NATURAL RESOURCE PARTNERS LP - 10-K Annual Report

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 the filing requirements for the past 90 days. Yes þ No o

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 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. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2) Yes þ No o

The aggregate value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the Common Units outstanding, for this purpose, as if they were affiliates of the registrant) was approximately $136.2 million on June 30, 2003 based on a price of $31.61 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date.

As of March 1, 2004, there were 11,353,658 Common Units outstanding and 11,353,658 Subordinated Units outstanding.

Natural Resource Partners L.P. is a limited partnership formed in April 2002, and we completed our initial public offering in October 2002. We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. As of December 31, 2003, we controlled approximately 1.6 billion tons of proven and probable coal reserves in eight states. As of December 31, 2003, our reserves were subject to 109 leases with 48 lessees. In 2003, our lessees produced 44.3 million tons of coal from our properties and our total revenues were $85.5 million. We do not operate any mines. We lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine our coal reserves in exchange for royalty payments. Our lessees are generally required to make payments to us based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, in addition to a minimum payment.

NRP (GP) LP, our general partner, has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board of directors and officers of GP Natural Resource Partners LLC makes decisions on our behalf. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. As a result, Mr. Robertson is entitled to nominate five directors, two of whom must be independent directors, to the board of directors of GP Natural Resource Partners LLC. On December 22, 2003, Arch Coal, Inc., one of the original sponsors of our partnership, sold the following interests:


	•	all of its interests in GP Natural Resource Partners LLC to Robertson Coal Management LLC;

	•	all of its interests in NRP (GP) LP, together with all of its incentive distribution rights, to NRP Investment L.P., an affiliate of the WPP Group; and

	•	4,796,920 subordinated units of Natural Resource Partners L.P. to FRC-WPP NRP Investment L.P., an affiliate of the WPP Group and First Reserve GP IX, Inc.

Arch Coal retained the right to elect two directors, one of whom must be an independent director, to the board of directors of GP Natural Resource Partners LLC for so long as Arch continues to hold at least 10% of the common units of Natural Resource Partners. In connection with the sale, the board of directors of GP Natural Resource Partners LLC was expanded to nine members, and FRC-WPP NRP Investment L.P., which is indirectly controlled by First Reserve GP IX, Inc., obtained the right to elect two directors, one of whom must be an independent director, to the board of GP Natural Resource Partners LLC.

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our subsidiaries through a wholly owned operating company, NRP (Operating) LLC. As of March 1, 2004, our partnership structure is as follows:


	•	NRP (GP) LP owns the 2% general partner interest in us, as well as 65% of the incentive distribution rights, which entitle the holder to receive a higher percentage of cash distributed in excess of $0.5625 per unit in any quarter;

	•	the WPP Group owns 25% of the incentive distribution rights;

	•	NRP Investment L.P. owns 10% of the incentive distribution rights;

	•	we own 100% of the membership interests in the operating company; and

	•	the operating company owns 100% of the membership interests in its subsidiaries: WPP LLC, ACIN LLC and WBRD LLC.

The WPP Group includes Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation and Great Northern Properties Limited Partnership, three privately held companies that are primarily engaged in owning and managing mineral properties. Corbin J. Robertson, Jr. has a significant interest in each entity comprising the WPP Group. Mr. Robertson owns the general partner of Western Pocahontas Properties Limited Partnership, 85% of the general partner of Great Northern Properties Limited Partnership and is the Chairman, Chief Executive Officer and controlling stockholder of New Gauley Coal Corporation.

The senior executives and other officers who currently manage the WPP Group assets also manage us. They are employees of Western Pocahontas Properties Limited Partnership and Quintana Minerals Corporation, a company controlled by Mr. Robertson, and they allocate varying percentages of their time to managing our operations. None of our general partner, GP Natural Resource Partners LLC, or any of their affiliates receive any management fee or other compensation in connection with the management of our business, but they are entitled to be reimbursed for all direct and indirect expenses incurred on our behalf.

Our operations headquarters are located at P.O. Box 2827, 1035 Third Avenue, Suite 300, Huntington, West Virginia 25727 and the telephone number is (304) 522-5757. Our principal executive offices are located at 601 Jefferson Street, Suite 3600, Houston, Texas 77002 and our phone number is (713) 751-7507.

BLC Properties. In January 2004, we purchased all of the mineral interests of BLC Properties LLC for $73 million. This acquisition included coal, oil and gas and other mineral rights on approximately 270,000 acres that contain approximately 176 million tons of coal reserves. We lease these reserves to eight different lessees. The transaction also included oil and gas and other mineral rights on approximately 205,000 additional acres. BLC retained a 35% non-participating royalty interest in the oil and gas and other mineral rights. The properties are located in Kentucky, Tennessee, West Virginia, Virginia and Alabama.

Eastern Kentucky Reserves. In November 2003, we acquired coal reserves and related interests in Eastern Kentucky from a number of affiliated sellers for $18.8 million. The acquisition included approximately 21 million tons of coal reserves, an additional royalty interest in approximately 8 million tons of coal reserves on contiguous property, and the right to collect a wheelage fee on 10 million tons of coal. We lease these reserves to Appalachian Fuels.

PinnOak Resources. In July 2003, we acquired approximately 79 million tons of coal reserves and an overriding royalty interest on additional coal reserves from subsidiaries of PinnOak Resources, LLC for $58 million. We lease these reserves to other subsidiaries of PinnOak Resources. The properties consist of coal reserves at two separate mine complexes: the Pinnacle mine in Pineville, West Virginia and the Oak Grove mine near Birmingham, Alabama. PinnOak Resources produces low volatile metallurgical coal from these longwall mines and has onsite preparation plants.

Alpha Natural Resources Reserves. In April 2003, we acquired approximately 295,000 mineral acres containing approximately 353 million tons of coal reserves from two subsidiaries of Alpha Natural Resources, LLC for $53.6 million. We lease most of these reserves to the two Alpha subsidiaries and seven other operators. The properties are located in Virginia adjacent to the VICC property that we acquired from El Paso Corporation in December 2002, which is operated by another subsidiary of Alpha Natural Resources, LLC.

Alpha Natural Resources Royalty Interest. In February 2003, we purchased an overriding royalty interest from a subsidiary of Alpha Natural Resources LLC for $11.9 million. The royalty interest is in coal reserves in Kentucky and Virginia that we acquired from El Paso Corporation in December 2002.

VICC/ Alpha. The VICC/ Alpha property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia. In 2003, 7.0 million tons were produced from this property. This property is a combination of property we purchased in December 2002 from El Paso Corporation and in April 2003 from Alpha Natural Resources. We lease this property to Alpha Land and Reserves, LLC Production comes from both underground and surface mines and is trucked to one of four preparation plants. Coal is shipped via both the CSX and Norfolk Southern railroads to both utility and metallurgical customers. Major customers include American Electric Power, The Southern Company, TVA, Vepco and U.S. Steel.

Evans-Laviers. The Evans-Laviers property is located in Breathitt, Floyd, Knott and Magoffin Counties, Kentucky. In 2003, 3.0 million tons were produced from this property. We lease the property to CONSOL of Kentucky Inc., a subsidiary of publicly held CONSOL Energy Inc., which operates an underground mine and contracts the operations of other mines to third-party operators. Additionally, a sublessee has a surface and a highwall mine on the property. The underground mine is on our property as well as adjacent property. The coal produced from this property is trucked to the Big Sandy River for barge transport or is transported by truck or beltline to preparation plants located on-site and on adjacent property. Coal is shipped from the preparation plants on the CSX railroad to customers such as DuPont, Virginia Electric Power, Southern Company, American Electric Power and Electric Fuels.

Lynch. The Lynch property is located in Harlan and Letcher Counties, Kentucky. In 2003, 2.9 million tons were produced from this property. We primarily lease the property to Resource Development, L.L.C., an independent coal producer. Production comes from both underground mines and surface mines. Production from the mines is transported by truck to a preparation plant on the property and is shipped primarily on the CSX railroad to utility customers such as Georgia Power and Orlando Utilities.

West Fork. The West Fork property is located in Boone County, West Virginia. In 2003, 2.8 million tons were produced from this property. We lease the property to Eastern Associated Coal Company, a subsidiary of publicly held Peabody Energy. Production from the property is from an underground mine, and the coal is transported via belt to a preparation plant on an adjacent property and shipped by CSX railroad to both utility and metallurgical customers such as Cinergy, Detroit Edison and U. S. Steel.

Eunice. The Eunice property is located in Raleigh and Boone Counties, West Virginia. In 2003, 2.6 million tons were produced from this property. We lease the property to Boone East Development Co., a subsidiary of publicly held Massey Energy Company. Boone East Development, through affiliates, conducts two operations on the property, including a surface operation and an underground longwall mine. These operations extend onto adjacent reserves and will also eventually extend onto a portion of our nearby Y&O property. Production from this operation is generally transported by beltline and processed at two preparation plants located off the property. The preparation plants ship both metallurgical and steam coal on the CSX railroad to customers such as American Electric Power, Cinergy, Louisville Gas & Electric, Virginia Electric Power, AK Steel and U.S. Steel.

Lone Mountain. The Lone Mountain property is located in Harlan County, Kentucky. In 2003, 2.5 million tons were produced from this property. We lease the property to Ark Land Company, a subsidiary of publicly held Arch Coal, Inc. Production comes from underground mines and is transported primarily by beltline to a preparation plant on adjacent property and shipped on the Norfolk Southern or CSX railroads to utility customers such as Georgia Power and the Tennessee Valley Authority.

VICC/ Kentucky Land. The VICC/ Kentucky Land property is located primarily in Perry, Leslie and Pike Counties, Kentucky. We purchased the property in December 2002 from El Paso Corporation. In 2003, 2.3 million tons were produced from this property. Coal is produced from a number of lessees and from both underground and surface mines. Coal is shipped primarily by truck and also on the CSX and Norfolk Southern railroads to customers such as Southern Company, TVA, and American Electric Power.

Hocking-Wolford/ Cummings. The Hocking-Wolford property and the Cummings property are both located in Sullivan County, Indiana. In 2003, 1.6 million tons were produced from our property. Both properties are under common lease to Black Beauty Coal Company, an affiliate of Peabody Energy. Production is currently from a surface mine, and a dragline is being moved onto the property. Coal is shipped by truck and railroad to customers such as Public Service of Indiana and Indianapolis Power and Light.

Western Energy. The Western Energy property is located in Rosebud and Treasure Counties, Montana. In 2003, 4.3 million tons were produced from our property. Western Energy Company, a subsidiary of publicly held Westmoreland Coal Company, has two coal leases on the property. Western Energy produces coal by surface dragline mining, and the coal is transported by either truck or beltline to the four-unit 2,200-megawatt Colstrip generation station located at the mine mouth. A small amount of coal is transported by truck or the Burlington Northern Santa Fe railroad to other customers.

Coal royalty businesses are principally engaged in the business of owning and managing coal reserves. As an owner of coal reserves, royalty businesses typically are not responsible for operating mines but instead enter into long-term leases with third-party coal mine operators granting them the right to mine coal reserves on the owner’s property in exchange for a royalty payment. A standard lease has a 5- to 10-year base term, with the lessee having an option to extend the lease for additional terms. Leases often include the right to renegotiate rents and royalties for the extended term.

Coal royalty revenues are affected by changes in coal prices, lessees’ supply contracts and, to a lesser extent, fluctuations in the spot market prices for coal. The prevailing price for coal depends on a number of factors, including the supply-demand relationship, the price and availability of alternative fuels, overall economic conditions and governmental regulations. In addition to their royalty obligation, lessees are often subject to pre-established minimum monthly, quarterly or annual payments. These minimum rentals reflect amounts owners are entitled to receive even if no mining activity occurred during the period. Minimum rentals are usually credited against future production royalties that are earned when coal production commences.

Because royalty businesses do not operate any mines, they do not bear ordinary operating costs and have limited direct exposure to environmental, permitting and labor risks. As operators, the lessees are subject to environmental laws, permitting requirements and other regulations adopted by various governmental authorities. In addition, the lessees generally bear all labor-related risks, including health care legacy costs, black lung benefits and workmen’s compensation costs, associated with operating the mines. Royalty businesses typically pay property taxes and then are reimbursed by the lessee for the taxes on the leased property, pursuant to the terms of the lease.

Our business is not seasonal, although at times severe winter weather can cause a short-term decrease in coal production by our lessees, due to the weather’s negative impact on production and transportation.

We have four lessees who provided more than 10% of our revenue in 2003: Alpha Natural Resources LLC, Arch Coal, Inc., Massey Energy Company and Peabody Energy Corp. Each of these companies has several different mines on our properties. While the loss of any one of these lessees would have a material adverse effect on us, we do not believe that the loss of any single mine would have a material adverse effect on us.

The following table sets forth coal royalty revenues from the properties that we own or control for the years ending December 31, 2003, 2002 and 2001. For the year ended December 31, 2001, the revenues are attributable to the properties contributed to us at the time of our initial public offering. For the year ended December 31, 2002, the revenues are attributable to both the contributed properties and the properties we

The following table sets forth production data and reserve information for the properties that we own or control for the years ending December 31, 2003, 2002, and 2001. For the year ended December 31, 2001, the production data and reserve information are attributable to the properties contributed to us at the time of our initial public offering. For the year ended December 31, 2002, the production data and reserve information are attributable to both the contributed properties and the properties we acquired in December 2002. Coal production data and reserve information for the properties in each of the following areas is as follows: Appalachia, Illinois Basin and Northern Powder River Basin.

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 coal which meets the standards of Phase II of the Clean Air Act and is that portion of low sulfur coal that, when burned, emits less than 1.2 pounds of sulfur dioxide per million Btu. As of December 31, 2003, approximately 36% of our reserves were compliance coal. Unless otherwise indicated, we present the quality of the coal throughout this Form 10-K on an as-received basis, which assumes 6% moisture for Appalachian reserves, 12% moisture for Illinois Basin reserves and 25% moisture for Northern Powder River Basin reserves. We own both steam and metallurgical coal reserves in Central and Southern Appalachia, and we own steam coal reserves in Northern Appalachia, the Illinois Basin and the Northern Powder River Basin. In 2003, approximately 22% of the coal royalty revenues from our properties were from metallurgical coal.

The following table sets forth our estimate of the sulfur content, the typical quality of our coal reserves and the type of coal in each area as of December 31, 2003.


(1)	Compliance coal meets the sulfur dioxide emission standards imposed by Phase II of the Clean Air Act without blending with other coals or using sulfur dioxide reduction technologies. Compliance coal is a subset of low sulfur coal and is, therefore, also reported within the amounts for low sulfur coal.

(2)	For purposes of this table, we have defined metallurgical coal reserves as reserves located in those seams that historically have been of sufficient quality and characteristics to be able to be used in the steel making process. Some of the reserves in the metallurgical category can also be used as steam coal.

We prepare our reserve estimate from geologic data assembled and analyzed by our staff of geologists and engineers. The geologic data is taken from thousands of drill holes, adjacent mine workings, outcrop prospect openings and other sources, including from third parties. These estimates also take into account legal, 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 geologic data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods, and other factors. Our reserves as of December 31, 2003 were estimated internally by our geologists and engineers.

For the year ended December 31, 2003, we derived less than 2% of our total revenues from oil and gas and timber. On most of the properties we own, we do not own the oil and gas or timber. Our oil and gas and timber ownership primarily consists of properties in Kentucky and Virginia, although we acquired additional acreage in connection with the BLC acquisition in January 2004.

Numerous producers in the coal industry make the industry intensely competitive. Our lessees compete with coal producers in various regions of the United States for domestic sales. The industry has undergone significant consolidation since 1976. The top ten producers have increased their share of total domestic coal production from 38% in 1976 to 69% in 2002. This consolidation has led to a number of our lessees’ parent companies having significantly larger financial and operating resources than their competitors. Our lessees compete with both large and small producers nationwide on the basis of coal price at the mine, coal quality, 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 and steel, as well as environmental and government regulations, technological developments and the availability and price of alternative fuel supplies, including nuclear, natural gas, oil and hydroelectric power.

The coal mining industry is subject to regulation by federal, state and local authorities on matters such as:


	•	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 some current and retired coal miners;

	•	air quality standards;

	•	protection of wetlands;

	•	endangered plant and wildlife protection;

	•	limitations on land use;

	•	storage of petroleum products and substances that are regarded as hazardous under applicable laws; and

	•	management of electrical equipment containing polychlorinated biphenyls, or PCBs.

In addition, the electricity generation 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. New legislation or regulations may be adopted or enforcement of existing laws could become more stringent, either of which may have a significant impact on the mining operations of our lessees or their customers’ ability to use coal. Potential regulation may require our lessees or their customers to change operations significantly or incur substantial costs.

Our lessees are obligated to conduct mining operations in compliance with all applicable federal, state and local laws and regulations. However, 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. We do not currently expect that future compliance will have a material adverse effect on us, our unitholders or our minimum quarterly distributions.

While it is not possible to quantify the expenditures incurred by our lessees to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. Our 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. Compliance with these laws substantially increases the cost of coal mining for all domestic coal producers.

Surface Mining Control and Reclamation Act. SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. 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 similar state and local laws.

SMCRA also requires our lessees to submit a bond or otherwise financially secure the performance of their reclamation obligations. The earliest a reclamation bond can be completely released is five years after reclamation is complete. In addition, the Abandoned Mine Lands Act, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. Since our lessees are responsible for these obligations and any related liabilities, we do not accrue the estimated costs of reclamation or mine closing, and we do not pay the tax described above.

Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent mine lessees and other third parties could potentially be imputed to other companies that are deemed to have “owned” or “controlled” the mine operator. Sanctions against the “owner” or “controller” are quite severe and can include civil penalties, reclamation fees and reclamation costs. We are not aware of any currently pending or asserted claims against us asserting that we “own” or “control” our lessees. We believe our lessees are generally in compliance with all operational, reclamation and closure requirements under their SMCRA permits.

West Virginia Antidegradation Policy. In January 2002, a number of environmental groups and individuals filed suit in the U.S. District Court for the Southern District of West Virginia to challenge the EPA’s approval of West Virginia’s antidegradation implementation policy. Under the federal Clean Water Act, state regulatory authorities must conduct an antidegradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality by the state. Antidegradation review involves public and intergovernmental scrutiny of permits and requires permittees to demonstrate that the proposed activities are justified in order to accommodate significant economic or social development in the area where the waters are located. In Ohio Valley Environmental Coalition v. Whitman, the court vacated the EPA’s approval of West Virginia’s antidegradation implementation policy that exempted current holders of National Pollutant Discharge Elimination System (NPDES) permits and Section 404 permits, among other parties, from the antidegradation-review process. The EPA has reportedly decided not to appeal this decision, and West Virginia is currently operating without an antidegradation policy in place while the EPA proceeds with its policy review. Our lessees are current NPDES or Section 404 permit holders that had been exempt from antidegradation review under the former policy. If the exemptions are not in place and our lessees discharge into waters that have been designated as high quality by the state, they may experience delays in the issuance or reissuance of Clean Water Act permits, or these permits may be denied. Delay in issuance of or denial of these, increases the costs of coal production, potentially reducing our royalty revenues.

Massey Energy Show Cause Order. In January 2002, the West Virginia Department of Environmental Protection entered an order finding a pattern of violations relating to water quality by Marfork Coal Company, a subsidiary of Massey Energy, and suspending its permit for operations adjacent to the Dorothy-Sarita property for 14 days. Marfork Coal filed an appeal and obtained a stay of enforcement of this order. The Surface Mining Board heard the appeal and reduced the suspension to nine days. Marfork Coal appealed this decision to the circuit court, which held a hearing on November 22, 2002. On December 23, 2002, the circuit court reversed the order of the West Virginia Department of Environmental Protection. The court found that the show cause hearing was not conducted in an impartial manner and caused a violation of Marfork Coal’s due process rights. The matter was remanded to the West Virginia Department of Environmental Protection for an impartial hearing. The West Virginia Department of Environmental Protection appealed the decision of the circuit court to the Supreme Court of West Virginia on April 9, 2003, and oral argument was held on February 10, 2004. If this show cause order is upheld, the permits issued to Massey Energy and its subsidiaries could be suspended or revoked and production could be decreased at the mines on the Dorothy-Sarita property and at the longwall mine operated by Performance Coal at the Eunice property, reducing our coal royalty revenues on that property.

