acquisition” below).

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. Additionally, we provide fee-based coal preparation and transportation facilities to some of our lessees to enhance their production levels and to generate additional coal services revenues.

We also earn revenues from the sale of standing timber on our properties. As of December 31, 2003, we owned approximately 114,500 surface acres of timberland containing approximately 166 million board feet of inventory. 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 2003, we sold 5.3 million board feet of timber.

In 2003, 94.4% of our revenues were attributable to our coal and land leasing operations, 3.8% of our revenues were attributable to our coal services operations and 1.8% of our revenues were attributable to our timber operations.

Acquisitions and Investments in Coal Facilities

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 $4.0 million loadout facility is designed for the high-speed loading of 150-car unit trains and became operational in January 2004. We expect this facility to generate additional revenues of approximately $0.7 million in 2004, in addition to increasing coal production from this lessee.

The Peabody Acquisition

In December 2002, we acquired two properties from Peabody Energy Corporation (“Peabody”). Central to the transaction was the purchase and leaseback of approximately 120 million tons of proven and probable coal reserves (the “Reserves”) located in New Mexico (80 million tons) and West Virginia (40 million tons) (the “Peabody Acquisition”). The transaction was an acquisition of assets, in which the Partnership did not acquire from Peabody, or its affiliates, any physical facilities, mining equipment, employees, market distribution system,

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sales force or customer base associated with the assets acquired. As a result of the Peabody Acquisition, our total proven and probable reserves increased by approximately 25% as of December 2002 and our royalty revenues increased by 45% in 2003 over 2002. All of the Reserves were leased back to subsidiaries of Peabody by the Partnership under leases containing the terms described below under “Coal Leases.”

Approximately two-thirds, or 80 million tons, of the Reserves consist of predominantly low sulfur, low BTU coal located in New Mexico (the “Lee Ranch Reserves”) and are being mined by an affiliate of Peabody at the Lee Ranch mine by a combination of the dragline and truck-and-shovel surface mining methods. For a description of the dragline and truck-and-shovel mining methods, see “Item 2. Properties—Coal Reserves and Production.” The Lee Ranch Reserves are trucked from the mine to a loading facility which blends and loads the coal via conveyor belts into railcars for delivery to Peabody’s customers. Production from the Lee Ranch mine during the year ended December 31, 2003 was 7.0 million tons which generated $9.4 million of coal royalty revenues and $1.1 million of deferred income. Production from the Lee Ranch Reserves during 2004 is expected to be between 5.3 and 6.0 million tons. We anticipate that the Lee Ranch Reserves will be exhausted in approximately 2015.

Approximately one-third, or 40 million tons, of the Reserves consist of predominantly high sulfur, high BTU coal located in northern West Virginia (the “Federal Reserves”) which are being mined by a second affiliate of Peabody (together, the “Peabody Lessees”) at the Federal No. 2 mine predominantly by the longwall underground mining method. For a description of the longwall mining method, see “Item 2. Properties—Coal Reserves and Production.” Peabody has a preparation plant located in close proximity to the Federal No. 2 mine and they load the processed coal onto railcars at a unit train loading facility for delivery to their customers. Production from the Federal No. 2 mine for the year ended December 31, 2003 was approximately 4.3 million tons which generated $4.7 million in coal royalty revenues and $0.4 million of deferred income. Production from the Federal Reserves during 2004 is expected to be between 4.2 and 4.8 million tons. We anticipate that the Federal Reserves will be exhausted in approximately 2011.

The Peabody Acquisition, which included 8,800 mineral acres, was funded with $72.5 million in cash and the issuance by the Partnership to Peabody of 1,522,325 common units and 1,240,833 class B common units. In July 2003, 241,000 Class B common units were released from escrow in exchange for certain title transfers in New Mexico. 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. As of December 31, 2003, 52,700 of the common units were being held in escrow pending Peabody acquiring and transferring to us approximately one million tons of coal reserves located in West Virginia. As a result of the units held in escrow, approximately one million tons of coal reserves and 52,700 common units were not included in property, plant and equipment or partners’ capital, respectively, at December 31, 2003. In December 2003 and January 2004, Peabody sold 1,150,000 of its common units in a public offering sponsored by the Partnership.

The Peabody Acquisition provides 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 adds additional strength and stability to our lessee group. In addition, Peabody is incentivized to source additional assets to the Partnership in the future. This incentive is derived not only from Peabody’s ownership of our common units, but also from the right to share in our general partner’s incentive distribution rights if Peabody sells us additional coal assets in the future. See “Incentive Distribution Rights.”