Mine Health and Safety Laws. Stringent safety and health standards have been imposed on the coal mining industry 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 Act

requires payments of benefits by all businesses conducting current mining operations to coal miners with black lung and to some survivors of miners who die from this disease. Because the regulatory requirements imposed by mine worker health and safety laws are comprehensive and ongoing in nature, non-compliance cannot be eliminated completely. We believe our lessees have made all payments under the Black Lung Act and are generally in compliance with all applicable mine health and safety laws.

Clean Air Act. The federal Clean Air Act and similar state and local laws, which regulate emissions into the air, affect coal mining and processing operations primarily through permitting and emissions control requirements. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the emissions from coal-fired industrial boilers and power plants, which are the largest end-users of our coal. These regulations can take a variety of forms, as explained below.

The Clean Air Act imposes obligations on the Environmental Protection Agency, or EPA, and the states to implement regulatory programs that will lead to the attainment and maintenance of EPA-promulgated ambient air quality standards, including standards for sulfur dioxide, particulate matter, nitrogen oxides and ozone. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources to comply with these ambient air standards. Significant additional emissions control expenditures will be needed in order to meet the current national ambient air standards.

Numerous legal and regulatory actions have been initiated over the years under the Clean Air Act, the outcome of which could adversely affect coal mining and coal-fired power plants. In February 2003, legislation was introduced in Congress outlining the Bush administration’s Clear Skies Initiative, which calls for dramatic decreases in sulfur emissions from power plants. If lower emissions standards are enacted under the act, it could result in a decrease in coal demand.

In summary, the effect that a variety of Clean Air Act regulations and legal actions could have on the coal industry and thus our business cannot be predicted with certainty. We cannot assure you that future regulatory provisions will not materially adversely affect our business, financial condition or results of operations. Additionally, we have no ability to control, or specific knowledge regarding, the environmental and other regulatory compliance of purchasers of coal mined from our properties.

Clean Water Act. Section 301 of the Clean Water Act prohibits the discharge of a pollutant from a point source into navigable waters except in accordance with a permit issued under either Section 402 or Section 404 of the Clean Water Act. Navigable waters are broadly defined to include streams, even those that are not navigable in fact, and may include wetlands.

All mining operations in Appalachia generate excess material that must be placed in fills in adjacent valleys and hollows. Likewise, coal refuse disposal areas and coal processing slurry impoundments are located in valleys and hollows. Almost all of these areas contain intermittent or perennial streams, which are considered navigable waters. An operator must secure a Clean Water Act permit before filling such streams. For approximately the past twenty-five years, operators have secured Section 404 fill permits to authorize the filling of navigable waters with material from various forms of coal mining. Operators have also obtained permits under Section 404 for the construction of slurry impoundments although the use of these impoundments, including discharges from them, requires permits under Section 402. Our leases require our lessees to obtain all necessary permits required under the Clean Water Act. To our knowledge, our lessees have obtained all permits required under the Clean Water Act and equivalent state laws.

In March 2002, the Army Corps of Engineers issued Nationwide Permit 21 under Section 404 to allow mining companies to discharge into fills without obtaining individual permits under the Clean Water Act. The legality of that permitting scheme has been challenged in a lawsuit filed in October 2003 by the Ohio Valley Environmental Coalition and several other citizens groups. This lawsuit is the latest in a series of lawsuits filed in the United States District Court for the Southern District of West Virginia by citizens groups challenging the legality of various aspects of the regulatory scheme for the permitting of surface coal mining, especially mountaintop removal coal mining and valley fills. Although the first two lawsuits were successful at the district court level, the Fourth Circuit Court of Appeals overturned both decisions.

The most recent lawsuit alleges that a nationwide permit cannot lawfully be issued under Section 404 for the surface mining of coal and that the Corps of Engineers failed to comply with the requirements of the National Environmental Policy Act in the adoption of Nationwide Permit 21. If the plaintiffs are successful, the district court could enjoin further discharges pursuant to Nationwide Permit 21 at those operations that have received authorizations under that permit and could require coal miners to obtain individual permits under Section 404 of the Clean Water Act to discharge into fills in the future. Obtaining individual permits for fills is likely to be more costly and more time consuming than filing under a nationwide permit. As a result, our lessees’ coal mining costs could increase and they could mine less coal, which would adversely affect our coal royalty revenues.

Mining Permits and Approvals. Numerous governmental permits or approvals are required for mining operations. We do not hold any mining permits. Under our leases, our lessees are responsible for obtaining and maintaining all permits. 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. Regulations also provide that a mining permit can be refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.

In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including our lessees, must submit a reclamation plan for restoring the mined property to its prior condition, productive use or other permitted condition upon the completion of mining operations. 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 by our lessees over the next five years. Our lessees are in the planning phase for obtaining permits for the remaining reserves planned to be mined over the next five years. We cannot assure you, however, that they will not experience difficulty in obtaining mining permits in the future.

As a consequence of potential future legislation and administrative regulations that may emphasize the protection of the environment, the activities of mine operators, including our lessees, may be more closely regulated. Legislation and regulations, as well as future interpretations of existing laws, may also require substantial increases in equipment expenditures and operating costs, as well as delays, interruptions or the termination of operations. We cannot predict the possible effect of such regulatory changes.

Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.

Framework Convention on Global Climate Change. The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, that is intended to limit or capture emissions of greenhouse gases such as carbon dioxide and methane. The U.S. Senate has neither ratified the treaty commitments, which would mandate a reduction in U.S. greenhouse gas emissions, nor enacted any law specifically controlling greenhouse gas emissions, and the Bush Administration has withdrawn support for this treaty. Nonetheless, future regulation of greenhouse gases could occur either pursuant to future U.S. treaty obligations or pursuant to statutory or regulatory changes under the Clean Air Act. Efforts to control greenhouse gas emissions could result in reduced demand for coal if electric power generators switch to lower carbon sources of fuel. These restrictions or uncertainties could have a material adverse effect on our business.

Comprehensive Environmental Response, Compensation and Liability Act. CERCLA and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances that may endanger public health or welfare or the environment. Under

CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners and lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could implicate the liability provisions of the statute. Thus, coal mines on lands that we currently own or have previously owned, and sites to which our lessees sent waste materials, may be subject to liability under CERCLA and similar state laws. In particular, we may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination at sites where we own surface rights. We cannot assure you that we or our lessees will not become involved in future proceedings, litigation or investigations or that these liabilities will not be material.

Endangered Species. The federal Endangered Species Act and counterpart state legislation protects species threatened with possible extinction. Protection of endangered species may have the effect of prohibiting or delaying our lessees from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or silvicultural activities in areas containing the affected species. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our lessees’ ability to mine coal from our properties in accordance with current mining plans. There can be no assurance, however, that additional species on our properties will not receive protected status under the Endangered Species Act or that currently protected species will not be discovered within our properties.

Other Environmental Laws Affecting Our Lessees. Our lessees are required to comply with numerous other federal, state and local environmental laws in addition to those previously discussed. These additional laws include the Resource Conservation and Recovery Act, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. Except as set forth above, we believe that our lessees are in substantial compliance with all applicable environmental laws.

Of the 1.6 billion tons of proven and probable coal reserves to which we had rights as of December 31, 2003, we owned approximately 99% of the reserves in fee. We lease approximately 20 million tons, or 1% of our reserves, from unaffiliated third parties. We believe that we have satisfactory title to all of our mineral properties, but we have not had a qualified title company confirm this belief. Although title to these properties is subject to encumbrances in certain cases, such as customary easements, rights-of-way, interests generally retained in connection with the acquisition of real property, licenses, prior reservations, leases, liens, restrictions and other encumbrances, we believe that none of these burdens will materially detract from the value of our properties or from our interest in them or will materially interfere with their use in the operations of our business.

For most of our properties, the surface, oil and gas and mineral or coal estates are owned by different entities. Some of those entities are our affiliates. State law and regulations in most of the states where we do business require the oil and gas owner to coordinate the location of wells so as to minimize the impact on the intervening coal seams. We do not anticipate that the existence of the severed estates will materially impede development of the minerals on our properties.

We do not have any employees. To carry out our operations, affiliates of our general partner employ approximately 40 employees who directly support our operations. None of these employees are subject to a collective bargaining agreement. Some of the employees of our lessees and sub-lessees are subject to collective bargaining agreements.

Pursuant to SFAS No. 131, “Disclosure About Segments of an Enterprise and Related Information,” we are not required to disclose separate segment information because the materiality of timber and oil and gas did not meet the test for segment disclosure.

Our internet address is www.nrplp.com. We make available free of charge on or through our internet website our annual report on Form 10-K, quarterly reports on Form 10-Q 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. Also included on our website are our “Code of Business Conduct and Ethics” adopted by our Board of Directors and the charters for our Audit Committee, Conflicts Committee and Compensation, Nominating and Governance Committee. Also, copies of our annual report will be made available upon written request.

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 legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Our common units are listed and traded on the New York Stock Exchange under the symbol “NRP.” As of March 1, 2004, there were an estimated 4,550 beneficial owners of our common units, and four holders of subordinated units.

The following table sets forth the high and low sales prices per common unit, as reported on the New York Stock Exchange Composite Transaction Tape, from October 11, 2002 to December 31, 2003, and the quarterly cash distribution paid per common unit and subordinated unit.


(1)	The prorated cash distribution relates to the period from October 17, 2002, the closing date of our initial public offering, to December 31, 2002. This distribution was declared on January 21, 2003 and paid on February 14, 2003.

(2)	This distribution was declared on January 21, 2004 and paid on February 13, 2004.

In addition to common units, we have also issued subordinated units for which there is no established public trading market. The subordinated units were issued as part of our initial public offering in October 2002 and receive a quarterly distribution only after sufficient funds have been paid to the common units, as described below. The subordinated units are held by the WPP Group and FRC-WPP NRP Investment L.P.

During the subordination period, the holders of our common units are entitled to receive a minimum quarterly distribution of $0.5125 per unit prior to any distribution of available cash to holders of our subordinated units. The subordination period is defined generally as the period that will end on the first day of any quarter beginning after September 30, 2007 if (1) we have distributed at least the minimum quarterly distribution on all outstanding units in each of the immediately preceding three consecutive, non-overlapping four-quarter periods and (2) our adjusted operating surplus, as defined in our partnership agreement, during such periods equals or exceeds the amount that would have been sufficient to enable us to distribute the minimum quarterly distribution on all outstanding units on a fully diluted basis and the related distribution on the 2% general partner interest during those periods. In addition, 25% of the subordinated units may convert to common units on a one-for-one basis after September 30, 2005, and 25% of the subordinated units may convert to common units on a one-for-one basis after September 30. 2006, if we meet the tests set forth in our partnership agreement. If the subordination period ends, the rights of the holders of subordinated units will no longer be subordinated to the rights of the holders of common units, the subordinated units may be converted into common units and the common units will no longer be entitled to arrearages.

Our general partner, the WPP Group and NRP Investment L.P. are entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash” as that term is defined in our partnership agreement. The amount of available cash may be greater than or less than the minimum quarterly distribution. We currently pay quarterly cash distributions of $0.5625 per unit. In general, we intend to increase our cash distributions in the future assuming we are able to increase our “available cash” from our operations and through acquisitions, provided there is no adverse change in our operations, economic conditions and other factors. However, we cannot guarantee that future distributions will continue at such levels.

The following tables show selected historical financial data for Natural Resource Partners L.P. and our predecessors (Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and the Arch Coal Contributed Properties, collectively known as predecessors), in each case for the periods and as of the dates indicated. We derived the selected historical financial data for Natural Resource Partners L.P. as of December 31, 2003 and 2002, and for the year ended December 31, 2003 and for the period from commencement of operations (October 17, 2002) through December 31, 2002 from the audited financial statements of Natural Resource Partners L.P. We derived the selected historical financial data for the WPP Group for the period from January 1 through October 16, 2002 and as of and for the years ended December 31, 2001, 2000 and 1999 from the audited financial statements of the WPP Group, and we derived the selected historical financial data for the Arch Coal Contributed Properties for the period from January 1 through October 16, 2002 and as of and for the years ended December 31, 2001, 2000 and 1999 from the audited financial statements of the Arch Coal Contributed Properties.

We derived the information in the following tables from, and the information should be read together with and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes included in Item 8, “Financial Statements and Supplementary Data.” The tables should be read together with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” While substantially all of the producing coal-related assets and operations of the WPP Group were contributed to us, some assets and liabilities were retained by the WPP Group.


(1)	No financial data is presented for these periods because Natural Resource Partners L.P. was not formed until April 9, 2002 and did not commence operations until October 17, 2002.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of the financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included elsewhere in this filing. For more detailed information regarding the basis of presentation for the following financial information, see the notes to the historical financial statements.

After the Introduction, there is a separate section for each of Natural Resource Partners L.P., Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and the Arch Coal Contributed Properties. The Arch Coal Contributed Properties include the properties contributed to us by Ark Land Company, a subsidiary of Arch Coal, Inc.

Natural Resource Partners L.P. is a master limited partnership formed by the WPP Group and Arch Coal, Inc. We completed our initial public offering in October 2002. We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois basin and the Western United States. As of December 31, 2003, we controlled approximately 1.6 billion tons of proven and probable coal reserves in eight states.

We lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine our coal reserves in exchange for royalty payments. As of December 31, 2003, our reserves were subject to 109 leases with 48 lessees. For the year ended December 31, 2003, approximately 64% of the coal produced from our properties came from underground mines and approximately 36% came from surface mines. As of December 31, 2003, approximately 66% of our reserves were low sulfur coal. Included in our low sulfur reserves is compliance coal, which constitutes approximately 36% of our reserves. Coal produced from our properties is burned in electric power plants located east of the Mississippi River and in Montana and Minnesota. In the year ended December 31, 2003, our lessees produced 44.3 million tons of coal from our properties and our total revenues were $85.5 million. In addition, approximately 22% of our 2003 coal royalty revenues were from metallurgical coal, which was sold to steel companies in the Eastern United States, South America, Europe and Asia.

Our revenue and profitability are dependent on our lessees’ ability to mine and market our coal reserves. Coal royalties are paid to us on the basis of a percentage of the sales price of the coal, subject to a minimum royalty per ton. In addition, our leases specify minimum monthly, quarterly or annual royalties. These minimum royalties are generally recoupable over a specified period of time (usually three to five years) if sufficient royalties are generated from coal production in future periods. We do not recognize these minimum coal royalties as revenue until the applicable recoupment period has expired or they are recouped through production. Until recognized as revenue, these minimum royalties are carried as deferred revenue, a liability on the balance sheet.

Most of our coal is produced by large companies, many of which are publicly traded, with professional and sophisticated sales departments. We estimate that 80% of our coal is sold by our lessees under coal supply contracts that have terms of one year or more. However, coal supply contracts with terms of one year or more are becoming increasingly rare, and our coal royalty revenue stream is increasingly affected by changes in market price of coal.

Coal prices are based on supply and demand, specific coal characteristics, economics of alternative fuel, and overall domestic and international economic conditions. During the last few years, steam coal prices have varied greatly. While higher than average spot prices prevailed for most of 2001, in late 2001 prices declined as demand for coal fell due to unusually warm weather during the winter of 2001-2002 and the sluggish U.S. economy. In contrast, the winter of 2002-2003 was colder than normal in many parts of the United States. As a result of the increased demand for electricity for heating resulting from this colder weather, electric utilities used substantial amounts of coal to generate electricity and reduced the size of their stockpiles. Additionally, the weaker U.S. dollar, especially against the Euro and the Australian dollar, and the increase in ocean-going freight rates caused an increase in demand for export coal because the United States was better able to

compete with Australia for the European market. Thus, in 2003, our lessees experienced a greater demand for coal, and spot prices increased about 30%. We expect these increased spot prices to begin to affect our results of operations in 2004 because our lessees received previously contracted prices for much of their production in 2003.

Prices of metallurgical coal have increased substantially in the past year. Metallurgical coal, because of its unique chemical characteristics, is usually priced higher than steam coal. Metallurgical coal production gradually decreased during the years prior to 2003 due to a decline in exports as a result of the strength of the U.S. dollar and increasing use of electric arc furnaces and pulverized coal, rather than metallurgical coal, for steel production. With the weakening of the dollar and the increase in ocean-going freight rates, U.S. metallurgical coal has become more competitive and exports seem to be increasing. The ventilation disruption resulting in the closure of PinnOak Resources’ Pinnacle Mine in West Virginia, together with the closure of another low vol metallurgical mine in Alabama have caused a critical shortage of that type of coal and a substantial increase in its price. Metallurgical coal can also be used as steam coal. However, some metallurgical coal mines on our properties may only operate profitably if all or a portion of their production is sold as metallurgical coal. If the operators of these mines are unable to sell metallurgical coal, these mines may not be economically viable and may be closed.

In addition to coal royalty revenues, we generated approximately 5% of our 2003 revenue from rentals, royalties on oil and gas and coalbed methane leases, overriding royalty arrangements and wheelage payments, which are toll payments for the right to transport third-party coal over or through our property.

Most of our lessees are required to reimburse us for property taxes paid on the leased property. These property tax reimbursements are shown as revenue in our financial statements. We include the corresponding property tax expenses as “taxes other than income.” However, a portion of our property taxes are not reimbursed due to the terms in the lease. The WPP Group’s property tax expenses are higher than its property tax revenue because the WPP Group retained certain properties and because some of the properties contributed by the WPP Group are unleased and, therefore, no reimbursements are received.

General and administrative expenses include salary and benefits, rent, expenses and other costs related to managing the properties. An affiliate charged the WPP Group for certain finance, tax, treasury and insurance expenses. The Arch Coal Contributed Properties did not maintain stand-alone corporate treasury, legal, tax, human resources, general administration or other similar corporate support functions. Corporate general and administrative expenses were not previously allocated to the Arch Coal Contributed Properties because there was not sufficient information to develop a reasonable cost allocation. We reimburse the general partner and its affiliates for direct and indirect expenses they incur on our behalf, including general and administrative expenses.

Depletion and amortization consist primarily of depletion on the coal properties. Depletion of coal reserves is calculated on a unit-of-production basis and thus fluctuates from property to property with coal production for the period.

Since our initial public offering in October 2002, we have completed six significant acquisitions for an aggregate purchase price of $272.3 million. These acquisitions included approximately 735 million tons of coal reserves, or 665 million tons net of production, on approximately one million mineral acres. In connection with these acquisitions, we have added 22 new lessees and 63 new leases. All of the acquired properties are located in Appalachia and were integrated with our existing operations. All of the acquisitions were initially funded under our revolving credit facility. In connection with our issuance of $175 million in senior notes in June and September 2003, we converted a portion of those borrowings to long-term debt.

BLC Properties. In January 2004, we purchased all of the mineral interests of BLC Properties LLC for $73.0 million. This acquisition included coal, oil and gas and other mineral rights on approximately 270,000 acres that contain approximately 176 million tons of coal reserves. We lease these reserves to eight different lessees. The transaction also included oil and gas and other mineral rights on approximately 205,000 additional

Eastern Kentucky Reserves. In November 2003, we acquired coal reserves and related interests in Eastern Kentucky from a number of private sellers for $18.8 million. The acquisition included approximately 21 million tons of coal reserves, an additional royalty interest in approximately 8 million tons of coal reserves on contiguous property, and the right to collect a wheelage fee, which is a toll paid to transport coal across or through our properties, on 10 million tons of coal. We lease these reserves to Appalachian Fuels.

PinnOak Resources. In July 2003, we acquired approximately 79 million tons of coal reserves and an overriding royalty interest on additional coal reserves from subsidiaries of PinnOak Resources, LLC for $58.0 million. We lease these reserves to other subsidiaries of PinnOak Resources. PinnOak Resources produces low volatile metallurgical coal from these longwall mines and has onsite preparation plants. The properties consist of coal reserves located at two mine complexes: the Pinnacle mine in Pineville, West Virginia and the Oak Grove mine near Birmingham, Alabama.

Alpha Natural Resources Reserves. In April 2003, we acquired approximately 295,000 mineral acres containing approximately 353 million tons of coal reserves from two subsidiaries of Alpha Natural Resources, LLC for $53.6 million. We leased most of these reserves to two Alpha subsidiaries and seven other operators. The properties are located in Virginia adjacent to the coal properties that we acquired from El Paso Corporation in December 2002, which are operated by another subsidiary of Alpha Natural Resources, LLC.

Alpha Natural Resources Royalty Interest. In February 2003, we purchased an overriding royalty interest in the coal reserves that we purchased from El Paso Corporation in December 2002 from a subsidiary of Alpha Natural Resources LLC for $11.9 million.

El Paso Properties. In December 2002, we purchased 108 million tons of coal reserves from El Paso Corporation for $57.0 million. We lease these reserves to Alpha Natural Resources and thirteen other lessees. More than half of the reserves are in Kentucky, and the remainder are located in Virginia and West Virginia. We also acquired the mineral rights in 164,000 acres that generate minor amounts of revenues from timber, oil and gas and other leases.

In September 2003, the Pinnacle mine in West Virginia, which mines coal from the reserves we acquired from PinnOak Resources in July 2003, was idled following a ventilation disruption believed to have been caused by a lightning strike. On December 10, 2003, we received a force majeure notice from Pinnacle Mining Company, LLC regarding the mine. The notice allows Pinnacle to forego payment of the minimum royalties due under the lease terms until the mine is again in production. The Pinnacle mine produces metallurgical coal for which we receive higher prices than steam coal. Although we expected this mine to generate coal royalty revenues of about $6.5 million per year, we have not received any coal royalty revenues or minimum royalties from the operator of this mine since it was idled and will not until mining operations resume. If the mine does not reopen, we would lose some or all of our investment in these reserves.

In February 2004, a team of mine-rescue personnel, consisting of trained Pinnacle employees and representatives from the U.S. Mining Safety and Health Administration and the West Virginia Office of Miners’ Health Safety & Training, entered the mine to examine and assess the conditions. Pinnacle’s management is continuing to work with government officials and the United Mine Workers to reopen the mine.

Coal Royalties. We recognize coal royalty revenues on the basis of tons of coal sold by our lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time (usually three to five years) if sufficient royalties are generated from coal production in future periods.

We do not recognize these minimum coal royalties as revenue until the applicable recoupment period has expired or they are recouped through production. Until recognized as revenue, these minimum royalties are carried as deferred revenue, a liability on the balance sheet.

Timber Royalties. We sell timber on a contract basis where independent contractors harvest and sell the timber and, from time to time, in a competitive bid process involving sales of standing timber on individual parcels. We recognize timber revenues when the timber has been sold or harvested by the independent contractors. Title and risk of loss pass to the independent contractors when they harvest the timber.

Oil and Gas Royalties. Oil and gas royalties are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the lessees make payments based on a percentage of the selling price. Some leases are subject to minimum annual payments or delay rentals. The minimum annual payments that are recoupable are generally recoupable over certain periods. The minimum payments are initially recorded as deferred revenue and recognized either when the lessee recoups the minimum payments through production or when the period during which the lessee is allowed to recoup the minimum payment expires.

Depletion. We deplete coal properties on a units-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral properties and estimated proved and probable tonnage in those properties. We estimate proven and probable coal reserves with the assistance of third-party mining consultants, and we use estimation techniques and recoverability assumptions. Our estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. Historical revisions have not been material. Timberlands are stated at cost less depletion. We determine the cost of the timber harvested based on the volume of timber harvested in relation to the amount of estimated net merchantable volume by geographic areas. We estimate our timber inventory using statistical information and data obtained from physical measurements and other information gathering techniques. We update these estimates annually, which may result in adjustments of timber volumes and depletion rates that are recognized prospectively. Changes in these estimates have no effect on our cash flow.

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, with the associated asset retirement cost being capitalized as a part of the carrying amount of the long-lived asset. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and a reconciliation of changes in the components of those obligations. The operators of mines on our leased property are responsible for asset retirement obligations. Therefore, the adoption of SFAS No. 143 on January 1, 2003 did not have any impact on our financial position or results of operations.

In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which supersedes EITF No. 94-3, “Liability Recognition for Certain Employment Termination Benefits and Other Costs to Exit an Activity.” SFAS No. 146 requires companies to record liabilities for costs associated with exit or disposal activities to be recognized only when the liability is incurred instead of at the date of commitment to an exit or disposal activity. Adoption of this standard is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this standard did not have any impact on our financial statements.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities. “ SFAS No. 149 amends SFAS No. 133 as a result of:


	•	Decisions previously made as part of the Derivatives Implementation Group (DIG) process;

	•	Changes made in connection with other FASB projects dealing with financial instruments; and

	•	Deliberations in connection with issues raised in relation to the application of the definition of a derivative.

SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. However, the provisions of SFAS No. 149 that merely represent the codification of previous DIG decisions are already effective and continue to be applied in accordance with their prior respective effective dates. Management does not expect SFAS No. 149 to have any impact on our results of operations, financial position or liquidity.

SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” was issued in May 2003. SFAS No. 150 requires certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity to be classified as liabilities. Many of these instruments previously were classified as equity or temporary equity and as such, SFAS No. 150 represents a significant change in practice in the accounting for a number of financial instruments, including mandatorily redeemable equity instruments and certain equity derivatives that frequently are used in connection with share repurchase programs.

SFAS No. 150 is effective for public companies for all financial instruments created or modified after May 31, 2003, and to other instruments at the beginning of the first interim period beginning after June 15, 2003 (July 1, 2003 for calendar quarter companies). The adoption of SFAS No. 150 did not have any impact on our results of operations, financial position or liquidity.

In January 2003, the FASB issued FASB Interpretation No. 46 (“FIN No. 46”),“Consolidation of Variable Interest Entities.” The objective of this interpretation is to provide guidance on how to identify a variable interest entity (“VIE”) and determine when the assets, liabilities, noncontrolling interests, and results of operations of a VIE need to be included in a company’s consolidated financial statements. A company that holds variable interests in an entity will need to consolidate the entity if the company’s interest in the VIE is such that the company will absorb a majority of the VIE’s expected losses and/or receive a majority of the entity’s expected residual returns, if they occur. FIN No. 46 also requires additional disclosures by primary beneficiaries and other significant variable interest holders. FIN No. 46 was effective for all VIE’s created after January 31, 2003. For VIE’s created prior to February 1, 2003, FIN No. 46 was to be effective for public companies on July 1, 2003. However, the FASB postponed that effective date to December 31, 2003. In December 2003, the FASB issued a revised FIN No. 46 (FIN No. 46R), which further delayed the effective date for public companies to March 31, 2004 for VIE’s created prior to February 1, 2003, except for interests in special purpose entities, for which a company must adopt either FIN No. 46 or FIN No. 46R as of December 31, 2003. Adoption of the requirements of FIN No. 46R is not expected to have a material impact on our consolidated financial position, results of operations or cash flows.

Historical practice in the extractive industry has been to classify leased mineral interests on the same basis as owned minerals due to similar rights of the lessor. However, SFAS No. 141, “Business Combinations”, provides mineral rights as an example of a contract-based intangible asset that should be considered for separate classification as the result of a business combination. Due to the potential for inconsistencies in applying the provisions of SFAS No. 141 (and SFAS No. 142, “Goodwill and Other Intangible Assets”) in the extractive industries as they relate to mineral interests controlled by other than fee ownership, the Emerging Issues Task Force (the “EITF”) has established a Mining Industry Working Group that is currently addressing this issue. At December 31, 2002 and 2003, coal acquisition costs for leased mineral interests were less than 6% of our total assets. The classification of our leased coal interests and contractual agreements may be revised depending upon the conclusions reached by the Mining Industry Working Group and the EITF. Any reclassification would not have an effect on net income or net cash flows.

Revenues. For the year ended December 31, 2003, total revenues were $85.5 million compared to $13.9 million for the period from October 17, 2002 through December 31, 2002. The 2003 results include $73.8 million in coal royalty revenues, $2.0 million from minimum royalty payments, $1.0 million from overriding royalty agreements, $5.1 million from reimbursements of property taxes and $3.6 million from other revenue. Other revenue is comprised of oil and gas income of $1.7 million, wheelage income of $1.4 million and timber and rental income of $0.3 million and $0.2 million, respectively. For the two-and-one-half month period in 2002, we had $11.5 million in coal royalty revenues, $0.9 million from minimum royalty payments, $0.2 million from overriding royalty agreements, $1.0 million in property tax revenue and $0.2 million in other, which was primarily oil and gas and wheelage income. All of the increases are primarily due to 2003 consisting of complete year of operations and to acquisitions made during 2003.

Coal royalty revenues were $73.8 million, on 44.3 million tons of coal produced, for the year ending December 31, 2003, and represented 86% of total revenue. For the period from October 17, 2002 through December 31, 2002, coal royalty revenues were $11.5 million, on 7.3 million tons produced, and represented 83% of total revenue. The increase in coal royalty revenues in 2003 is reflective of not only a full year reporting period, but also the acquisitions made during fiscal 2003. For a comparison of coal royalty revenues in 2003 to the full year 2002, please read “— Coal Royalty Revenues and Production.”

Expenses. Total expenses were $41.4 million, or 48%, of total revenues for the year ended December 31, 2003, compared to $7.3 million, or 52%, of total revenues for the period from October 17, 2002 through December 31, 2002. Depletion and amortization represented 61% and 62% of the total expenses for the periods in 2003 and 2002, respectively. Although depletion and amortization was fairly consistent for the periods discussed, it can vary depending on where the coal production occurs and fluctuations in depletion rates. General and administrative expenses were approximately 15% of total expenses in both years, excluding accruals for incentive compensation of $2.8 million in 2003. Taxes other than income were $5.8 million, or 14%, of total expenses for 2003 and $1.3 million, or 18%, of total expenses for 2002. Due to the acquisitions made during 2003 and the timing of the assumption of the liability for such taxes, however, a comparison of the two percentages is not meaningful. Other coal-related expenses were down as a percentage of total expenses in 2003, due to the purchase of the overriding interest from a subsidiary of Alpha Natural Resources LLC in February 2003.

Other Income (Expense). Interest expense was significantly higher for 2003 due to the debt incurred to finance the acquisitions we made during 2003. Interest income increased from 2002 as a result of the investment of surplus cash in money market funds. Other expense includes a $0.5 million expense related to the hedge of interest rates on the issuance of the senior notes that occurred in second quarter of 2003. Also included in other expense is a loss on the sale of oil and gas properties of $0.1 million incurred upon disposition of these properties.

The following table sets forth coal royalty revenues and production from our properties for the years ending December 31, 2003 and 2002. In 2002, the revenues and production are attributable to both the properties contributed to us at the time of our initial public offering and the properties we acquired in December 2002. Coal royalty revenues and production were generated from the properties in each of the following areas: Appalachia, Illinois Basin and Northern Powder River Basin.

Coal royalty revenues for the year ended December 31, 2003 were $73.8 million compared to $49.6 million for the year ended December 31, 2002, an increase of $24.2 million, or 49%. In 2003, production increased by 13.8 million tons, from 30.5 million tons to 44.3 million tons, or 45%, compared to 2002. Substantially all of the increases in production and coal royalty revenues were from the properties and an overriding royalty interest that we acquired since our initial public offering. Other than approximately one month of production from the properties we acquired from El Paso in December 2002, all of the production and coal royalty revenues attributable to our acquisitions are reflected in our 2003 results. Other increases in coal royalty revenues and production were due to:

Appalachia. Coal royalty revenues in Appalachia in 2003 were $63.9 million compared to $40.7 million in 2002, an increase of $23.2 million, or 57%. In 2003, production in Appalachia was 36.0 million tons compared to 22.6 million tons in 2002, an increase of 13.4 million tons, or 59%. As noted above, the increases in both coal royalty revenues and production primarily resulted from the acquisitions we have completed since our initial public offering.

In addition to the acquisitions, production from our West Fork property increased from 2.1 million tons to 2.8 million tons, and coal royalty revenues increased from $4.7 million to $6.3 million because a longwall mine moved onto the property from adjacent property and was on our property for the entire year versus a portion of the year in 2002. On our Lynch property, production decreased from 3.0 million tons to 2.9 million tons while coal royalty revenue increased from $4.5 million to $4.7 million. This increase in royalty revenue was due to a slightly higher average selling price for the production of our lessee.

These increases were partially offset by lower royalty revenue from our Evans-Laviers, Eunice and Lone Mountain properties. On our Evans-Laviers property, production decreased from 3.4 million tons to

3.0 million tons and coal royalty revenues decreased from $4.5 million to $3.8 million. This decrease was a combination of a higher royalty surface mine being idle for most of the year and an underground mine having higher production during the current year. On our Eunice property, production remained constant at 2.6 million tons but coal royalty revenues decreased from $4.6 million to $4.3 million because a greater proportion of the production came from the lower royalty surface mine. On our Lone Mountain property production remained constant at 2.5 million tons while royalty revenue decreased from $4.8 million to $4.6 million due to a slightly lower average selling price from the production of our lessee.

Illinois Basin. On our Cummings/ Hocking-Wolford property, production increased from 1.1 million tons to 1.6 million tons, and coal royalty revenues increased from $1.1 million to $1.7 million. This increase was due to a larger proportion of the production from the mine being on our property.

Northern Powder River. Production from our Western Energy property increased from 3.7 million tons to 4.3 million tons and royalty revenue increased from $4.3 million to $5.4 million. This increase was due to the typical variations in production resulting from the checkerboard ownership pattern of the mine and a higher average selling price for the production from our property.

The following table sets forth coal royalty revenues and production from our properties for the years ending December 31, 2002 and 2001. For the year ended December 31, 2001, the revenues and production are attributable to the properties contributed to us at the time of our initial public offering. For the year ended December 31, 2002, the revenues and production are attributable to both the contributed properties and the properties we acquired in December 2002. Coal royalty revenues and production were generated from the properties in each of the following areas: Appalachia, Illinois Basin and Northern Powder River Basin.

Coal royalty revenues for the year ended December 31, 2002 were $49.6 million compared to $41.8 million for the year ended December 31, 2001, an increase of $7.8 million, or 19%. In 2002, production increased by 1.5 million tons, from 29.0 million tons to 30.5 million tons or 5.2%, compared to 2001. The increases in production and coal royalties were primarily due to:

Appalachia. Production from our West Fork property increased from 222,000 tons to 2.1 million tons, and coal royalty revenues increased from $357,000 to $4.7 million because a longwall mine moved onto the

property from adjacent property. On our Eunice property, production increased from 1.8 million tons to 2.6 million tons, and coal royalty revenues increased from $2.7 million to $4.6 million because a longwall mine was on our property for a greater portion of the year and was subject to a higher royalty rate. On our Welch/ Wyoming property, production increased from 222,000 tons to 609,000 tons, and coal royalty revenues increased from $361,000 to $1.3 million because a new mine, which began production during 2001, operated on the property for the entire year. On our Dorothy property, production increased from 652,000 tons to 1.0 million tons, and coal royalty revenues increased from $1.1 million to $2.0 million. This increase was due to increased production from a surface mine and the resumption of mining at a temporarily idled mine. On our Kingston property, production increased from 740,000 tons to 1.1 million tons, and coal royalty revenues increased from $1.3 million to $1.8 million. This increase was primarily due to a new mine starting on the property during the year. In addition to the above increases, the acquisition of properties from El Paso on December 4, 2002 resulted in additional production of 504,000 tons and coal royalty revenues of $601,000 in 2002.

These increases were partially offset by lower production and coal royalty revenues from our Evans-Laviers, Rockhouse and Boone-Lincoln properties. On our Evans-Laviers property, production decreased from 3.8 million tons to 3.4 million tons. Coal royalty revenues decreased from $5.1 million to $4.4 million. This decrease was due to the idling of a higher-royalty-rate surface mine for part of the year. On our Rockhouse property, production decreased from 322,000 tons to 34,000 tons, and coal royalty revenues decreased from $791,000 to $82,000 because a mine on the property ceased production. On our Boone-Lincoln property, production decreased from 670,000 tons to 195,000 tons, and coal royalty revenues decreased from $1.3 million to $389,000. This decrease was due to lower production on the property from the active surface mine and the temporary idling of the underground mine on the property. This mine has since been restarted.

Illinois Basin. On our Trico property, production increased to 486,000 tons from 253,000 tons because a mine that began operating in 2001 produced for an entire year. This resulted in coal royalty revenues increasing to $682,000 from $343,000. This increase was offset by lower production on our Cummings/ Hocking-Wolford property. Production decreased from 1.5 million tons to 1.1 million tons, and coal royalty revenues decreased from $1.5 million to $1.1 million. This decrease was due to a larger proportion of the production from the mine being on adjacent property.

Northern Powder River. Production from our Western Energy property decreased from 4.9 million tons to 3.7 million tons. This resulted in a decrease in coal royalty revenues from $5.3 million to $4.3 million. This decrease was due to the typical variations in production resulting from the checkerboard ownership pattern of the mine. This pattern causes variations in the proportions of the total mine production on our property.

For the Period from January 1 through October 16, 2002 compared with year ended December 31, 2001

Revenues. Total revenues for the nine and one-half month period in 2002 were $22.6 million compared to $26.0 million for the full year 2001, a decrease of $3.4 million, or 15%, of which $3.1 million was due to a sale of assets in 2001.

For the nine and one-half month period in 2002, coal royalty revenues were $17.3 million compared to $15.5 million for the full year 2001, an increase of $1.8 million, or 12%. Over these same periods, production decreased by 0.7 million tons, or 7%, from 10.3 million tons to 9.6 million tons. In addition to the differences caused by comparing twelve months in 2001 to nine and one-half months in 2002, these changes in production and coal royalties were primarily due to:

Appalachia. Production from our West Fork property increased from 222,000 tons to 1.5 million tons, and coal royalty revenues increased from $357,000 to $3.3 million because a longwall mine moved onto the property from adjacent property. On our Eunice property, production stayed constant at 1.8 million tons, and coal royalty revenues increased from $2.7 million to $3.2 million because a greater proportion of production was from a longwall mine that is subject to a higher royalty rate. On our Welch/ Wyoming property, production increased from 222,000 tons to 449,000 tons, and coal royalty revenues increased from $361,000 to $1.0 million because a new mine, which began production during 2001, operated on the property for the entire nine and one-half month period. On our Dorothy property, production increased from 652,000 tons to 813,000

These increases were partially offset by lower production and coal royalty revenues from our Rockhouse property. On that property, production decreased from 322,000 tons to 34,000 tons, and coal royalty revenues decreased from $791,000 to $82,000 because a mine on the property ceased production.

Aggregate production from our Beaver Creek, Thomas and Stony River properties increased from 333,000 tons to 621,000 tons as the lessee concentrated production on our properties during the nine and one-half month period. This resulted in coal royalty revenues increasing from $792,000 to $1.4 million.

On our Evans-Laviers property, production decreased from 3.8 million tons to 2.6 million tons, and coal royalty revenues decreased from $5.1 million to $3.5 million. This decrease was due to the idling of a higher-royalty-rate surface mine for part of the nine and one-half month period.

Illinois Basin. The increases in Appalachia were offset by lower production on our Cummings/ Hocking-Wolford property. Production decreased from 1.5 million tons to 775,000 tons, and coal royalty revenues decreased from $1.5 million to $778,000. This decrease was due to a larger proportion of the production from the mine being on adjacent property during the nine and one-half month period.

Timber revenues decreased to $2.8 million in 2002 from $3.7 million in 2001, a decrease of $0.9 million, or 32%. This decrease was primarily due to 2002 being a short period of nine and one-half months.

Other revenues decreased from $2.5 million in 2001 to $1.2 million in 2002, a decrease of $1.3 million, or 52%. Of the $1.3 million decrease, $0.9 million was due to a determination that a lessee was required to pay transportation fees for 2001 that were previously unreported by the lessee for several years. Rental receipts for the nine and one-half month period were $0.3 million lower than for the full year 2001.