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 Upshur Acquisition was our first investment outside of central Appalachia. The properties, which include approximately 18,000 mineral acres, contain predominatly high sulfur, high BTU coal reserves.

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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 approximately 53 million tons of coal reserves for $33 million. In early 2002, the operator at West Coal River filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. West Coal River’s operations were subsequently idled on March 4, 2002. The operator continued to pay minimum royalties until we recovered our lease on August 31, 2002. In November 2002, we purchased various infrastructure at West Coal River, including a 900 ton per hour coal preparation plant and 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 $2.4 million in reclamation liabilities and approximately $0.6 million of stream mitigation obligations. We leased this property in May 2003 and have assigned all reclamation and mitigation liabilities to the new lessee, which 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:

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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 72% of our 2003 coal royalty revenues and 99% of our 2002 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 for the Lee Ranch Reserves and the Federal Reserves, which require the Peabody Lessees to make royalty payments to us based on fixed royalty rates per ton of coal sold, which rates escalate annually. Under the lease for the Lee Ranch Reserves (the “Lee Ranch Lease”), the initial royalty payment in 2003 was $1.50 per ton and escalates annually until it reaches $2.48 per ton on January 1, 2014. Under the lease for the Federal Reserves (the “Federal Lease” and, together with the Lee Ranch Lease, the “Peabody Leases”), the initial royalty payment in 2003 was $1.09 per ton and escalates annually until it reaches $1.75 per ton on January 1, 2010. 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. The Lee Ranch Lease and the Federal Lease require the Peabody Lessees to pay to the Partnership annual minimum rental payments of $2.0 million and $5.0 million, respectively, which are recoupable against production royalties due over the life of the applicable lease.

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 on account of 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 default by the lessee, substantially all of the leases give us the right to terminate the lease and take possession of the leased premises. In the event of a default under the Peabody Leases, Peabody is required to purchase the then remaining Federal or Lee Ranch Reserves from the Partnership at a price equal to (x) the number of tons of reserves being purchased times (y) the production royalty rate then in effect with respect to such reserves. If Peabody fails for any reason to pay such purchase price, the Partnership is then entitled to terminate the applicable Peabody Lease and reclaim the reserves leased thereunder.

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

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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% limited partner interest and the 2% 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 expects 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 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 will 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.

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 26, 2004, our Partnership structure was as follows:

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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 10—Related Party Transactions—General and Administrative—to Consolidated Financial Statements.”

Partnership Distributions

Cash Distributions

The Partnership paid cash distributions of $2.06 per common and subordinated unit for the year ended December 31, 2003. For 2004, we expect to make distributions of not less than $2.08 per common unit 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:

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%, of

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payments we make to our general partner with respect to incentive distribution rights if we purchase additional assets from Peabody in the future.

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% of the subordinated units, or up to 3,824,940 subordinated units, will convert 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 will occur if at the end of the applicable quarter each of the following three tests are met:

However, the early conversion of the second 25% of the subordinated units may not occur until at least one year following the early conversion of the first 25% of the subordinated units.

When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.

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

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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% 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, 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. The officers and directors of our general partner have significant relationships with, and responsibilities to, Penn Virginia. As a result of this relationship, 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.

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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 Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

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.

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 to have significantly larger financial and operating resources than some 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, access to transportation, environmental and government regulations, technological

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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 in order 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 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

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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 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.

• 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, but 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.

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 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. While the details of proposed initiatives to regulate air emissions vary, there is a movement toward increased regulation of emissions of pollutants from the combustion of fossil fuels, including coal. If such

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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 the 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 laws, including SMCRA and equivalent state and local laws, which obligations include reclaiming and restoring 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 to 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.

On October 23, 2003, a third lawsuit involving the disposal of coal mining overburden was filed under the name of Ohio Valley Environmental Coalition v. Bulen. In this case, which was also filed in the District Court, several public interest group plaintiffs have alleged that the Army Corps of Engineers violated the Clean Water Act (“CWA”) and other federal regulations when it issued Nationwide Permit 21, a general permit for the disposal of coal mining overburden into United States waters. This most recent suit also challenges certain individual discharge authorizations in West Virginia, including several involving the mining activities of the Partnership’s lessees. If the plaintiffs prevail in this latest lawsuit, lessees who have received authorization for discharges pursuant to Nationwide Permit 21 could be prevented from undertaking future discharges until they receive individual CWA permits, and future operations could require individual permits. Obtaining these individual permits is likely to substantially increase both the time and the costs of obtaining CWA permits for our lessees and other coal mining operators throughout the industry where any such unfavorable ruling may be applied. These increases could adversely affect our coal royalty revenues. Although the Partnership expects that any ruling for the plaintiffs would be appealed to the Fourth Circuit, the coal mining industry, including the operations of our lessees, could be significantly adversely impacted by the initial effects of an adverse decision while any appeal is pending.