Expenses. Aggregate expenses for 2002 were $7.3 million compared to $5.8 million for 2001, an increase of $1.5 million, or 26%, primarily due to increased depletion associated with the purchase of the reversionary interest described below.

Other Income (Expense). Interest expense was $4.8 million for 2002 compared to $4.0 million for 2001, an increase of $0.8 million, or 20%, resulting from additional debt incurred from the acquisition of the reversionary interest from CSX.

Reversionary Interest. The previous owner of Western Pocahontas Properties Limited Partnership’s coal and timber properties (CSX Corporation and certain of its affiliates) retained a reversionary interest in those properties whereby it received either a 25% or 28% interest in the properties and the net revenues of the properties after July 1, 2001, and in the net proceeds of any property sale occurring prior to July 1, 2001. Western Pocahontas purchased the reversionary interest related to its Kentucky properties in 2001 and the remainder of the interest in March 2002. In 2001, Western Pocahontas accrued $1.9 million related to the reversionary interest.

Net Income. Net income was $10.1 million in 2002 compared to $14.5 million in 2001, a decrease of $4.4 million, or 30%. This is primarily due to 2002 being a short period of nine and one half months.

For the Period from January 1 through October 16, 2002 compared with year ended December 31, 2001

Revenues. Total revenues for the nine and one-half month period in 2002 were $6.5 million compared to $8.8 million for the full year 2001, a decrease of $2.3 million, or 35%. For the nine and one-half month period in 2002, coal royalty revenues were $5.9 million compared to $7.5 million for the full year 2001, a decrease of $1.6 million, or 27%. Over these respective periods, production decreased by 3.5 million tons, or 41%, from 8.5 million tons to 5.0 million tons. These changes in production and coal royalties were primarily due to:


	Northern Powder River. Production from our Western Energy property decreased from 4.9 million tons to 3.7 million tons. This resulted in a decrease in coal royalty revenues from $5.3 million to $3.3 million. These differences are primarily due to 2002 being a short period of nine and one-half months.

	Lease and easement income in 2002 was $474,000 compared to $787,000 in 2001. This decrease is a result of a decline in surface mining activity as well as 2002 being a short period of nine and one-half months.

	Gain on sale of property was $439,000 in 2001, and there were no property sales for the nine and one-half months in 2002.

Other Income (Expense). Interest expense was $1.9 million for 2002 compared to $3.7 million for 2001, a decrease of $1.8 million, or 95%. In addition to the differences caused by the difference in the length of periods, this decrease resulted from a reduction in the interest rate and a decline in the amount of debt outstanding.

Net Income. Net income was $2.3 million for 2002 compared to $2.6 million for 2001, a decrease of $0.3 million, or 13%. This decrease primarily resulted from a reduction in interest expense that was partially offset by lower coal royalties.

For the Period from January 1 through October 16, 2002 compared with year ended December 31, 2001

Revenues. Total revenues for the nine and one-half month period in 2002 were $1.5 million compared to $1.7 million for the full year 2001, a decrease of $0.2 million, or 13%. Coal royalty revenues in 2002 were $1.4 million compared to $1.6 million in 2001, a decrease of $0.2 million, or 14%. Over these same periods, production decreased by 239,000 tons, or 50%, from 718,000 tons to 479,000 tons. In addition to the differences caused by comparing twelve months in 2001 to nine and one-half months in 2002, these changes in production and coal royalties were primarily due to:


	A decrease in production from our West Virginia property from 441,000 tons to 230,000 tons. Coal royalty revenues decreased from $985,000 to $561,000 due to a combination of market-based reductions and adverse geologic conditions in the mine during part of the nine and one-half month period of 2002. This decrease was partially offset by increased coal royalty revenues on our Alabama properties.

Expenses. Aggregate expenses for the nine and one-half month period in 2002 were $232,000 compared to $298,000 for 2001, a decrease of $66,000, or 28%. This decrease was due primarily to a decrease in depletion expense.

Net Income. Net income was $1.1 million for 2002 compared to $1.2 million for 2001, a decrease of $0.1 million, or 9%. This decrease was primarily due to 2002 being a short period of nine and one-half months.

For the Period from January 1 through October 16, 2002 compared with year ended December 31, 2001

Revenues. Revenues for the nine and one-half month period in 2002 were $17.3 million, a decrease of $3.5 million as compared to twelve months in 2001. In addition to the differences caused by comparing twelve months in 2001 to nine and one-half months in 2002, these changes in production and coal royalties were primarily due to:


	Appalachia. On our Kingston property, production increased from 740,000 tons to 894,000, and coal royalty revenues increased from $1.3 million to $1.5 million. This increase was primarily due to a new mine starting on the property during the year. On our Boone-Lincoln property, production decreased from 670,000 tons to 158,000 tons, and coal royalty revenues decreased from $1.3 million to $322,000. This decrease was due to lower production on the property from the active surface mine and the temporary idling of the underground mine on the property. This mine resumed production in late 2002.

	Illinois Basin. On our Trico property, production increased to 376,000 tons from 253,000 tons due to a mine that began operating in 2001 producing for nine and one-half months. This resulted in coal royalty revenues increasing to $528,000 from $343,000.

Direct costs and expenses. Direct costs and expenses in 2002 were $6.6 million compared to $7.6 million in 2001, a decrease of $1.0 million, or 13%. This decrease was largely due to depletion resulting from the nine and one-half month period being compared to a full year. Depletion expense decreased $1.5 million to $4.9 million in 2002 from $6.4 million in 2001.

Our general partner will not receive any management fee or other compensation for its management of Natural Resource Partners. However, in accordance with our partnership agreement, our general partner and its affiliates are reimbursed for expenses incurred on our behalf. All direct general and administrative expenses are charged to us as incurred. We also reimburse indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates. Cost reimbursements due our general partner may be substantial and will reduce our cash available for distribution to unitholders. The reimbursements to our general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation totaled $2.9 million in 2003 and $0.3 million in 2002. For additional information, please read “Certain Relationships and Related Transactions — Omnibus Agreement.”

On December 22, 2003, Corbin J. Robertson, Jr., the Chairman and Chief Executive Officer of GP Natural Resource Partners LLC, together with First Reserve Corporation and members of our management team, formed an investor group that purchased the subordinated units of Arch Coal, Inc. for $111 million. In addition, Mr. Robertson and a private group of investors consisting of individual partners in the WPP Group purchased the interests in our general partner and the incentive distribution rights held by Arch for $4 million. Our Conflicts Committee reviewed and approved this transaction.


	•	all of its interests in GP Natural Resource Partners LLC to Robertson Coal Management LLC;

	•	all of its interests in NRP (GP) LP, together with all of its incentive distribution rights, to NRP Investment L.P., an affiliate of the WPP Group; and

	•	4,796,920 subordinated units of Natural Resource Partners L.P. to FRC-WPP NRP Investment L.P., an affiliate of the WPP Group and First Reserve GP IX, Inc.

The transactions did not include the 2,895,670 common units owned by Arch. Arch Coal retained the right to elect two directors, one of whom must be an independent director, to the board of directors of GP Natural Resource Partners LLC for so long as Arch continues to hold at least 10% of the common units of Natural Resource Partners. In connection with the sale, the board of directors of GP Natural Resource Partners LLC was expanded to nine members, and FRC-WPP NRP Investment L.P., which is indirectly controlled by First Reserve GP IX, Inc., obtained the right to elect two directors, one of whom must be an independent director, to the board of GP Natural Resource Partners LLC.

Concurrently with our initial public offering in October 2002, we entered into four coal mining leases with Ark Land Company, a subsidiary of Arch Coal, Inc. The Ark Land leases grant them the right to mine our coal on the following properties:


	•	Lone Mountain located in Kentucky, which contains 44.6 million tons of proven and probable reserves as of December 31, 2003;

	•	Pardee located in Kentucky and Virginia, which contains 19.2 million tons of proven and probable reserves as of December 31, 2003;

	•	Boone/ Lincoln located in West Virginia, which contains 17.9 million tons of proven and probable reserves as of December 31, 2003; and

	•	Campbell’s Creek located in West Virginia, which contains 9.0 million tons of proven and probable reserves as of December 31, 2003.

Coal royalty revenues payable under these leases based on 2003 production were $9.5 million, representing 12.9% of our total coal royalty revenues for the year ended December 31, 2003. If no production had taken place in 2003, minimum recoupable royalties of $6.8 million would have been payable under the leases. On October 21, 2003, Arch Coal entered into a guaranty agreement with us under which Arch agreed to pay us a minimum of $11.3 million in coal royalties with respect to these leases in 2004.

The Ark Land leases have an initial term of either eight or ten years, each with an automatic year-to-year extension until the earlier to occur of (1) delivery of notice by Ark Land that it will not renew the lease or (2) all mineable and merchantable coal has been mined. The leases provide for payments to us based on the higher of a percentage of the gross sales price or a fixed minimum per ton of coal sold from the properties, with minimum annual royalty payments. Under the Ark Land leases, minimum royalty payments are credited against future production royalties.

The leases are intended to allow Ark Land to retain some of the legal rights possessed when it owned the properties. For this reason, the leases contain some terms and provisions that are different from our third-party coal leases negotiated at arm’s length. Some of the more significant differences include:


	•	Ark Land has the ability to sublease the leased property without our prior approval, although it remains responsible for sublessee performance;

	•	minimum royalty payments from Ark Land continue to be payable during the initial lease term even if all mineable and merchantable coal has been mined from the property;

	•	royalties for coal sold to any affiliates may be based on a gross selling price below the market value of the coal;

	•	the indemnities provided by Ark Land to us do not survive the termination of the leases;

	•	we only have a limited ability to terminate the leases;

	•	Ark Land has royalty-free wheelage rights on the leased properties; and

	•	the leases do not impose a legal duty to diligently mine the maximum amount of coal possible from the leased property.

We believe that the production and minimum royalty rates contained in the Ark Land leases are consistent with current market royalty rates.

First Reserve, which has the right to nominate two members to the board of directors of GP Natural Resource Partners LLC, has a controlling interest in Alpha Natural Resources, which was our largest lessee in 2003, based on revenues. We have entered into a number of coal mining leases with Alpha through a combination of new leases entered into upon our purchase of the Alpha property and through leases we had with entities that Alpha acquired. The leases we have with Alpha or related companies consist of the following properties:


	•	VICC/ Alpha in Virginia, which contains 365.0 million tons of proven and probable reserves as of December 31, 2003.

	•	Kingwood in West Virginia, which contains 20.8 million tons of proven and probable reserves as of December 31, 2003.

	•	Welch/ Wyoming in West Virginia, which contains 8.0 million tons of proven and probable reserves as of December 31, 2003.

	•	Davis Lumber in West Virginia, which contains 17,000 tons of proven and probable reserves as of December 31, 2003.

	•	Kentucky Land in Kentucky, which contains 20.3 million tons of proven and probable reserves as of December 31, 2003.

Coal royalty revenues payable under these leases based on 2003 production totaled $15.1 million, representing 20.5% of our total coal royalty revenues for the year ended December 31, 2003. If no production had taken place in 2003, minimum recoupable royalties of $3.9 million would have been payable under the leases.

The Alpha leases in general have terms of five to ten years with the ability to renew the leases for subsequent terms of five to ten years, until the earlier to occur of: (1) delivery of notice that the lessee will not renew the lease or (2) all mineable and merchantable coal has been mined. The leases provide for payments to us based on the higher of a percentage of the gross sales price or a fixed minimum per ton of coal sold from the properties, with minimum annual payments. Under the Alpha leases minimum royalty payments are credited against future production royalties.

We believe the production and minimum royalty rates contained in the Alpha leases are consistent with current market royalty rates.

For more information about our related party transactions, please read Item 13, “Certain Relationships and Related Transactions.”

We satisfy our working capital requirements with cash generated from operations. Since our initial public offering, we have financed our property acquisitions through borrowings under our revolving credit facility and the issuance of our senior notes. We believe that cash generated from our operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements and anticipated capital expenditures for the next several years. We expect to fund future acquisitions with borrowings under our credit facility and proceeds from the issuance of debt and equity. Our ability to satisfy any debt service obligations, to fund planned capital expenditures, to make acquisitions and to pay distributions to our unitholders will depend upon our ability to access the capital markets, as well as our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control. For a more complete discussion of factors that will affect cash flow we generate from our operations, please read “Risks Related to Our Business.” Our capital expenditures, other than for acquisitions, have historically been minimal.

Net cash provided by operations for the year ended December 31, 2003 was $64.5 million and for the period from commencement of operations (October 17, 2002) through December 31, 2002 it was $6.7 million, substantially all of which was from coal royalty revenues.

Net cash used in investing activities for the year ended December 31, 2003 was $142.5 million. This amount includes the acquisition of the overriding interest in February for $11.9 million, the acquisition of 290,000 mineral acres from Alpha Natural Resources for $53.8 million, the acquisition of 78 million tons of proven coal reserves from PinnOak Resources for $58 million and the acquisition of additional Kentucky coal reserves for $18.8 million. We funded these acquisitions with borrowings under our revolving credit facility. We repaid $175 million of those borrowings with the proceeds from the issuance of senior notes in June and September of 2003. For the period from commencement of operations (October 17, 2002) through December 31, 2002, net cash used for investing was $57.5 million for the acquisition of the properties from El Paso Corporation. We financed this acquisition with borrowings and our revolving credit facility.

Cash provided by financing activities for the year ended December 31, 2003 was $94.5 million. During the year we received proceeds from additional borrowings of $317.1 million, which includes $142.1 million under our revolving credit facility and $175.0 million from the issuance of our senior unsecured notes. These borrowings were partially offset by repayments of debt on our revolving credit facility of $172.6 million. We paid $0.9 million to settle an interest rate hedge entered into in connection with issuance of our senior notes and $2.5 million for debt issuance costs. For the year ended December 31, 2003, we also paid cash distributions of $46.5 million to our partners. Cash provided by financing activities for 2002 was $58.5 million. This was attributable to borrowings under our revolving credit facility used to fund acquisitions.

Our debt exists entirely at our wholly owned subsidiary, NRP Operating LLC, and currently consists of:


	•	a $175 million revolving credit facility that matures in October 2005 and under which $27.0 million was outstanding at December 31, 2003;

	•	$60 million of 5.55% senior notes due 2023, with a 10-year average life;

	•	$80 million of 4.91% senior notes due 2018, with a 7.5-year average life; and

	•	$35 million of 5.55% senior notes due 2013.

Credit Facility. NRP Operating LLC has entered into a $175.0 million revolving credit facility which includes a $12.0 million distribution loan sublimit that can be used for funding quarterly distributions. The remainder of the revolving credit facility is available for general purposes, including future acquisitions, but may not be used to fund quarterly distributions.

Our obligations under the credit facility are unsecured but are guaranteed by us and our operating subsidiaries. We may prepay all loans at any time without penalty. We must reduce all borrowings under the distribution loan subfacility to zero for a period of at least 15 consecutive days once during each twelve-month period.

Indebtedness under the revolving credit facility bears interest, at our option, at either:


	•	the higher of the federal funds rate plus an applicable margin ranging from 0.25% to 0.75% or the prime rate as announced by the agent bank; or

	•	at a rate equal to LIBOR plus an applicable margin ranging from 1.25% to 2.25%.

We incur a commitment fee on the unused portion of the revolving credit facility at a rate of 0.50% per annum.

The credit facility prohibits us from making distributions to unitholders and distributions in excess of available cash if any potential default or event of default, as defined in the credit agreement, occurs or would result from the distribution. In addition, the credit facility contains various covenants limiting our operating company’s and its subsidiaries’ ability to:


	•	incur indebtedness;

	•	prepay our senior notes or amend or modify the terms thereof;

	•	grant liens;

	•	engage in mergers and acquisitions or change the nature of our business;

	•	amend our organizational documents or omnibus agreement;

	•	make loans and investments;

	•	sell assets; or

	•	enter into transactions with affiliates.


	•	a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the credit agreement) of 3.5 to 1.0 for the four most recent quarters; and

	•	a ratio of consolidated EBITDA to consolidated fixed charges of 4.0 to 1.0 for the four most recent quarters.

If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of any indebtedness outstanding under the credit agreement and exercise other rights and remedies. Each of the following will be an event of default:


	•	failure to pay any principal, interest, fees or other amount when due;

	•	failure to pay any indebtedness, other than indebtedness under the credit facility, in excess of $1 million when due or the occurrence and continuance of any other default beyond any applicable grace period, if the default permits or causes the acceleration of the indebtedness or termination of any commitment to lend;

	•	bankruptcy or insolvency events;

	•	termination of existence;

	•	failure to comply with the loan documents, subject to certain grace periods;

	•	any representation, warranty or document provided is determined to have been materially untrue when made or provided;

	•	entry and the failure to pay, bond, stay or contest adverse judgments or similar processes in excess of $1 million more than any applicable insurance coverage; and

	•	any of the following changes in control:


	•	we cease to own all of the member interests of the operating company;

	•	our general partner ceases to own directly all of our general partner interests; or

	•	Corbin J. Robertson, Jr. and the WPP Group, Arch Coal and one or more of their direct or indirect subsidiaries cease to own more than 50% of the partnership interests of our general partner.

Senior Notes. NRP Operating LLC issued the senior notes under a note purchase agreement. The senior notes are unsecured but are guaranteed by our operating subsidiaries. We may prepay the senior notes at any time together with a make-whole amount (as defined in the note purchase agreement). If any event of default exists under the note purchase agreement, the noteholders will be able to accelerate the maturity of the senior notes and exercise other rights and remedies. The note purchase agreement contains covenants limiting our operating company’s and, in some cases, its subsidiaries’, ability to:


	•	enter into transactions with affiliates;

	•	engage in mergers or sell assets;

	•	grant liens;

	•	incur additional debt if the ratio of consolidated debt (as defined in the note purchase agreement) to consolidated EBITDA (as defined in the note purchase agreement) would exceed 4.0 to 1.0; and

	•	change the nature of its business.

The note purchase agreement also contains covenants requiring our operating subsidiary to:


	•	not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and

	•	maintain the ratio of consolidated EBITDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.

If an event of default exists under the note purchase agreement, the noteholders will be able to accelerate the maturity of the senior notes and exercise other rights and remedies. Each of the following will be an event of default:


	•	failure to pay principal on any make-whole amount when due;

	•	failure to pay interest for more than five business days after it becomes due;

	•	failure to comply with the note purchase agreement, subject to certain grace periods;

	•	any representation or warranty provided proves to have been false or incorrect in any material respect when made;

	•	failure to pay any debt (or interest thereon) in excess of $10.0 million beyond any applicable grace period, a default in the performance of or compliance with any term of any debt in excess of $10.0 million if the default causes the debt to become due;

	•	the occurrence or continuation of any event that results in the borrower becoming obligated to repay or repurchase any of its debt, such as a change of control provision;

	•	bankruptcy or insolvency events;

	•	entry and failure to pay bond, stay or discharge a final judgment in excess of $10.0 million;

	•	the occurrence of certain ERISA events; and

	•	the note purchase agreement, any note or subsidiary guarantee ceases to be in full force and effect.

The following table reflects our long-term non-cancelable contractual obligations as of December 31, 2003 (in millions):


(1)	The amounts indicated in the table include principal and interest due on our senior notes and the amount due at the maturity of our revolving credit facility in 2005. The amount of interest we will pay with respect to our revolving credit facility will depend on interest rates and the amounts drawn under the facility during the year.

On December 23, 2003 we and our operating subsidiaries jointly filed a $500 million “universal shelf” registration statement with the Securities and Exchange Commission for the proposed sale of debt and equity securities. Securities issued under this shelf may be in the form of common units representing limited partner interests in Natural Resource Partners or debt securities of NRP or any of our operating subsidiaries. The registration statement also covers, for possible future sales, up to 673,715 common units held by Great Northern Properties Limited Partnership. Great Northern Properties acquired the common units as consideration for its contribution to us of properties and debt in connection with our initial public offering.

The securities may be offered from time to time directly or through underwriters at amounts, prices, interest rates and other terms to be determined at the time of any offering. The net proceeds from the sale of securities from the shelf will be used for future acquisitions and other general corporate purposes, including the retirement of existing debt. We will not receive any proceeds from the sale of common units by Great Northern Properties.

Inflation in the United States has been relatively low in recent years and did not have a material impact on operations for the years ended December 31, 2001, 2002 and 2003.

The operations our lessees conduct on our properties are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As an owner of surface interests in some properties, we may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of our coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify us against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Because we have no employees, employees of Western Pocahontas Properties make regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. We believe that our lessees will be able to comply with existing regulations and do not expect any lessee’s failure to comply with environmental laws and regulations to have a material impact on our financial condition or results of operations. We have neither incurred, nor are aware of, any material environmental charges imposed on us related to our properties for the period ended December 31, 2003. We are not associated with any environmental contamination that may require remediation costs. However, our lessees do conduct reclamation work on the properties under lease to them. Because we are not the permittee of the mines being reclaimed, we are not responsible for the costs associated with these reclamation operations. In addition, West Virginia has established a fund to satisfy any shortfall in our lessees’ reclamation obligations. We are also indemnified by Western Pocahontas Properties, Great Northern Properties, New Gauley Coal Corporation and Arch Coal, jointly and severally, until October 17, 2005 against environmental and tax liabilities attributable to the ownership and operation of the assets contributed to us prior to the closing of the initial public offering. The environmental indemnity is limited to a maximum of $10.0 million.

Statements included in this Form 10-K are forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements.

Such forward-looking statements include, among other things, statements regarding capital expenditures, acquisitions and dispositions, expected commencement dates of coal mining, projected quantities of future coal production by our lessees producing coal from our reserves leased, projected demand or supply for coal that will affect sales levels, prices and royalties realized by us.

These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number or risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

You should not put undue reliance on any forward-looking statements. Please read “Risks Related to Our Business” for important factors that could cause our actual results of operations or our actual financial condition to differ.


	•	We may not have sufficient cash from operations to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

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

	•	Our lessees’ coal mining operations are subject to operating risks that could result in lower coal royalty revenues to us.


	•	We depend on a limited number of primary operators for a significant portion of our coal royalty revenues, and the loss of or reduction in production from any of our major operators could reduce our coal royalty revenues.

	•	We may not be able to terminate our leases, and we may experience delays and be unable to replace lessees that do not make royalty payments.

	•	If our lessees do not manage their operations well, their production volumes and our coal royalty revenues could decrease.

	•	Adverse developments in the coal industry could reduce our coal royalty revenues, and could substantially reduce our total revenues due to our lack of asset diversification.

	•	Any decrease in the demand for metallurgical coal could result in lower coal production by our lessees, which would thereby reduce our coal royalty revenues.

	•	We may not be able to expand and our business will be adversely affected if we are unable to replace or increase our reserves or obtain other mineral reserves through acquisitions.

	•	Any change in fuel consumption patterns by electric power generators resulting in a decrease in the use of coal could result in lower coal production by our lessees, which would reduce our coal royalty revenues.

	•	Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts with terms of one year or more, which could adversely affect the stability and profitability of their operations and adversely affect our coal royalty revenues.

	•	Competition within the coal industry may adversely affect the ability of our lessees to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.

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

	•	Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from our properties.

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

	•	Our lessees’ work forces could become increasingly unionized in the future.

	•	We may be exposed to changes in interest rates because our current borrowings under our revolving credit facility may be subject to variable interest rates based upon LIBOR.

	•	Our lessees are subject to federal, state and local laws and regulations that may limit their ability to produce and sell coal from our properties.

We are exposed to market risk, which includes adverse changes in commodity prices and interest rates as discussed below:

We are dependent upon the efficient marketing of the coal mined by our lessees. Our lessees sell the coal under various long-term and short-term contracts as well as on the spot market. In previous years, a large portion of these sales were under long term contracts. Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts with terms of one year or more. We estimate that 80% of our coal is sold by our lessees under coal supply contracts that have terms of one year or more. Our lessees’ failure to negotiate long-term contracts could adversely affect the stability and

Our exposure to changes in interest rates results from our current borrowings under our revolving credit facility, which may be subject to variable interest rates based upon LIBOR. As of December 31, 2003, we did not have any financial instruments in place to hedge our interest rate risk because interest rates have remained at historically low levels. In May 2003, in anticipation of the issuance of $125 million of senior unsecured notes, we entered into a treasury rate lock agreement for up to $50 million of the debt. Upon closing of the senior notes in June 2003, we paid $1.4 million to settle the treasury rate agreement. However, because a portion of the treasury rate instrument did not qualify as a hedge for accounting purposes, we expensed $0.5 million in 2003, and $0.9 million is being amortized over the 20 year term of the applicable note. Management intends to monitor interest rates and may enter into interest rate instruments to protect against increased borrowing costs. At December 31, 2003, we had outstanding $27.0 million of variable interest rate debt. If LIBOR rates were to increase by 100 basis points, annual interest expense would increase by $270,000, assuming the same principal amount remained outstanding during the year.

We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2003 and 2002, and the related consolidated statements of income, partners’ capital and cash flows for the year ended December 31, 2003 and for the period from commencement of operations (October 17, 2002) through December 31, 2002. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Natural Resource Partners L.P. at December 31, 2003 and 2002, and the consolidated results of its operations and its cash flows for the year ended December 31, 2003 and for the period from commencement of operations (October 17, 2002) through December 31, 2002, in conformity with accounting principles generally accepted in the United States.

Natural Resource Partners L.P. (the “Partnership”), a Delaware limited partnership, was formed in April 2002 to own and manage certain coal royalty producing properties contributed to the Partnership by Western Pocahontas Properties Limited Partnership, (“WPP”), Great Northern Properties Limited Partnership, (“GNP”), New Gauley Coal Corporation, (“NGCC”) and Arch Coal, Inc. (“Arch”) (collectively “predecessors” or “predecessors companies”). The predecessor companies contributed assets to the Partnership on October 17, 2002. There were no operations in the Partnership prior to the contribution of the assets from the predecessor companies. Therefore, the statements of income, partners’ capital and cash flows are presented from the date of commencement of operations (October 17, 2002) through December 31, 2002.

The chief executive officer of GP Natural Resource Partners LLC controls the general partners of WPP and GNP and is the controlling shareholder of NGCC. He also controls the general partner of the Partnership. In accordance with EITF 87-21, “Change of Accounting Basis in Master Limited Partnership Transactions”, the assets of WPP, GNP and NGCC were contributed to the Partnership at historical costs. The assets contributed by Arch, which consisted solely of land, coal reserves and minerals and other rights were recorded at their fair values.

We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. As of December 31, 2003, we controlled approximately 1.6 billion tons of proven and probable coal reserves in eight states. We do not operate any mines. We lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine our coal reserves in exchange for royalty payments. Our lessees are generally required 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 sold, in addition to a minimum payment.

The Partnership completed its initial public offering of 2,598,750 common units at a price of $20.00 per unit on October 17, 2002 and received aggregate gross proceeds of $52.0 million. Since the underwriters did not exercise their over-allotment option, GNP and NGCC purchased an additional 75,503 common units at a price of $20.00 per unit for aggregate gross proceeds of $1.5 million, resulting in aggregate gross proceeds of $53.5 million. In addition, WPP, GNP, NGCC and Arch contributed $0.9 million to cover transaction costs and expenses in excess of those covered by proceeds of the public offering.

Underwriting fees in connection with the offering were $3.6 million. The Partnership’s net proceeds from the offering, the purchase of common units by GNP and NGCC and the contribution by WPP, GNP, NGCC and Arch totaled $51.8 million. The Partnership used approximately $46.5 million of the proceeds to repay debt that was assumed from WPP, GNP and NGCC, $1.3 million to cover fees related to its revolving credit facility and $3.0 million to cover expenses related to its initial public offering, which consisted primarily of legal, accounting and other professional service costs. The remaining $1.0 million of proceeds was used to establish working capital necessary for the operation of the Partnership’s business.

Concurrent with the sale of common units to the public, Arch sold 1,901,250 common units to the public at a price of $20.00 per unit resulting in aggregate gross proceeds of $38 million and net proceeds of $35.4 million. In addition, Arch contributed $0.4 million and $0.6 million to the Partnership to establish working capital and cover fees related to the Partnership’s revolving credit facility.

On December 22, 2003, an investor group comprising Corbin J. Robertson, Jr., Chairman and Chief Executive Officer of GP Natural Resource Partners LLC, together with First Reserve Corporation and the management of the Partnership, purchased the subordinated units of Arch for $111 million. In addition, Mr. Robertson and a private group of investors consisting of individual partners in the WPP Group purchased the interests in the Partnership’s general partner and the incentive distribution rights in the Partnership held by Arch for $4 million.


	•	all of its interests in GP Natural Resource Partners LLC to Robertson Coal Management LLC;

	•	all of its interests in NRP (GP) LP, together with all of its incentive distribution rights, to NRP Investment L.P., an affiliate of the WPP Group; and

	•	4,796,920 subordinated units of Natural Resource Partners L.P. to FRC-WPP NRP Investment L.P., an affiliate of the WPP Group and First Reserve GP IX, Inc.

The transactions did not include the 2,895,670 common units owned by Arch. Arch retained the right to elect two directors, including one independent director, to the board of directors of GP Natural Resource Partners LLC for so long as Arch continues to hold at least 10% of the common units of Natural Resource Partners. In connection with the sale, the board of directors of GP Natural Resource Partners LLC was expanded to nine members, and FRC-WPP NRP Investment L.P., which is indirectly controlled by First Reserve GP IX, Inc., obtained the right to elect two directors to the board, one of whom must be an independent director.

First Reserve, which has the right to nominate two members to our Board of Directors, has a controlling interest in Alpha Natural Resources, which was our largest lessee based on coal royalty revenues, in 2003. We have entered into a number of coal mining leases with Alpha through a combination of new leases entered into upon our purchase of the Alpha property and through leases we had with entities which Alpha acquired.

The general partner of the Partnership is NRP (GP) LP, a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company.

The financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries. Intercompany transactions and balances have been eliminated.

Certain reclassifications have been made to the prior year’s balance sheet to conform to current year classifications.

Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents.

Land, coal and mineral rights are carried at historical cost for properties contributed by WPP, GNP and NGCC. The coal mineral rights contributed by Arch as well as the Partnership’s acquisitions have been accounted for using purchase accounting based on their estimated fair value. Coal mineral rights owned and

leased are depleted on a unit-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein, or upon the amortization period of the contractual rights.

If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset will not be recoverable, as determined based on projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value.

Substantially all of the Partnership’s accounts receivable result from amounts due from third-party companies in the coal industry. This concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be affected by changes in economic or other conditions. Receivables are generally not collateralized. Historical credit losses incurred by the Partnership on receivables have not been significant.

The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying value of these financial instruments approximate fair value, due to their short-term nature or variable interest rates that reflect market rates.

Deferred financing costs consists of legal and other costs related to the issuance of the Partnership’s revolving credit facility and senior unsecured notes. These costs are amortized over the term of the debt.

Coal Royalties. Coal royalty revenues are recognized on the basis of tons of coal sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the coal lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.

Minimum Royalties. Most of the Partnership’s lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue. The deferred revenue attributable to the minimum payment is recognized as coal royalty revenues either when the lessee recoups the minimum payment through production or when the period during which the lessee is allowed to recoup the minimum payment expires.

Oil and Gas Royalties. Oil and gas royalties are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the lessees make payments based on a percentage of the selling price. Some are subject to minimum annual payments or delay rentals. The minimum annual payments that are recoupable are generally recoupable over certain periods. The minimum payments are initially recorded as deferred revenue and recognized either when the lessee recoups the minimum payments through production or when the period during which the lessee is allowed to recoup the minimum payment expires.

The Partnership is responsible for paying property taxes on the properties it owns. The lessees are typically contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The reimbursement of property taxes is included in revenues in the statement of income as property taxes.

The Partnership is not a taxpaying entity, as the individual partners are responsible for reporting their pro rata share of the Partnership’s taxable income or loss. In the event of an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends SFAS No. 133 as a result of:


	•	Decisions previously made as part of the Derivatives Implementation Group (DIG) process;

	•	Changes made in connection with other FASB projects dealing with financial instruments; and

	•	Deliberations in connection with issues raised in relation to the application of the definition of a derivative.

accordance with their prior respective effective dates. The Partnership did not have any hedging instruments in place at December 31, 2003.

SFAS No. 150 is effective for public companies for all financial instruments created or modified after May 31, 2003, and to other instruments at the beginning of the first interim period beginning after June 15, 2003 (July 1, 2003 for calendar quarter companies). The adoption of SFAS No. 150 did not have any impact on the Partnership’s results of operations, financial position or liquidity.

In January 2003, the FASB issued FASB Interpretation No. 46 (“FIN No. 46”), “Consolidation of Variable Interest Entities.” The objective of this interpretation is to provide guidance on how to identify a variable interest entity (“VIE”) and determine when the assets, liabilities, noncontrolling interests, and results of operations of a VIE need to be included in a company’s consolidated financial statements. A company that holds variable interests in an entity will need to consolidate the entity if the company’s interest in the VIE is such that the company will absorb a majority of the VIE’s expected losses and/or receive a majority of the entity’s expected residual returns, if they occur. FIN No. 46 also requires additional disclosures by primary beneficiaries and other significant variable interest holders. FIN No. 46 was effective for all VIE’s created after January 31,2003. For VIE’s created prior to February 1, 2003, FIN No. 46 was to be effective for public companies on July 1, 2003. However, the FASB postponed that effective date to December 31, 2003. In December 2003, the FASB issued a revised FIN No. 46 (FIN No. 46R), which further delayed the effective date for public companies to March 31, 2004 for VIE’s created prior to February 1, 2003, except for interests in special purpose entities, for which a company must adopt either FIN No. 46 or FIN No. 46R as of December 31, 2003. Adoption of the requirements of FIN No. 46R is not expected to have a material impact on our consolidated financial position, results of operations or cash flows.

Historical practice in the extractive industry has been to classify leased mineral interest on the basis consistent with owned minerals due to similar rights of the lessor. SFAS No. 141, “Business Combinations, provides mineral rights as an example of a contract-based intangible asset that should be considered for separate classification as the result of a business combination. Due to the potential for inconsistencies in applying the provisions of SFAS No. 141 (and SFAS No. 142, “Goodwill and Other Intangible Assets”) in the extractive industries as they relate to mineral interests controlled by other than fee ownership, the Emerging Issues Task Force (the “EITF”) has established a Mining Industry Working Group that is currently addressing this issue. At December 31, 2003 and 2002, the Partnership’s coal acquisition costs for leased mineral interests were less than 6% of our total assets. The classification of the Partnership’s leased coal interest and contractual agreements may be revised depending upon the conclusions reached by the Mining Industry Working Group and the EITF. Any reclassification would not have an effect on net income or net cash flows.

On December 4, 2002, the Partnership purchased the land and mineral rights to approximately 108 million tons of coal and 164,000 acres of surface land for $57.0 million, including transaction costs, from certain subsidiaries of El Paso Corporation. El Paso Corporation retained an overriding royalty interest in certain assets.

On February 27, 2003, the Partnership purchased an overriding royalty interest in the coal reserves that were purchased from El Paso in December 2002, from a subsidiary of Alpha Natural Resources LLC for $11.85 million.

On April 10, 2003, the Partnership acquired more than 295,000 mineral acres containing over 353 million tons of coal reserves from two subsidiaries of Alpha Natural Resources, LLC for an aggregate purchase price of $53.625 million. The Partnership has, in turn, leased these reserves to the subsidiaries of Alpha Natural Resources, which will mine the coal and pay royalties to the Partnership. The acquisition was effective as of April 1, 2003.

On July 1, 2003, the Partnership acquired approximately 79 million tons of proven coal reserves and an overriding royalty interest on additional coal from subsidiaries of PinnOak Resources, LLC for $58 million. Simultaneous with the execution of the purchase and sale agreement, the Partnership placed the $58 million purchase price into an escrow account to be released at closing. The Partnership leased the reserves back to other subsidiaries of PinnOak Resources that mine the reserves and pay royalties to the Partnership. The overriding royalty interest is being paid to the Partnership on third party coal mined and processed by PinnOak Resources through its preparation plants on these properties. This overriding interest represents an increase to the coal and other mineral rights leased, net of $6.3 million.

In November 2003, the Partnership completed its acquisition of Kentucky coal reserves and related interests for a purchase price of $18.8 million. The acquisition includes approximately 21 million tons of coal reserves, an additional royalty interest in approximately 8 million tons of coal reserves on contiguous property, and a wheelage fee on 10 million tons of coal.

All of the acquisitions were initially funded utilizing the Partnership’s revolving credit facility. In June and September of 2003, the Partnership issued $125 million and $50 million, respectively, of senior unsecured notes, with the proceeds used to reduce the borrowings under the Partnership’s revolving credit facility.

The factors used in determining the fair market value of the assets acquired included, but were not limited to, discounted future net cash flows, the quality of the reserves, the probability of continued coal mining on the property, and marketability of the coal.

The Partnership’s coal and other mineral rights owned consists of the following:

The Partnership’s coal and other mineral rights leased consists of the following:

In connection with the Partnership’s initial public offering in October 2002, the Partnership through its wholly owned subsidiary, entered into a $100 million unsecured revolving credit facility, which matures in October 2005, when all principal payments are due in full. The revolving credit facility provides for the election of the interest rate at (i) LIBOR plus an applicable margin ranging from 1.25% to 1.75% based on certain financial data or (ii) the higher of the future funds rate plus 0.50% or the prime rate as announced by the agent bank. The facility includes a $12 million distribution loan sublimit that can be used for quarterly distributions. The remainder of the revolving credit facility is available for general limited partnership and limited liability company purposes, including future acquisitions, but may not be used to fund quarterly distributions. The financial covenants require the maintenance of a ratio of consolidated total indebtedness to consolidated EBITDA (as defined in the credit agreement) that are not to exceed 2.5 to 1.0 and a ratio of consolidated EBITDA to consolidated interest expense of at least 4.0 to 1.0. At December 31, 2002, $57.5 million was outstanding on the facility bearing interest at 2.72%.

On April 4, 2003, the Partnership increased the borrowing capacity under its credit facility to $175 million, and the other terms of the credit facility remained unchanged. The amended credit facility includes increased commitments from the original bank syndicate, led by PNC Bank, as well as commitments from three new banks.

On June 19, 2003 and simultaneous with the issuance of senior notes, the Partnership’s subsidiary adopted a second amendment to the credit facility. This amendment permitted NRP Operating to issue unsecured notes through a private placement in an amount up to $175 million, with a portion of the proceeds to be used to reduce the outstanding balance on the revolving credit facility. Among other items, this amendment increased the maximum leverage ratio from 2.75 to 1.00 to 3.50 to 1.0. Indebtedness under the revolving credit facility bears interest, at the Partnership’s option, at either (i) a rate equal to LIBOR plus an applicable margin ranging from 1.25% to 2.25% or (ii) the higher of the federal funds rate plus an applicable margin ranging from 0.25% to 0.75% or the prime rate as announced by the agent bank.

At December 31, 2003, $27 million was outstanding under the revolving credit facility bearing interest at a LIBOR rate of 3.17%. The Partnership incurs a commitment fee on the unused portion of the revolving credit facility at a rate of 0.50% per annum.

Proceeds from the issuance of the senior notes were used to repay borrowings under NRP Operating’s existing revolving credit facility and for expenses associated with the transaction. In anticipation of the private placement on May 12, 2003, NRP Operating entered into a treasury rate hedge with respect to $50 million of the senior notes. In connection with the closing of the private placement, NRP Operating paid $1.4 million to settle this treasury rate hedge. Of the $1.4 million paid for the settlement, approximately $0.9 million will be amortized into expense over 20 years, and the balance of approximately $0.5 million has been expensed in 2003 and classified as other income (expense) in the income statement. The terms under the private placement require that the Partnership to maintain a fixed charge coverage ratio of not less than 3.50 to 1.0 and a limit on consolidated debt to consolidated EBITDA of not more than 4.00 to 1.00.