• West Virginia Anti-degradation Policy. As a result of a September 2003 decision by the District Court in Ohio Valley Environmental Coalition v. Whitman, the State of West Virginia is currently implementing the CWA without an EPA-approved anti-degradation implementation policy, which would apply in cases of pollutant discharges into waters that have been designated as high quality waters by the State. In this case, the District Court vacated EPA’s previous approval of the West Virginia anti-degradation policy after 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.

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The EPA has reportedly decided not to appeal this decision and is instead proceeding with a policy review. Our lessees seek permits to discharge into high quality waters under a new policy which does not include such an exception. 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. Stringent safety and health standards have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs 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 safety and health 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 and to some survivors of a miner who has died from this disease. Since we do not operate any mines and do not employ any coal miners, we are not subject to such laws and regulations.

• 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 18 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 7. “Quantitative and Qualitative Disclosure about Market Risk” for a discussion of interest rate risk.

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, 2003. The general partner considers current employee relations to be good.

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

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Officer Code of Ethics and Audit Committee Charter, and we will provide copies of such documents to any shareholder who so requests. We also make available free of charge on or through our 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 588 million tons of proven and probable coal reserves as of December 31, 2003, we owned the mineral interests and the majority of related surface rights to 544 million tons, or 93%, and we lease the remaining 44 million tons, or 7%, from unaffiliated third parties. In addition to the revenues we receive from our coal business, we also earn revenues from the sale of timber. At December 31, 2003, we owned 114,500 surface acres of timberland containing 166 million board feet of timber inventory.

Coal Reserves and Production

As of December 31, 2003, we had approximately 588 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.

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 farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

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.

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Our lessees mine coal using both underground and surface methods. Our lessees currently operate 16 surface mines and 38 underground mines. Approximately 55% of the coal produced from our properties in 2003 came from underground mines and 45% came from surface mines. Most of our lessees use the continuous mining method in all of the 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 from transportation entries 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 subsidence 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 use 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. Shovels 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 Kanawha River, 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 588.2 million tons of proven and probable coal reserves to which we had rights as of December 31, 2003, we owned the mineral interests and the related surface rights to 396.9 million tons, or 67.5%, and we owned the mineral interests only to 147.6 million tons, or 25.1%. We lease the mineral rights to the remaining 43.7 million tons, or 7.4%, 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 2003, our expenses to third-party surface and mineral owners aggregated $2.7 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, 2003:

At December 31, 2003, 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, 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%, medium sulfur coal as coal with a sulfur content between 1.0% and 1.5% and high sulfur coal as coal with a sulfur content of greater than 1.5%. Compliance coal is that portion of low sulfur coal that meets compliance standards for Phase II of the Clean Air Act Amendments. As of December 31, 2003, approximately 32.8% of our reserves met compliance standards for Phase II of the Clean Air Act Amendments. 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, 2003.

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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, 2003, the property included 212 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, 2003, we leased 86% of the Wise property reserves pursuant to 22 separate leases. Production from the property totaled 9.3 million tons for the year ended December 31, 2003 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, 2003, the Coal River property included 201 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, a unit train loading facility and a modular coal preparation plant. 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 $4.0 million loadout facility is designed for the high-speed loading of 150-car unit trains and became operational in January 2004.

As of December 31, 2003, we leased 86% of the Coal River property reserves pursuant to 11 leases. Production from the property totaled 3.9 million tons for the year ended December 31, 2003 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, 2003, the New Mexico property included approximately 73 million tons of proven and probable coal reserves

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As of December 31, 2003, we leased all of the New Mexico property reserves to Peabody. Production from the property totaled 6.3 million tons for the year ended December 31, 2003 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, 2003, the Northern Appalachia property included approximately 49 million tons of proven and probable coal reserves and approximately one million tons of reserves which we have not included in the total reserves in our combined and consolidated financial statements for the year ended December 31, 2003. See “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Acquisitions.”

As of December 31, 2003, we leased substantially all of the Northern Appalachia property reserves pursuant to eight leases. Production from the property totaled 5.1 million tons for the year ended December 31, 2003 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, 2003, the Spruce Laurel property included approximately 51 million tons of proven and probable coal reserves.

As of December 31, 2003, we leased all of the Spruce Laurel property reserves pursuant to eight leases. Production from the Spruce Laurel property was 1.5 million tons for the year ended December 31, 2003 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, 2003, the Buchanan property included approximately 1.7 million tons of coal reserves, all of which are low sulfur.

As of December 31, 2003, we 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, 2003 and was shipped to our lessees’ customers via the Norfolk Southern railroad and via truck.

Timber

The Partnership’s approximately 166 million board feet (“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 2003, we sold 5.3 Mbf of timber, which generated timber revenues of $1.0 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.

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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” above 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 2003.

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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 2003 and 2002, respectively, were as follows:

The quarterly cash distributions paid in 2002 and 2003 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 26, 2004, there were approximately 6,400 holders of our common units and two holders of our subordinated units.

Distributions

For the year ended December 31, 2003, the Partnership paid cash distributions of $2.06 per common and subordinated unit. For 2004, we expect to pay distributions of at least $2.08 per common unit and subordinated unit. The cash distribution paid in February 2002 was in the amount of $0.34 per unit, which amount represented the pro rata quarterly cash distribution due with respect to the time period from October 30, 2001, the closing date of the Partnership’s IPO, through December 31, 2001.

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%. See “Part I. Item 1. Business—Partnership Distributions—Incentive Distribution Rights.”

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, 2003, 2002, 2001, 2000 and 1999 and for the five years ended December 31, 2003, 2002, 2001, 2000 and 1999. 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. (the “Partnership”) should be read in conjunction with the Consolidated Financial Statements and Notes thereto.

Overview

Penn Virginia Resource Partners, L.P. (“the Partnership”) is a Delaware limited partnership formed by Penn Virginia Corporation (“Penn Virginia”) 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 three business segments: coal royalty and land leasing, coal services and timber. In 2003, 94.4% of our revenues were attributable to our coal and land leasing operations, 3.8% of our revenues were attributable to our coal services operations and 1.8% of our revenues were attributable to our timber 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, 2003, our properties contained approximately 588 million tons of proven and probable coal reserves located on 241,000 acres in Virginia, West Virginia, New Mexico and eastern Kentucky. In 2003, our lessees produced 26.5 million tons of coal from our properties and paid us coal royalty revenues of $50.3 million. As of December 31, 2003, we leased an aggregate of approximately 90% of our reserves under 53 leases to 29 different operators who mine coal at 54 mines. Approximately 72% of our 2003 coal royalty revenues and 99% of our 2002 coal royalty revenues were based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, with pre-established minimum monthly or annual rental payments. The remainder of our 2003 and 2002 coal royalty revenues were derived from fixed royalty rate leases, which escalate annually, with pre-established minimum monthly payments (see “The Peabody Acquisition” below). 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 1-3 years. During 2003, we recognized $1.7 million of minimum rental revenues.

In addition to our coal royalty revenues, we also generate coal services revenues from fees we charge to our lessees for the use of our coal preparation and transportation facilities. The facilities provide efficient methods to

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enhance lessee production levels and exploit our reserves. 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 $4.0 million (see “Bull Creek Loadout Facility” below). Our coal services revenues totaled $2.1 million for 2003. We expect the operations of the West Coal River infrastructure and the Bull Creek facility to increase coal services revenues to over $3.0 million in 2004.

We also earn revenues from the sale of standing timber on our properties. As of December 31, 2003, we owned approximately 114,500 surface acres of timberland containing approximately 166 million board feet of inventory. 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 2003, we sold 5.3 million board feet of timber.

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 588 million tons of proven and probable coal reserves to which we had rights as of December 31, 2003, we owned the mineral interests to 544 million tons and leased the mineral rights to 44 million tons. With respect to the 44 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.

2003 Performance

Our coal royalty revenues increased 60% to $50.3 million in 2003 from $31.4 million in 2002, driven by an 85% increase in coal production from our properties to 26.5 million tons in 2003 from 14.3 million tons in 2002. These increases were primarily due to the late 2002 acquisition of 120 million tons of coal from Peabody Energy Corporation (“Peabody”), with production from the Peabody Acquisition-related properties contributing 10.6 million tons in 2003, including 6.3 million tons in New Mexico and 4.3 million tons in northern Appalachia. The weighted average royalty rate received for coal produced from these properties during 2003 was $1.33 per ton. Excluding the property acquired from Peabody, production in West Virginia increased 34% due to the start up of new mining operations on our Coal River property, a lessee mining onto our property from an adjacent property in 2003 and the Upshur Acquisition (see below) in August 2002. Tonnage mined from our Virginia properties was up 3% in 2003 from 2002.