Quintana Minerals Corporation, a company controlled by Corbin J. Robertson, Jr., Chairman and CEO of GP Natural Resource Partners LLC, provided certain administrative services to the Partnership and charged it for direct costs related to the administrative services. The total expenses charged to the Partnership under this arrangement were $1.0 and $0.1 million for the years ended December 31, 2003 and for the period from commencement of operations on October 17, 2002 to December 31, 2002, respectively. These costs are reflected in the general and administrative expenses in the accompanying statements of income.

WPP provides certain administrative services for the Partnership. The total expenses charged to the Partnership under this arrangement were $1.9 million for the year ended December 31, 2003 and $.3 million for the period from commencement of operations on October 17, 2002 to December 31, 2002. These costs are reflected in the general and administrative expenses in the accompanying statements of income.

At December 31, 2003, the Partnership had accounts receivable from affiliates of $1.4 million due from Arch which consisted of minimum royalties due on coal royalty leases that was paid in the first week of January 2004. The Partnership also had accounts payable to affiliates of $0.3 million, which includes general and administrative expense to Quintana Minerals Corporation, and WPP of $0.1 million and $0.1 million, respectively. On October 21, 2003, Arch entered into a Guaranty agreement with the Partnership whereby Arch agreed to pay the Partnership a minimum of $11.3 million in coal royalties with respect to their leases with NRP in 2004.

The Partnership is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Partnership management believes these claims will not have a material effect on the Partnership’s financial position, liquidity or operations.

The operations conducted on the Partnership’s properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Because Natural Resource Partners L.P. has no employees, Western Pocahontas employees provide regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. Management believes that the Partnership’s lessees will be able to comply with existing regulations and does not expect any lessee’s failure to comply with environmental laws and regulations to have a material impact on its financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties for the periods ended December 31, 2003 and 2002. The Partnership is not associated with any environmental contamination that may require remediation costs. However, lessees do, from time to time, conduct reclamation work on the properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, it is not responsible for the costs associated with these reclamation operations. All of our lessees are required to post bonds to cover reclamation costs. In the event these bonds are insufficient, some states, such as West Virginia have established funds to cover these shortfalls. The Partnership is also indemnified by WPP, GNP, NGCC and Arch Coal Inc., jointly and severally, for three years after the closing of the initial public offering against environmental and tax liabilities attributable to the ownership and operation of the assets contributed to the Partnership prior to the closing. The environmental indemnity is limited to a maximum of $10.0 million.

The Partnership has four lessees that generate a significant portion of its revenues. Revenues from major lessees that exceed ten percent of total revenues are as follows:

Prior to the Partnership’s initial public offering, GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the “Long-Term Incentive Plan”) for employees and directors of GP Natural Resource Partners LLC and its affiliates who perform services for the Partnership. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.

On August 19, 2003, the compensation committee amended the Long-Term Incentive Plan to provide only for the issuance of phantom units that are payable solely in cash. In connection with the amendment to the Long-Term Incentive Plan, the compensation committee terminated all of the existing option grants and issued to all of the holders of terminated options a number of phantom units equivalent in value to the terminated options.

A phantom unit entitles the grantee to receive the fair market value in cash of a common unit upon the vesting of the phantom unit. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as the compensation committee determines. The compensation committee will determine the period over which the phantom units granted to employees and directors will vest. In addition, the phantom units will vest upon a change in control of the Partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s phantom units will be automatically forfeited unless and to the extent the compensation committee provides otherwise.

GP Natural Resource Partners LLC adopted the Natural Resource Partners Annual Incentive Compensation Plan (the “Annual Incentive Plan”) in October 2002. The Annual Incentive Plan is designed to enhance the performance of GP Natural Resource Partners LLC’s and its affiliates’ key employees by rewarding them with cash awards for achieving annual financial and operational performance objectives. The compensation committee in its discretion may determine individual participants and payments, if any, for each year. The board of directors of GP Natural Resource Partners LLC may amend or change the Annual Incentive Plan at any time. The Partnership reimburses GP Natural Resource Partners LLC for payments and costs incurred under the Annual Incentive Plan.

There were 143,721 phantom units outstanding at December 31, 2003. The Partnership accrued expenses to be reimbursed to its general partner of $2.8 million for the year ended December 31, 2003 related to these plans, of which $0.5 million was paid in 2003.

In January 2004 the Partnership acquired all of the mineral interests of BLC Properties LLC for $73 million. The acquisition included coal, oil and gas and other mineral rights on approximately 270,000 acres that contain approximately 176 million tons of coal reserves. The transaction also included oil and gas and other mineral rights on approximately 205,000 additional acres. BLC retained a 35% non-participating royalty interest in the oil and gas and other mineral rights. The properties are located in Kentucky, Tennessee, West Virginia, and Alabama, and was funded utilizing the Partnership’s credit facility.

On January 22, 2004, the board of directors of GP Natural Resource Partners LLC declared a cash distribution of $0.5625 per unit. Total distributions of $13.0 million will be paid on February 13, 2004, to unitholders of record on February 2, 2004.


(1)	No financial data is present for these periods because Natural Resource Partners L.P. was not formed until April 9, 2002 and did not commence operations until October 17, 2002.

We have audited the accompanying statements of income, changes in partners’ capital and cash flows of Western Pocahontas Properties Limited Partnership for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Western Pocahontas Properties Limited Partnership for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

Western Pocahontas Properties Limited Partnership (“the Partnership”), a Delaware limited partnership, was formed in 1986 to own and manage land and mineral rights and timber located in West Virginia, Kentucky, Alabama, Maryland and Indiana. Western Pocahontas Corporation (“WPC”), a Texas corporation, serves as the general partner. All items of income and loss of the Partnership are allocated 1% to the general partner and 99% to the limited partners.

The Partnership enters into leases with various third-party operators for the right to mine coal reserves and harvest timber on the Partnership’s land in exchange for royalty payments. Generally, the coal lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments. The timber lessees make payments to the Partnership based on pre-determined rates per board foot harvested.

Land, coal property and timberlands are carried at cost and include expenditures for additions and improvements, such as roads and land improvements, which substantially increase the productive lives of the existing assets. Maintenance and repair costs are expensed as incurred. Coal properties are depleted on a unit-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein. Timberlands are depleted based on the volume of timber harvested in relation to the amount of estimated merchantable timber volume.

Deferred financing costs consists of legal and other costs related to the issuance of the Partnership’s long-term note payable. These costs are amortized over the term of the note payable.

Timber Royalties. Timber is sold on a contract basis where independent contractors harvest and sell the timber. Timber revenues are recognized when the timber has been harvested by the independent contractors.

The Partnership is responsible for paying property taxes on the properties it owns. The lessees are responsible for reimbursing the Partnership for property taxes on the leased properties. The reimbursement of property taxes is included in revenues in the statement of income as property tax.

The Partnership is not a taxpaying entity, as the individual partners are responsible for reporting their pro-rata share of the Partnership’s taxable income or loss. In the event of an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities.

In June 2001, the FASB issued SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets.” SFAS No. 141 eliminates pooling-of-interests accounting and requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. With regard to intangible assets, SFAS No. 141 states that intangible assets acquired in a business combination subsequent to June 30, 2001 should be recognized separately if the benefit of the intangible asset is obtained through contractual rights or if the intangible asset can be sold, transferred, licensed, rented to or exchanged, without regard to the acquirer’s intent. The adoption of SFAS No. 141 did not have a material impact on the 2001 or 2002 financial statements. SFAS No. 142 discontinues goodwill amortization; rather, goodwill will be subject to at least an annual fair-value based impairment test. The adoption of SFAS No. 142 on January 1, 2002 did not have a material impact on our financial statements.

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement cost being capitalized as a part of the carrying amount of the long-lived asset. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and a reconciliation of changes in the components of those obligations. The adoption of SFAS No. 143 on January 1, 2003 did not have a material impact on our financial statements.

In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of” and APB Opinion No. 30, “Reporting the Results of Operations — Reporting the Effects of the Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.” The objective of SFAS No. 144 is to establish one accounting model for long-lived assets to be disposed of by sale as well as resolve implementation issues related to SFAS No. 121. The adoption of SFAS No. 144 effective January 1, 2002 did not have a material impact on our financial position or results of operations.

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 62, Amendment of FASB Statement No. 13, and Technical Corrections.” Among other things, SFAS No. 145 will require gains and losses on extinguishments of debt to be classified as income or loss from continuing operations rather than as extraordinary items as previously required under SFAS No. 4. The provisions of this statement related to the rescission of SFAS No. 4 shall be applied in fiscal years beginning after May 15, 2002. Adoption of SFAS No. 145 on January 1, 2003 did not have a material impact on our financial position or results of operations. In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which supersedes EITF No. 94-3, “Liability Recognition for Certain Employment Termination Benefits and Other Costs to Exit an Activity.” SFAS No. 146 requires companies to record

liabilities for costs associated with exit or disposal activities to be recognized only when the liability is incurred instead of at the date of commitment to an exit or disposal activity. Adoption of this standard is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this standard did not have a significant impact on our financial statements.

The previous owner of the Partnership’s coal and timber properties (CSX Corporation and certain of its affiliates, or “CSX”) retained a reversionary interest in those properties whereby it receives either a 25% or 28% interest in the properties and the net revenues, as defined, from the properties after July 1, 2001, and in the net proceeds, as defined, from any property sale occurring prior to July 1, 2001.

In 2000, the Partnership sold 1,391 acres of surface land to a third party and paid $1.3 million to CSX related to its reversionary interest in the property. In 2001, the Partnership sold 1,928 acres of surface land to various third parties and paid $936,000 to CSX related to its reversionary interest in these properties (see Note 4).

In December 2001, the Partnership purchased from CSX its reversionary interest in the Partnership’s Kentucky properties for $2.0 million in cash and a note payable of $7.9 million (see Note 5). The Partnership allocated $8.8 million to coal and timber properties and $1.1 million to a reduction in the reversionary interest payable for the six months ended December 31, 2001.

In March 2002, the Partnership purchased from CSX its reversionary interest in the remaining assets subject to the reversionary interest. The Partnership allocated $35 million to coal and timber properties and $1.4 million to a reduction in the reversionary interest payable for the period ended October 16, 2002. The purchase was financed with a $45.0 million loan and a portion of the proceeds were used to retire the $7.9 million note that the Partnership issued in December 2001 as part of the consideration for the purchase of the reversionary interest in Kentucky (see Note 4).

The notes are collateralized by a mortgage on the Partnership’s properties, a security interest in accounts receivable, other assets and the partners’ interest in the Partnership and the common stock of WPC. The Partnership is required to maintain an aggregate minimum balance of $3.0 million in cash and cash equivalents, which is pledged to its lenders. The Partnership is allowed to make cash distributions to its partners provided no event of default exists, as defined, and the aggregate cash balance is not reduced below $4.0 million by any distribution.

The Partnership is required to contribute cash or cash equivalents to a debt service account when the Partnership receives royalties related to coal tonnage or timber harvested greater than a predetermined amount or sells certain properties. Pursuant to these provisions, the Partnership contributed $2.1 million and $2.4 million to the debt service account for the years ended December 31, 2000 and 2001, respectively.

On December 10, 2001, the Partnership issued a $7.9 million non-interest bearing note payable to an affiliate of CSX in conjunction with the purchase of CSX’s reversionary interest in properties located in Kentucky (see Note 3), and is subject to a Purchase and Sale Agreement between the CSX affiliate and the Partnership. The note was due and paid-off in March 2002. A discount of $152,000 was imputed for the period ended December 31, 2001 (see Note 3).

For the nine and one half months ended October 16, 2002 and the year ended December 31, 2001 the Partnership had interest expense of $4.8 million and $3.0 million relating to long term debt.

A company controlled by the owner of WPC provides certain administrative services to the Partnership and charges the Partnership for the direct costs related to the administrative services. The total expenses charged to the Partnership under this arrangement were approximately $500,000 for each of the years ended December 31, 2000 and 2001, and $330,000 for the period from January 1, 2002 through October 16, 2002. These costs are reflected in the general and administrative expenses in the accompanying statements of income.

The Partnership has a management contract to provide certain management, engineering and accounting services to Great Northern Properties Limited Partnership (“GNP”), a limited partnership which has certain common ownership with the Partnership. The contract provides for a $250,000 annual fee, which is intended to reimburse the Partnership for its expense. This fee is presented as other revenue in the accompanying statement of income. The contract may be canceled upon 90 days advance notice by GNP.

Substantially all employees of the Partnership are covered by a noncontributory retirement plan and a defined contribution thrift plan. Under the retirement plan, the Partnership contributes annually an amount equal to one-twelfth of each participant’s base compensation. Participants vest in the retirement plan based on the following:

A participant is fully vested upon termination of employment as a result of death, disability, reduction of labor force or retirement on or after age 55. For each of the years ended December 31, 2000 and 2001, the Partnership contributed approximately $90,000 to the retirement plan. No contribution was required during the period from January 1, 2002 through October 16, 2002.

Under the thrift plan, participants may contribute up to 12% of their base compensation, subject to a maximum set by IRS regulations, on a tax-deferred basis. The Partnership makes matching contributions equal to 100% of each participant’s contributions to the extent of 3% of base compensation and 50% of each participant’s contributions between 3% and 6% of base compensation. The Partnership’s contribution is 40% vested after two years of service with the vested interest increasing by 20% for each additional year of service. A participant is fully vested as to his own contributions and is fully vested as to the Partnership’s contributions upon termination of employment as a result of death, reduction of labor force, disability or retirement on or after age 55. For each of the years ended December 31, 2000 and 2001, the Partnership made matching contributions in an amount of approximately $50,000, and $28,277 during the period from January 1, 2002 through October 16, 2002.

The Partnership depends on a few lessees for a significant portion of its revenues. Revenues from major lessees that exceed ten percent of total revenues are as follows:

Segment information has been provided in accordance with SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information.” The Partnership’s reportable segments are as follows:

Coal Royalty. The coal royalty segment is engaged in managing the Partnership’s coal properties.

Timber Royalty. The Partnership’s timber segment is engaged in the selling of standing timber on the Partnership’s properties.

The following is a summary of certain financial information relating to the Partnership’s segments:

Total rental and lease expense for the year ended December 31, 2001 and for the period January 1, 2002 through October 16, 2002 were $142,000 and $114,000, respectively.

The operations conducted on Partnership properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental. The lessees obtain reclamation bonds and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Employees of the Partnership regularly visit the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. Management believes that the Partnership’s lessees will be able to comply with existing regulations and does not expect any material impact on its financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties for the years ended December 31, 2001, 2002 or the period ended October 16, 2002. The Partnership is not associated with any environmental contamination that may require remediation costs. However, our lessees do, from time to time, conduct reclamation work on our properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, it is not responsible for the costs associated with these reclamation operations. Each of our lessees is required to post a bond assuring that the reclamation will be completed as required by the permit. However, in the event any of our lessees is unable to complete the reclamation obligations and their

bonding company likewise fails to meet the obligations or provide money to the state to perform the reclamation, the Partnership could be held liable for these costs.

In connection with the formation of Natural Resource Partners L.P. and its public offering of limited partnership units, the Partnership transferred certain coal royalty producing properties that are currently under lease to coal mine operators to Natural Resource Partners L.P. on October 17, 2002, at historical cost. The Partnership also transferred a portion of its deferred revenue and long-term debt to Natural Resource Partners L.P. The Partnership retained a coal reserve property that is leased to a third party that is experiencing permitting problems. Additionally, the Partnership retained unleased coal reserve properties, surface land and timberlands.

We have audited the accompanying statements of income, changes in partners’ capital and cash flows of Great Northern Properties Limited Partnership for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Great Northern Properties Limited Partnership for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

Great Northern Properties Limited Partnership (“the Partnership”), a Delaware limited partnership, was formed in 1992 to own and manage land and mineral rights located in Montana, North Dakota, Wyoming, Illinois and Washington. GNP Management Corporation (“GNP”), a Delaware corporation, serves as its general partner. All items of income and loss of the Partnership are allocated 1% to the general partner and 99% to the limited partners. In 1999, a limited partner’s interest in the Partnership was redeemed by the partners for $1,000.

The Partnership enters into leases with various coal mine operators for the right to mine coal reserves on the Partnership’s land in exchange for royalty payments. Generally, the lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.

Land and coal property are carried at cost and include expenditures for additions and improvements, such as roads and land improvements, which substantially increase the productive lives of the existing assets. Maintenance and repair costs are expensed as incurred. Coal properties are depleted on a unit-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein.

Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s long-term debt. These costs are amortized over the term of the debt.

Coal Royalties. Coal royalty revenues are recognized on the basis of tons of coal sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.

Lease and Easement Income. Lease and easement income is generated through contracts with third parties for use of the Partnership’s land for transportation of coal mined on adjacent properties, agricultural grazing and recreational uses.

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement cost being capitalized as a part of the carrying amount of the long-lived asset. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and a reconciliation of changes in the components of those obligations. The adoption of SFAS No. 143 on January 1, 2003 did not have a material impact on our financial statements.

Benefits and Other Costs to Exit an Activity.” SFAS No. 146 requires companies to record liabilities for costs associated with exit or disposal activities to be recognized only when the liability is incurred instead of at the date of commitment to an exit or disposal activity. Adoption of this standard is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this standard did not have a significant impact on our financial statements.

The previous owner of the Partnership’s coal properties, Meridian Minerals Company (“Meridian”), a subsidiary of Burlington Resources, Inc., retained a nonparticipating royalty interest in certain properties, which were not leased at the time of acquisition, at a royalty rate ranging from 2% to 5%. Such properties are presently not leased. In the event any of the properties subject to the nonparticipating royalty interest are sold to a third party, Meridian will receive a certain percentage of the selling price as defined in the asset purchase agreement.

The notes are collateralized by a mortgage on the Partnership’s properties, a security interest in accounts receivable, other assets, the partners’ interest in the Partnership and the debt service account established by the Partnership. The debt service account is funded quarterly with 100% of the Partnership’s cash flows, defined as all cash revenue received by the Partnership, net of any operating expenses, management fees and up to a maximum of 20% of positive operating income to be used to pay the income tax liabilities of the partners as they relate to the Partnership properties, except that the Partnership may maintain $250,000 in cash for general operating purposes. The debt service account will be used to collateralize the notes until the balance of the account reaches a minimum of $10.0 million, after which the amount in excess of $10.0 million may be applied directly to the outstanding balance of the notes. The Partnership contributed $4.7 million and $2.2 million to the debt service account for the years ended December 31, 2000 and 2001, respectively, and $2.3 million for the period from January 1, 2002 through October 16, 2002.

For the nine and one half months ended October 16, 2002 and the year ended December 31, 2001 the Partnership had interest expense of $1.9 million and $3.7 million relating to long term debt.

The Partnership has a management contract to receive management, engineering and accounting services from Western Pocahontas Properties Limited Partnership (“WPP”), a limited partnership which has some common ownership with the Partnership. The contract provides for a $250,000 fee to be paid annually. Such amounts are reflected in general and administrative expenses in the statements of income. The contract may be canceled upon 90 days advance notice to the Partnership.

The Partnership depends on a few lessees for a significant portion of its revenues. Revenues from major lessees that exceed ten percent of total revenues are as follows:

The operations conducted on Partnership properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental. The lessees obtain reclamation bonds and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Employees regularly visit the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. Management believes that the Partnership’s lessees will be able to comply with existing regulations and does not expect any material impact on its financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties for the years ended December 31, 2000 and 2001 and for the period ended October 16, 2002. The Partnership is not associated with any environmental contamination that may require remediation costs. However, our lessees do, from time to time, conduct reclamation work on our properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, it is not responsible for the costs associated with these reclamation operations. Each of our lessees is required to post a bond assuring that the reclamation will be completed as required by the permit. However, in the event any of our lessees is unable to complete the reclamation obligations and their bonding company likewise fails to meet the obligations or provide money to the state to perform the reclamation, the Partnership could be held liable for these costs.

We have audited the accompanying statements of income, changes in stockholders’ deficit and cash flows of New Gauley Coal Corporation for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of New Gauley Coal Corporation for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

New Gauley Coal Corporation (“the Company”), a West Virginia subchapter S corporation, was incorporated in 1918 to own and manage land and mineral rights. The Company owns property in Alabama and West Virginia.