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.

In May 2003, we agreed to a new lease on our West Coal River property (formerly known as Fork Creek) with an established operator, who has over 25 years of experience as a successful miner in Appalachia.

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Production from the idled property commenced in July 2003 and is expected to increase over the next two years.

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 $4.0 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 $2.1 million in 2003 from $1.7 million in 2002, and are expected to increase to over $3.0 million in 2004. 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.

As part of our coal land management business, we own approximately 166 million board feet of standing timber. We generally sell cutting rights to various contractors who cut in advance of a mining project. Timber revenues in 2003 were $1.0 million, down from $1.6 million in 2002.

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% of fossil fuel reserves in the United States. As environmental progress continues, we are optimistic about the future of coal continuing to play a vital role in the generation of electricity. Most of our lessee’s customers are major utilities and have favorable transportation options to such 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:

However, 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 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. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.

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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.—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. Additional management has been added to assist in the evaluation of coal reserves, infrastructure and related assets as well as other appropriate assets, such as oil and gas gathering and transportation systems.

As the economic growth of the United States and the world continues and the need for clean, environmental friendly energy increases, additional output from conventional energy sources will be essential. Coal represents the vast majority of energy resources in the United States and it continues to be substantially more economical than other fossil fuel alternatives. Although coal represents about half of the nation’s electricity, coal combustion emits sulfur dioxide, nitrous oxides and carbon dioxide, all of which are considered pollutants. The challenge to the industry is to continue to reduce these emissions while remaining the fuel of choice.

Acquisitions and Investments in Coal Facilities

Capital expenditures, including noncash items, for each of the three years ended December 31, 2003 were as follows:

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 $4.0 million loadout facility is designed for the high-speed loading of 150-car unit trains and became operational in January 2004. We expect this facility to generate revenues of approximately $0.7 million in 2004.

The Peabody Acquisition

In December 2002, we acquired two properties from Peabody Energy Corporation (“Peabody”). Central to the transaction was the purchase and leaseback of approximately 120 million tons of proven and probable coal reserves (the “Reserves”) located in New Mexico (80 million tons) and West Virginia (40 million tons) (the “Peabody Acquisition”). The transaction was an acquisition of assets, in which the Partnership did not acquire from Peabody, or its affiliates, any physical facilities, mining equipment, employees, market distribution system, sales force or customer base associated with the assets acquired. As a result of the Peabody Acquisition, our total proven and probable reserves increased by approximately 25% as of December 2002 and our royalty revenues increased by 45% in 2003 over 2002. All of the Reserves were leased back to subsidiaries of Peabody by the Partnership under leases containing the terms described below under “Coal Leases.”

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Approximately two-thirds, or 80 million tons, of the Reserves consist of predominantly low sulfur, low BTU coal located in New Mexico (the “Lee Ranch Reserves”) and are being mined by an affiliate of Peabody at the Lee Ranch mine by a combination of the dragline and truck-and-shovel surface mining methods. For a description of the dragline and truck-and-shovel mining methods, see “Item 2. Properties—Coal Reserves and Production.” The Lee Ranch Reserves are trucked from the mine to a loading facility which blends and loads the coal via conveyor belts into railcars for delivery to Peabody’s customers. Production from the Lee Ranch mine during the year ended December 31, 2003 was 7.0 million tons which generated $9.4 million of coal royalty revenues and $1.1 million of deferred income. Production from the Lee Ranch Reserves during 2004 is expected to be between 5.3 and 6.0 million tons. We anticipate that the Lee Ranch Reserves will be exhausted in approximately 2015.

Approximately one-third, or 40 million tons, of the Reserves consist of predominantly high sulfur, high BTU coal located in northern West Virginia (the “Federal Reserves”) which are being mined by a second affiliate of Peabody (together, the “Peabody Lessees”) at the Federal No. 2 mine predominantly by the longwall underground mining method. For a description of the longwall mining method, see “Item 2. Properties—Coal Reserves and Production.” Peabody has a preparation plant located in close proximity to the Federal No. 2 mine and they load the processed coal onto railcars at the unit train loading facility for delivery to their customers. Production from the Federal No. 2 mine for the year ended December 31, 2003 was approximately 4.3 million tons which generated $4.7 million in coal royalty revenues and $0.4 million of deferred income. Production from the Federal Reserves during 2004 is expected to be between 4.2 and 4.8 million tons. We anticipate that the Federal Reserves will be exhausted in approximately 2011.

The Peabody Acquisition, which included 8,800 mineral acres, was funded with $72.5 million in cash and the issuance by the Partnership to Peabody of 1,522,325 common units and 1,240,833 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 our common unitholders in which were subsequently converted to common units in July 2003. In July 2003, 241,000 Class B common units were released from escrow in exchange for certain title transfers in New Mexico. As of December 31, 2003, 52,700 of the common units were being held in escrow pending Peabody acquiring and transferring to us certain of the West Virginia reserves we purchased. As a result of the units held in escrow, approximately one million tons of coal reserves and 52,700 common units were not included in property, plant and equipment or partners’ capital, respectively, at December 31, 2003. Peabody sold 1,150,000 of its common units in a public offering in December 2003 and January 2004. The Peabody Acquisition provides 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 adds additional strength and stability to our lessee group. In addition, Peabody is incentivized to source additional assets to the Partnership in the future. This incentive is derived not only from Peabody’s ownership of our common units, but also from the right to share in our general partner’s incentive distribution rights if Peabody sells us additional coal assets in the future. See “Incentive Distribution Rights.”

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 approximately 53 million tons of coal reserves for $33 million. In early 2002, the operator at West Coal River filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. West Coal River’s operations were subsequently idled on March 4, 2002. The operator continued to pay minimum royalties until we recovered our lease on August 31, 2002. In November 2002, we purchased various infrastructure at West Coal River, including a 900-ton per hour coal preparation plant and a unit-train loading facility and a railroad-granted rebate on coal loaded through the facility for $5.1 million and the assumption of approximately $2.4 million in reclamation liabilities and approximately $0.6 million of stream mitigation obligations. We leased this property in May 2003 and have assigned all reclamation and mitigation liabilities to the new lessee, which agreed to be responsible for those liabilities. The new lessee began operations in the third quarter of 2003.

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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 Upshur Acquisition was our first investment outside of central Appalachia. The properties, which include approximately 18,000 mineral acres, contain predominantly high sulfur, high BTU coal reserves.

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. In 2001, we estimated proven and probable coal reserves with the assistance of third-party mining consultants and involved the use of estimation techniques and recoverability assumptions. As a result of the independent reserve audit conducted in 2001 in connection with our initial public offering, we recorded a downward revision of our coal reserves, resulting from differences in general reserve criteria utilized by our independent engineer and the site or operator specific criteria utilized by us. Consequently, we increased our depletion rates on a prospective basis. Subsequent to 2001, proven and probable reserves have been estimated internally by our geologists. Our estimates of coal reserves are updated periodically 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 Mineral Rights. Based on the application of certain provisions of SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” the Partnership has begun to classify costs associated with the leasing of certain coal reserves as an intangible asset on the balance sheet, apart from other capitalized property costs. The amount capitalized related to a mineral right represents its fair value at the time such right was acquired less accumulated amortization. The transition provisions of SFAS No. 141 and SFAS No. 142 only require the reclassification of rights which were acquired after the June 30,2001 effective date, unless previously maintained records make it possible to reclassify rights acquired prior to that date. Prior to June 30, 2001, the Partnership did not separately allocate acquisition costs between owned mineral interests (tangible property) and leased mineral rights (intangible property), as such interests were part of the same coal seams. Accordingly, the Partnership has only classified coal mineral rights acquired after June 30, 2001 as an intangible asset in the accompanying consolidated balance sheet. The pattern in which the economic benefits of the intangibles are used cannot be reliably determined; consequently, the Partnership is amortizing the coal mineral rights using the straight-line method over an estimated useful life of 13 years.

Coal Royalties Revenues. Coal royalty revenues are recognized on the basis of tons of coal sold by our lessees and the corresponding revenues from those sales. Coal royalty revenues are accrued on a monthly basis, based on our best estimates of coal mined on our properties. Since we do not operate any coal mines, we rely on estimates made by our engineers and information obtained from our lessees to make our accruals.

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Results of Operations

Year Ended December 31, 2003 Compared With Year Ended December 31, 2002

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