The Company enters into leases with various coal mine operators for the right to mine coal reserves on the Company’s land in exchange for royalty payments. Generally, the lessees make payments to the Company based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.

Deferred financing costs consist of legal and other costs related to the issuance of the Company’s long-term note payable. These costs are amortized over the term of the note payable.

Coal Royalties. Coal royalty revenues are recognized on the basis of tons of coal sold by the Company’s lessees and the corresponding revenue from those sales. Generally, the lessees make payments to the Company based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.

Minimum Royalties. Most of the Company’s lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue. The deferred revenue attributable to the minimum payment is recognized as coal royalty revenues either when the lessee recoups the minimum payment through production or when the period during which the lessee is allowed to recoup the minimum payment expires.

The Company is responsible for paying property taxes on the properties it owns. One of the lessees is not responsible for reimbursing the Company for property taxes on the leased properties. The reimbursement of property taxes is included in revenues in the statement of income as property tax.

The Company is not a taxpaying entity, as the individual stockholders are responsible for reporting their pro rata share of the Company’s taxable income or loss. In the event of an examination of the shareholders’ tax return, the tax liability of the shareholders could be changed if an adjustment in the shareholders’ income is ultimately sustained by the taxing authorities.

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement cost being capitalized as a part of the carrying amount of the long-lived asset. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and a reconciliation of changes in the components of those obligations. The adoption of SFAS No. 143 on January 1, 2003 did not have a material impact on our financial statements.

The previous owner of a portion of the Company’s coal properties (CSX Corporation and certain of its affiliates, or “CSX”) retained a reversionary interest in certain of those properties whereby it receives a 25% interest in the properties and the net revenues, as defined, from the properties after July 1, 2001, and in the net proceeds, as defined, of any property sale occurring prior to July 1, 2001. The reversionary interest only applies to the Company’s Alabama property. In March 2002, Western Pocahontas Properties Limited Partnership (the “Partnership”), who formerly owned the Company, purchased the reversionary interest from CSX. As a result of this transaction, the Alabama property is now owned 25% by the Partnership and 75% by the Company.

In June 2001, the Company loaned $200,000 to a third party. The agreement requires the third party to use the proceeds to develop certain coal properties it owned. In exchange for the loan, the Company will receive a royalty on coal produced from the developed properties. The total royalty received by the Company is limited to the greater of $200,000 plus 15% interest per year or $240,000. If no royalties are received by June 2005, the third party is required to repay the note with interest. Through the period ended October 16, 2002, the Company has accrued approximately $39,000 of interest income related to this note. This agreement may be terminated at any time by the third party by repaying the note under the terms described above.

The note is collateralized by a mortgage on the Company’s properties, a security interest in accounts receivable, other assets, the stockholders’ interest in the Company and the debt service account established by the Company. The notes are guaranteed by the Partnership.

The Company is required to contribute cash or cash equivalents to a debt service account when the Company receives royalties greater than a predetermined amount or sells qualified properties. The Company was not required to contribute to the debt service account for the years ended December 31, 2001, or the period ended October 16, 2002.

For the nine and one half months ended October 16, 2002 and the year ended December 31, 2001 the Partnership had interest expense of $0.1 million and $0.1 million relating to long term debt.

The Company depends on a few lessees for a significant portion of its revenues. Revenues from major lessees that exceed ten percent of total revenues are as follows:

The Company is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Company management believes these claims will not have a material effect on the Company’s financial position, liquidity or operations.

The operations conducted on Company properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Company may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Company’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental. The lessees obtain reclamation bonds and substantially all of the leases require the lessee to indemnify the Company against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Employees of the Company regularly visit the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. Management believes that the Company’s lessees will be able to comply with existing regulations and does not expect any material impact on its financial condition or results of operations. The Company has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties for the years ended December 31, 2001, and period ended October 16, 2002. The Company is not associated with any environmental contamination that may require remediation costs. However, our lessees do, from time to time, conduct reclamation work on our properties under lease to them. Because the Company is not the permittee of the mines being reclaimed, it is not responsible for the costs associated with these reclamation operations. Each of our lessees is required to post a bond assuring that the reclamation will be completed as required by the permit. However, in the event any of our lessees is unable to complete the reclamation obligations and their bonding company likewise fails to meet the obligations or provide money to the state to perform the reclamation, the Company could be held liable for these costs.

In connection with the formation of Natural Resource Partners L.P. and its public offering of limited partnership units, the Company transferred certain coal royalty producing properties that are currently under lease to coal mine operators to Natural Resource Partners L.P. on October 17, 2002 at historical cost The Company transferred a portion of its deferred revenue and all its long-term debt to Natural Resource Partners L.P. The Company retained unleased coal reserve properties.

We have audited the accompanying statements of revenues and direct costs and expenses of Arch Coal Contributed Properties for the period January 1, 2002 through October 16, 2002 and the year ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 1, the accompanying financial statements have been prepared solely to present the revenue and direct costs and expenses of the acquired properties for the period January 1, 2002 through October 16, 2002 and the year ended December 31, 2001, for the purpose of complying with the requirements of the Securities and Exchange Commission and are not intended to be a complete presentation of the financial position and results of operations of the acquired properties on a stand-alone basis.

In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct costs and expenses of Arch Coal Contributed Properties for the period January 1, 2002 through October 16, 2002 and the year ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

Ark Land Company (“Ark Land”) is a wholly owned subsidiary of Arch Coal, Inc. (“Arch Coal”). Ark Land owns and manages land and mineral rights primarily located in the Western, Central Appalachian and the Illinois Basins. In conjunction with the formation of Natural Resource Partners L. P. (“NRP”), Ark Land contributed a number of owned land and coal interests on which coal leasing activity occurs (“Contributed Properties”) to NRP. Ark Land retained owned land and mineral reserves with no leasing activity as well as other land and mineral reserves controlled through leasing arrangements. The accompanying statements have been prepared on Ark Land’s historical cost basis in the Contributed Properties.

The Contributed Properties was not a legal entity and, except for revenues earned from the properties and certain direct costs and expenses of the properties and assets acquired and liabilities assumed, no separate financial information was maintained. The Contributed Properties did not maintain stand-alone corporate treasury, legal, tax, human resources, general administration and other similar corporate support functions. Corporate general and administrative expenses have not been allocated to the Contributed Properties, nor were they allocated in connection with the preparation of the accompanying statements because there was not sufficient information to develop a reasonable cost allocation. Because the separate and distinct accounts necessary to present a balance sheet and income statements of the Contributed Properties were not maintained for the period from January 1 through October 16, 2002 and for the two years ended December 31, 2001. Statements of Revenues and Direct Costs and Expenses were prepared.

The accompanying Statements of Revenues and Direct Costs and Expenses and Statement of Assets Purchased and Liabilities Assumed are not intended to be a complete presentation of financial position and the results of operations of the Contributed Properties. The accompanying financial statements have been prepared to comply with the requirements of the Securities and Exchange Commission for inclusion in the annual report on Form 10-K of NRP.

With respect to cash flows, the Contributed Properties did not maintain cash accounts. Cash receipts and expenditures are maintained by Ark Land. A description of cash flows directly attributable to the Contributed Properties is included in Note 5.

Coal properties are carried at cost. Coal properties are depleted on a unit-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral properties and estimated proven tonnage therein. Depletion occurs either as Arch Coal mines on the property, or as others mine on the property through leasing transactions.

Coal Royalties. Coal royalty revenues are recognized on the basis of tons of coal sold by the Contributed Properties’ lessees and the corresponding revenue from those sales. Generally, the coal lessees make payments to the Contributed Properties based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.

Minimum Royalties. Most of the Contributed Properties’ lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue. The deferred revenue attributable to the minimum payment is recognized as coal royalty revenues either when the lessee recoups the minimum payment through production or when the period during which the lessee is allowed to recoup the minimum payment expires.

Ark Land is responsible for paying property taxes on the properties it owns. The lessees are responsible for reimbursing Ark Land for property taxes on the leased properties. The reimbursement of property taxes is included in revenues in the statement of revenues and direct costs and expenses as property tax.

While these financial statements are not intended to be a complete presentation of financial statements prepared in conformity with accounting principles generally accepted in the United States, the following recent accounting pronouncements are included in consideration of potential impacts associated with the accounts included in these financial statements.

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement cost being capitalized as a part of the carrying amount of the long-lived asset. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and a reconciliation of changes in the components of those obligations. The Contributed Properties have adopted SFAS No. 143 effective January 1, 2003 and it did not have a material affect.

Certain of the Contributed Properties were leased to affiliates of Arch Coal that mine on the properties. Contracted royalty rates from these affiliates (“affiliate royalties”) for the period from January 1, 2002 through October 16, 2002 and the two years ended December 31, 2001 were 6.5% of the gross sales price of coal sold from the property using underground mining methods and 7.5% of the gross sales price of coal sold from the property using surface mining methods, which are similar to those that are received from third parties. Affiliate royalties amounted to$7.7 million, $10.5 million and $10.2 million during the period from January 1, 2002 through October 16, 2002 and the two years ended December 31, 2001.

The Contributed Properties depended on a few lessees for a significant portion of its revenues. Revenues from major lessees that exceed 10% of total revenues, are as follows:

The Contributed Properties do not maintain cash accounts. Cash receipts and expenditures are maintained by Ark Land. However, the following information is provided to identify direct cash flows generated from the Contributed properties:

The operations conducted on our property by our lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, Ark Land may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of Ark Land’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental. The lessees obtain reclamation bonds and substantially all of the leases require the lessee to indemnify the Contributed Properties against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Employees of Ark Land regularly visit the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. Management of Ark Land believes that Ark Land’s lessees will be able to comply with existing regulations and does not expect any material impact on its financial condition or results of operations of the Contributed Properties. Ark Land has neither incurred, nor is aware of, any material environmental charges imposed on it related to the Contributed Properties for the period from January 1, 2002 to October 16, 2002 and the two years ended December 31, 2001.

In connection with the formation of Natural Resource Partners L.P. and the consummation of its initial public offering of limited partnership units, Arch Coal transferred certain coal royalty producing properties that are currently under lease to coal mine operators to Natural Resource Partners L.P. on October 17, 2002 at fair market value.

Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

We carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-14(c) of the Securities Exchange Act) as of December 31, 2003. This evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and procedures are effective in producing the timely recording, processing, summary and reporting of information and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure.

In addition, there have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that occurred during our last fiscal quarter and that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

As a master limited partnership we do not employ any of the people responsible for the management of our properties. Instead, we reimburse our managing general partner, GP Natural Resource Partners LLC, for its services. All directors and officers are elected by our managing general partner. The following table sets forth information concerning the directors and officers of GP Natural Resource Partners LLC. Each officer and director is elected for their respective office or directorship on an annual basis. Unless otherwise noted below, the individuals served as officers or directors of the partnership since the initial public offering.

Corbin J. Robertson, Jr. is the Chief Executive Officer and Chairman of the Board of Directors of GP Natural Resource Partners LLC. Mr. Robertson has served as the Chief Executive Officer and Chairman of the Board of the general partners of Western Pocahontas Properties Limited Partnership since 1986, Great Northern Properties Limited Partnership since 1992 and Quintana Minerals Corporation since 1978 and as Chairman of the Board of Directors of New Gauley Coal Corporation since 1986. Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation are all affiliates of Natural Resource Partners L.P. He also serves as Chairman of the Board of the Baylor College of Medicine and of the Cullen Trust for Higher Education and on the boards of the American Petroleum Institute, the National Petroleum Council, the Texas Medical Center and the World Health and Golf Association. Mr. Robertson is the father of Corbin J. Robertson III, the Vice President — Acquisitions.

Nick Carter is the President and Chief Operating Officer of GP Natural Resource Partners LLC. He has also served as President of the general partner of Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation since 1990 and as President of the general partner of Great Northern Properties Limited Partnership from 1992 to 1998. Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation are all affiliates of Natural Resource Partners L.P. Prior to 1990, Mr. Carter held various positions with MAPCO Coal Corporation and was engaged in the private practice of law. He is President of the National Council of Coal Lessors, the immediate past Chair of the West Virginia Chamber of Commerce and a board member of the Kentucky Coal Association.

Dwight L. Dunlap is the Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC. Mr. Dunlap has served as Vice President and Treasurer of Quintana Minerals Corporation and as Chief

Financial Officer, Treasurer and Secretary of the general partner of Western Pocahontas Properties Limited Partnership and Great Northern Properties Limited Partnership since 2000. Mr. Dunlap has worked for Quintana Minerals since 1982 and has served as Vice President and Treasurer since 1987. Mr. Dunlap is a Certified Public Accountant with over 25 years of experience in financial management, accounting and reporting including six years of audit experience with a Big Four international public accounting firm.

Kevin F. Wall is Vice President and Chief Engineer of GP Natural Resource Partners LLC. Mr. Wall has served as Vice President — Engineering for the general partner of Western Pocahontas Properties Limited Partnership since 1998 and the general partner of Great Northern Properties Limited Partnership since 1992. He has also served as the Vice President — Engineering of New Gauley Coal Corporation since 1998. He has performed duties in the land management, planning, project evaluation, acquisition and engineering areas since 1981. He is a Registered Professional Engineer in West Virginia and is a member of the American Institute of Mining, Metallurgical, and Petroleum Engineers and of the National Society of Professional Engineers. Mr. Wall also serves on the Board of Directors of Leadership Tri-State and is a past president of the West Virginia Society of Professional Engineers

Kathy E. Hager is Vice President — Investor Relations of GP Natural Resource Partners LLC. Ms. Hager joined NRP in July 2002. She was the Principal of IR Consulting Associates from 2001 to July 2002 and from 1980 through 2000 held various financial and investor relations positions with Santa Fe Energy Resources, most recently as Vice President — Public Affairs. She is a Certified Public Accountant. Ms. Hager has served on the local board of directors of the National Investor Relations Institute and has maintained professional affiliations with various energy industry organizations. She has also served on the Executive Committee and as a National Vice President of the Institute of Management Accountants.

Wyatt L. Hogan is Vice President, General Counsel and Secretary of GP Natural Resource Partners LLC. Mr. Hogan joined NRP in May 2003 from Vinson & Elkins L.L.P., where he practiced corporate and securities law from August 2000 through April 2003. Prior to joining Vinson & Elkins in August 2000, he practiced corporate and securities law at Andrews & Kurth L.L.P. from September 1997 through July 2000.

Corbin J. Robertson III is Vice President — Acquisitions of GP Natural Resource Partners LLC. Mr. Robertson was elected as an officer in October 2003. In addition to his duties at NRP, Mr. Robertson also co-manages a private hedge fund he founded in 2002 and serves as Vice President — Business Development for Quintana Minerals Corporation, a privately held oil and gas company that he joined in 1999. Mr. Robertson also served from 1996 to 1998 as a Vice President of Sandefer Capital Partners LLC, a private investment partnership focused on energy-related investments, and from 1994 to 1996 as a management consultant for Deloitte and Touche LLP. Mr. Robertson is the son of Corbin J. Robertson, Jr., the Chief Executive Officer and Chairman of the Board.

Kenneth Hudson is the Controller of GP Natural Resource Partners LLC. He has served as Controller of the general partner of Western Pocahontas Properties Limited Partnership and of New Gauley Coal Corporation since 1988 and of the general partner of Great Northern Properties Limited Partnership since 1992. He was also Controller of Blackhawk Mining Co., Quintana Coal Co. and other related operations from 1985 to 1988. Prior to that time, Mr. Hudson worked in public accounting.

Charles H. Kerr is the Assistant Secretary of GP Natural Resource Partners LLC. Mr. Kerr has worked for Quintana Minerals Corporation, an affiliate of the Partnership, where he is currently Vice President of Land/ Legal, since 1983. His responsibilities have included acquisitions and divestitures, land/ legal management and administration, strategic planning and contract and agreement negotiation and administration. Prior to joining Quintana, he worked for two independent oil and gas companies.

Robert T. Blakely joined the Board of Directors of GP Natural Resource Partners LLC in January 2003. He currently serves as Executive Vice President and Chief Financial Officer of MCI, Inc. From mid-2002 through mid-2003, he served as President of Performance Enhancement Group, which was formed to acquire manufacturers of high performance and racing components designed for automotive- and marine-engine applications. He previously served as Executive Vice President and Chief Financial Officer of Lyondell Chemical from 1999 through 2002, Executive Vice President and Chief Financial Officer of Tenneco, Inc.

from 1981 until 1999 as well as a Managing Director at Morgan Stanley. He served a four-year term on the Financial Accounting Standards Advisory Council and currently serves as a trustee of Cornell University, where he serves as Chairman of Cornell’s Finance Committee and a member of the Executive Committee of the Board.

David M. Carmichael is a member of the Board of Directors of GP Natural Resource Partners LLC. He currently is a private investor. Mr. Carmichael is the former Vice Chairman of KN Energy and the former Chairman and Chief Executive Officer of American Oil and Gas Corporation, CARCON Corporation and WellTech, Inc. He has served on the Board of Directors of Tom Brown, Inc. since 1997 and ENSCO International since 2001. He also currently serves as a trustee of the Texas Heart Institute.

Robert B. Karn III is a member of the Board of Directors of GP Natural Resource Partners LLC. He currently is a consultant and serves on the Board of Directors of various entities. He was the partner in charge of the coal mining practice worldwide for Arthur Andersen from 1981 until his retirement in 1998. He retired as Managing Partner of the St. Louis office’s Financial and Economic Consulting Practice. Mr. Karn is a Certified Public Accountant, Certified Fraud Examiner and has served as president of numerous organizations. He also currently serves on the Board of Directors of Peabody Energy Corp.

Alex T. Krueger is a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Krueger joined First Reserve Corporation in 1999 and is currently a Director of First Reserve focused on investment efforts in the coal and energy infrastructure sectors. Mr. Krueger also serves on the board of Alpha Natural Resources LLC, a significant lessee of NRP, as well as the boards of Pine Mountain Oil and Gas, Inc. and Aquilex Services Corporation. Prior to joining First Reserve, Mr. Krueger worked in the Houston office of Donaldson, Lufkin & Jenrette in the Energy Group.

S. Reed Morian is a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Morian has served as a member of the Board of Directors of the general partner of Western Pocahontas Properties Limited Partnership since 1986, New Gauley Coal Corporation since 1992 and the general partner of Great Northern Properties Limited Partnership since 1992. Mr. Morian has worked for Dixie Chemical Company since 1971 and has served as its Chairman and Chief Executive Officer since 1981. He has also served as Chairman, Chief Executive Officer and President of DX Holding Company since 1989.

David B. Peugh is a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Peugh has also served as Vice President — Business Development of Arch Coal, Inc. since 1995. He is also a director of ZECA Corporation, a company developing an emission-free process of producing electricity from coal.

W. W. Scott, Jr. is a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Scott was Executive Vice President and Chief Financial Officer of Quintana Minerals Corporation from 1985 to 1999. He served as Executive Vice President and Chief Financial Officer of the general partner of Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation from 1986 to 1999. He served as Executive Vice President and Chief Financial Officer of the general partner of Great Northern Properties Limited Partnership from 1992 to 1999. Since 1999, he has continued to serve as a director of the general partner of Western Pocahontas Properties Limited Partnership and Quintana Minerals Corporation.

The Board of Directors has determined that Messrs. Blakely, Carmichael and Karn are independent under the standards set forth in Section 303.01(B)(2)(a) and (3) of the New York Stock Exchange’s listing standards and under Item 7(d)(3)(iv) of Schedule 14A under the Securities Exchange Act of 1934. Because we are a limited partnership and a “controlled company” as defined in Section 303A of the New York Stock Exchange’s listing standards, we are not required to have a majority of independent directors. The Board has three committees staffed solely by independent directors.


*	Determined to be Audit Committee Financial Experts pursuant to Item 401(h) of Regulation S-K.

     Compensation, Nominating and Governance Committee:
          David M. Carmichael – Chairman
          Robert T. Blakely – Member
          Robert B. Karn, III – Member

     Conflicts Committee:
          Robert T. Blakely – Chairman
          Robert B. Karn, III – Member
          David M. Carmichael – Member

Our Audit Committee is composed entirely of independent directors. The members of the Audit Committee meet the independence and experience requirements of the New York Stock Exchange. The Committee has adopted, and annually reviews, a charter outlining the practices it follows. The charter complies with all current regulatory requirements.

During the year 2003, at each of its meetings, the Committee met with the senior members of our financial management team, our general counsel and our independent auditors. The Committee had private sessions at certain of its meetings with our independent auditors at which candid discussions of financial management, accounting and internal control issues took place.

The Committee recommended to the Board of Directors the engagement of Ernst & Young LLP as our independent auditors for the year ended December 31, 2003 and reviewed with our financial managers and the independent auditors overall audit scopes and plans, the results of internal and external audit examinations, evaluations by the auditors of our internal controls and the quality of our financial reporting.

Management has reviewed the audited financial statements in the Annual Report with the Audit Committee, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant accounting judgments and estimates, and the clarity of disclosures in the financial statements. In addressing the quality of management’s accounting judgments, members of the Audit Committee asked for management’s representations and reviewed certifications prepared by the Chief Executive Officer and Chief Financial Officer that our unaudited quarterly and audited consolidated financial statements fairly present, in all material respects, our financial condition and results of operations, and have expressed to both management and auditors their general preference for conservative policies when a range of accounting options is available.

The Committee also discussed with the independent auditors other matters required to be discussed by the auditors with the Committee under Statement on Auditing Standards No. 61, as amended by Statement on Auditing Standards No. 90 (communications with audit committees). The Committee received and discussed with the auditors their annual written report on their independence from the partnership and its management, which is made under Rule 3600T of the Public Company Accounting Oversight Board, which has adopted on an interim basis Independence Standards Board Standard No. 1 (independence discussions with audit committees), and considered with the auditors whether the provision of non-audit services provided by them to the partnership during 2003 was compatible with the auditors’ independence.

In performing all of these functions, the Audit Committee acts only in an oversight capacity. The Committee reviews our quarterly and annual reporting on Form 10-K and Form 10-Q prior to filing with the Securities and Exchange Commission. In 2003, the full Committee also reviewed quarterly earnings announcements in advance of their issuance with management and representatives of the independent auditor. In its oversight role the Committee relies on the work and assurances of our management, which has the primary responsibility for financial statements and reports, and of the independent auditors, who, in their

In reliance on these reviews and discussions, and the report of the independent auditors, the Audit Committee has recommended to the Board of Directors, and the Board has approved, that the audited financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2003, for filing with the Securities and Exchange Commission.

Section 16(a) of the Securities and Exchange Act of 1934 requires directors, officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of their equity securities. These people are also required to furnish us with copies of all Section 16(a) forms that they file. Based solely upon a review of the copies of Forms 3, 4 and 5 furnished to us, or written representations from certain reporting persons that no Forms 5 were required, we believe that our officers and directors complied with all filing requirements with respect to transactions in our equity securities during 2003, except that Arch Coal and each of Messrs. Carmichael, Karn, Morian and Scott filed a late Form 4, and Mr. Hogan filed a late Form 3.

We have adopted a Code of Business Conduct and Ethics that applies to our management, including our Chief Executive Officer, Chief Financial Officer and Controller, and that complies with Item 406 of Regulation S-K. Our Code of Business Conduct and Ethics is available on the internet at www.nrplp.com.

We have no executive officers, but we reimburse the general partner for compensation paid to the general partners’ executive officers in connection with managing us. We and our general partner were formed in April 2002, but did conduct any operations until the completion of the initial public offering of common units on October 17, 2002. The following table sets forth amounts reimbursed to affiliates of our general partner for compensation expense in 2002 and 2003.


(1)	Includes portions of automobile allowance, 401(k) matching and retirement contributions allocated to Natural Resource Partners by Quintana Minerals Corporation and Western Pocahontas Properties Limited Partnership.

(2)	Represents allocations for the period from commencement of operations (October 17, 2002) through December 31, 2002.

Corbin J. Robertson Jr., Chairman of the Board and CEO, did not receive any salary, bonus or other compensation during 2003 or 2002 that was reimbursed by us to the general partner.

Each director receives an annual retainer of $20,000, payable quarterly, plus additional fees of $2,000 annually for being a Committee Chairman and $500 per committee meeting. Each non-employee director also receives $1,000 for attending board meetings in person or $500 for participation in telephonic meetings. David B. Peugh has assigned any compensation he receives as a director of the general partner to Arch Coal, Inc., his employer. Additionally, each non-employee director of the general partner, other than Alex T. Krueger, received 10,000 unit options upon election to the board. In connection with the amendment to our Long-Term Incentive Plan discussed below, all of the unit options were terminated, and each director received a number of phantom units of equivalent value to the terminated options. On October 18, 2003, upon vesting of one-third of their phantom units, Messers. Carmichael, Karn, Scott, Morian, Leer and Peugh each received a payment of $44,371 representing the market value of one-third of their phantom units. Mr. Leer and Mr. Peugh each assigned their payments to Arch. On January 25, 2004, Mr. Blakely received a payment of $43,551 upon the vesting of one-third of his phantom units.

Prior to our initial public offering, GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan for employees and directors of GP Natural Resource Partners LLC and its affiliates who perform services for us. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.

A phantom unit entitles the grantee to receive the fair market value in cash of a common unit upon the vesting of the phantom unit. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as the compensation committee determines. The compensation committee will determine the period over which the phantom units granted to employees and directors will vest. In addition, the phantom units will vest upon a change in control of the partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s phantom units will be automatically forfeited unless and to the extent the compensation committee provides otherwise.


(1)	Based on closing price of $41.40 on December 31, 2003.

(2)	The number of units granted is not subject to minimum thresholds, targets or maximum payout conditions.

The general partner also adopted the Natural Resource Partners Annual Incentive Compensation Plan in October 2002. The annual incentive plan is designed to enhance the performance of GP Natural Resource Partners LLC and its affiliates’ key employees by rewarding them with cash awards for achieving annual financial and operational performance objectives. The compensation committee in its discretion may determine individual participants and payments, if any, for each fiscal year. The board of directors of GP Natural Resource Partners LLC may amend or change the annual incentive plan at any time. We will reimburse GP Natural Resource Partners LLC for payments and costs incurred under the plan.

The following table sets forth, as of March 1, 2004 the amount and percentage of our common and subordinated units beneficially held by (1) each person known to us to beneficially own 5% or more of the stock, (2) by each of the directors and executive officers and (3) by all directors and executive officers as a group. Unless otherwise noted, each of the named persons and members of the group has sole voting and investment power with respect to the units shown.


*	Less than one percent.

(1)	Based upon 11,353,658 common units issued and outstanding on March 1, 2004 and 11,353,658 subordinated units issued and outstanding on March 1, 2004. Unless otherwise noted, beneficial ownership is less than 1% of our units and subordinated units.

(2)	Mr. Robertson may be deemed to beneficially own the 3,158,166 common units and 5,231,766 subordinated units owned by Western Pocahontas Properties Limited Partnership, and 126,107 common units and 208,907 subordinated units owned by New Gauley Coal Corporation. Also included are 69,530 common units held by William K. Robertson 1992 Management Trust and 69,530 units held by Frances C. Robertson 1992 Management Trust, both of which Mr. Robertson is the trustee, and has voting control, but not direct ownership. Also included are 17,170 common units held by Barbara Robertson, Mr. Robertson’s spouse.

(3)	These units may be deemed to be beneficially owned by Mr. Robertson.

(4)	Arch Coal, Inc. is the parent company of Ark Land Company and may be deemed to beneficially own the units held by Ark Land Company.

(5)	The address of Western Pocahontas Properties Limited Partnership and Great Northern Properties Limited Partnership is 601 Jefferson Street, Suite 3600, Houston, Texas 77002. The address of Arch Coal, Inc. and Ark Land Company is One City Place Drive Suite 300, St. Louis, Missouri 63141. The address of First Reserve GP IX Inc. and FRC-WPP NRP Investment L.P. is One Lafayette Place, Greenwich, CT 06830.

(6)	The subordinated units are directly owned by FRC-WPP NRP Investment L.P. (the “Unit Holder”). FRC-WPP GP LLC (the “Investment GP”) is the general partner of the Unit Holder. FRC-NRP A.V. Holdings, L.P. (“A.V.”) holds a majority of the limited partnership interests and member interests of the Unit Holder and the Investment GP, respectively. FRC-NRP, Inc. (“Blocker”) and First Reserve GP IX, L.P. (“GP IX”) are the general partners of A.V., and First Reserve Fund IX, .P. (“Fund IX”) is the sole stockholder of Blocker. GP IX is the general partner of Fund IX, and First Reserve GP IX, Inc. (“First Reserve”) is the general partner of GP IX. Each of the Unit Holder, the Investment GP, A.V., Blocker, Fund IX and GP IX are controlled by First Reserve.

(7)	These officers purchased interests in FRC-WPP Investment L.P., which owns an approximate 37% limited partnership interest in FRC-WPP NRP Investment L.P., which purchased 4,796,920 subordinated units from Ark Land Company on December 22, 2003. Mr. Carter’s interest was purchased by his wife, Mary Carolyn Carter.

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing operation and any liquidation of Natural Resource Partners. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.


		approximately $1.0 million on its 2% general partner interest and our affiliates would receive distributions of approximately $15.0 million on their common units and $25.5 million on their subordinated units.

Payments to our general partner and its affiliates		Our general partner and its affiliates will not receive any management fee or other compensation for the management of our partnership. Our general partner and its affiliates will be reimbursed, however, for all direct and indirect expenses incurred on our behalf. Our general partner has the sole discretion in determining the amount of these expenses.

Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

As part of the omnibus agreement entered into among us, our general partner, the WPP Group, Arch Coal, Ark Land Company and Robertson Coal Management LLC concurrently with the closing of our initial public offering, the WPP Group, any entity controlled by Corbin J. Robertson, Jr. and Arch Coal, which we refer to in this section as the GP affiliates, each agreed that neither they nor their affiliates will, directly or indirectly, engage or invest in entities that engage in the following activities (each, a “restricted business”) in the specific circumstances described below:


	•	the entering into or holding of leases with a party other than an affiliate of the GP affiliate for any GP affiliate-owned fee coal reserves within the United States; and

	•	the entering into or holding of subleases with a party other than an affiliate of the GP affiliate for coal reserves within the United States controlled by a paid-up lease owned by any GP affiliate or its affiliate.

In connection with sale of Arch’s interest in our general partner, NRP Investment L.P. became a party to the omnibus agreement. “Affiliate” means, with respect to any GP affiliate or, any other entity in which such GP affiliate owns, through one or more intermediaries, 50% or more of the then outstanding voting securities or other ownership interests of such entity. Except as described below, the WPP Group, Arch Coal and their respective controlled affiliates will not be prohibited from engaging in activities in which they compete directly with us.


	•	the GP affiliate was engaged in the restricted business at the closing of the offering; provided that if the fair market value of the asset or group of related assets of the restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.

	•	the asset or group of related assets of the restricted business have a fair market value of $10 million or less; provided that if the fair market value of the assets of the restricted business subsequently exceeds


		$10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.

	•	the asset or group of related assets of the restricted business have a fair market value of more than $10 million and the general partner (with the approval of the conflicts committee) has elected not to cause us to purchase these assets under the procedures described below.

	•	its ownership in the restricted business consists solely of a noncontrolling equity interest.

For purposes of this paragraph, “fair market value” means the fair market value as determined in good faith by the relevant GP affiliate.

The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged in by the WPP Group, other than those engaged in by the WPP Group at closing of our initial public offering, may not exceed $75 million. For purposes of this restriction, the fair market value of any entity engaging in a restricted business purchased by the WPP Group will be determined based on the fair market value of the entity as a whole, without regard for any lesser ownership interest to be acquired. Arch Coal is not subject to a similar restriction on the total fair market value of restricted businesses it may own.

If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a fair market value in excess of $10 million and the restricted business constitutes greater than 50% of the value of the business to be acquired, then the WPP Group must first offer us the opportunity to purchase the restricted business. If (1) Arch Coal desires to acquire a restricted business or an entity that engages in a restricted business with a fair market value in excess of $10 million or (2) the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a value in excess of $10 million and the restricted business constitutes 50% or less of the value of the business to be acquired, then the GP affiliate may purchase the restricted business first and then offer us the opportunity to purchase the restricted business within six months of acquisition. For purposes of this paragraph, “restricted business” excludes a general partner interest or managing member interest, which is addressed in a separate restriction summarized below. For purposes of this paragraph only, “fair market value” means the fair market value as determined in good faith by the relevant GP affiliate.

If we want to purchase the restricted business and the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP affiliate and the general partner, with the approval of the conflicts committee, are unable to agree in good faith on the fair market value and other terms of the offer within 60 days after the general partner receives the offer, then the GP affiliate may sell the restricted business to a third party within two years for no less than the purchase price and on terms no less favorable to the GP affiliate than last offered by us. During this two-year period, the GP affiliate may operate the restricted business in competition with us, subject to the restriction on total fair market value of restricted businesses owned in the case of the WPP Group.

If, at the end of the two year period, the restricted business has not been sold to a third party and the restricted business retains a value, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, then the GP affiliate must reoffer the restricted business to the general partner. If the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the second offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP Affiliate and the general partner, with the concurrence of the conflicts committee, again fail to agree after negotiation in good faith on the fair market value of the restricted business, then the GP affiliate will be under no further obligation to us with respect to the restricted business, subject to the restriction on total fair market value of restricted businesses owned in the case of the WPP Group.

In addition, if during the two-year period described above, a change occurs in the restricted business that, in the good faith opinion of the GP affiliate, affects the fair market value of the restricted business by more than 10 percent and the fair market value of the restricted business remains, in the good faith opinion of the

If the restricted business to be acquired is in the form of a general partner interest in a publicly held partnership or a managing member interest in a publicly held limited liability company, the WPP Group may not acquire such restricted business even if we decline to purchase the restricted business. If the restricted business to be acquired is in the form of a general partner interest in a non-publicly held partnership or a managing member of a non-publicly held limited liability company, the WPP Group may acquire such restricted business subject to the restriction on total fair market value of restricted businesses owned and the offer procedures described above. If the restricted business to be acquired is in the form of a general partner interest in a partnership or a managing member interest in a limited liability company, Arch Coal may acquire such restricted business as part of a larger transaction so long as (1) it sells the interest to us or a third party within six months of the acquisition or (2) the general partner, with the approval of the conflicts committee, agrees that the restricted business will be subject to the offer procedures described in the preceding paragraphs without reference again to this paragraph. If, following the six month period, Arch Coal has made a good faith, reasonable attempt to divest the interest, but is unable to do so and Arch has not received an extension from our conflicts committee or has not offered us the opportunity to buy its competing interest, Arch Coal may opt to either (1) have its designated directors immediately resign from the board of directors of our general partner, in which case Arch Coal may continue to own and operate the competing business but will continue to relinquish its rights to designate directors of our general partner until such time as it divests the competing business, or (2) hire an independent investment banking firm to determine the fair market value of the competing business. If Arch Coal elects to obtain an independent valuation of its competing business, then:


	•	if Arch Coal and our general partner (with the concurrence of the conflicts committee) agree upon the price of the competing business, our partnership will purchase the competing business;

	•	if Arch Coal seeks to sell the competing business to our partnership at the price determined by the investment banking firm and our general partner (with the concurrence of the conflicts committee) declines to purchase the competing business, Arch Coal will be free to continue to own and operate the competing business;

	•	if Arch Coal does not wish to sell the competing business to our partnership at the price determined by the investment banking firm and our general partner (with the concurrence of the conflicts committee) seeks to purchase the competing business at such price, then Arch Coal’s designated directors must immediately resign from the board of directors of our general partner, in which case Arch Coal may continue to own and operate the competing business. Arch Coal will continue to relinquish its rights to designate directors of our general partner until it divests the competing business.

Under the omnibus agreement, the WPP Group and Arch Coal, jointly and severally, will indemnify us for (1) three years after the closing of the initial public offering against environmental liabilities associated with the properties contributed to us and occurring before the closing date of the initial public offering and (2) all tax liabilities attributable to the ownership or operation of the partnership assets prior to the closing of the initial public offering. The environmental indemnity will be limited to a maximum amount of $10.0 million. Liabilities resulting from a change in law after the closing of the offering are excluded from the environmental indemnity.

The omnibus agreement may be amended at any time by the general partner, with the concurrence of the conflicts committee. The respective obligations of the WPP Group and Arch Coal under the omnibus agreement terminate when the WPP Group and its affiliates, or Arch Coal and its affiliates, as the case may be, cease to participate in the control of the general partner.

For information relating to our leases with Ark Land Company, please see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Related Party Transactions.”

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the WPP Group, Arch Coal and First Reserve Corporation and its affiliates) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of GP Natural Resource Partners LLC have fiduciary duties to manage GP Natural Resource Partners LLC and our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and our partnership or any other partner, on the other, our general partner will resolve that conflict. Our general partner may, but is not required to, seek the approval of the conflicts committee of the board of directors of our general partner of such resolution. The partnership agreement contains provisions that allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. In effect, these provisions limit our general partner’s fiduciary duties to our unitholders. Delaware case law has not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties. The partnership agreement also restricts the remedies available to unitholders for actions taken by our general partner that might, without those limitations, constitute breaches of fiduciary duty.

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is considered to be fair and reasonable to us. Any resolution is considered to be fair and reasonable to us if that resolution is:


	•	approved by the conflicts committee, although our general partner is not obligated to seek such approval and our general partner may adopt a resolution or course of action that has not received approval;

	•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

	•	fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In resolving a conflict, our general partner, including its conflicts committee, may, unless the resolution is specifically provided for in the partnership agreement, consider:


	•	the relative interests of any party to such conflict and the benefits and burdens relating to such interest;

	•	any customary or accepted industry practices or historical dealings with a particular person or entity;

	•	generally accepted accounting practices or principles; and

	•	such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

Conflicts of interest could arise in the situations described below, among others.

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:


	•	amount and timing of asset purchases and sales;

	•	cash expenditures;

	•	borrowings;

	•	the issuance of additional units; and

	•	the creation, reduction or increase of reserves in any quarter.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the unitholders, including borrowings that have the purpose or effect of:


	•	enabling our general partner to receive distributions on any subordinated units held by our general partner or the incentive distribution rights; or

	•	hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and subordinated units, our partnership agreement permits us to borrow funds which may enable us to make this distribution on all outstanding units.

The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us or our subsidiaries.

We do not have any officers or employees and rely solely on officers and employees of GP Natural Resource Partners LLC and its affiliates.

We do not have any officers or employees and rely solely on officers and employees of GP Natural Resource Partners LLC, its affiliates and the employees of our subsidiaries. Affiliates of GP Natural Resource Partners LLC conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner. The officers of GP Natural Resource Partners LLC are not required to work full time on our affairs. These officers devote significant time to the affairs of the WPP Group or its affiliates and are compensated by these affiliates for the services rendered to them.

We reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us on the one hand, and our general partner and its affiliates, on the other, do not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the result of arm’s-length negotiations.

The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered to us, provided these services are rendered on terms that are fair and reasonable. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the

All of these transactions entered into after our initial public offering are on terms that are fair and reasonable to us.

Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. If we do not issue any equity securities prior to the expiration of the subordination period, upon the conversion of subordinated units into common units at the end of the subordination period, our general partner and its affiliates will own 81.1% of our outstanding common units and will be able to exercise this call right.

We may not choose to retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent auditors and others who have performed services for us in the past were retained by our general partner, its affiliates and us and have continued to be retained by our general partner, its affiliates and us. Attorneys, independent auditors and others who perform services for us are selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law has not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties.

The partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in our partnership agreement and in the omnibus agreement, affiliates of our general partner will not be prohibited from engaging in activities in which they compete directly with us. Please read “Omnibus Agreement.”

Corbin J. Robertson III, the son of our managing general partner’s Chief Executive Officer, Corbin J. Robertson, Jr., is Vice President Acquisitions for GP Natural Resource Partners LLC and is an employee of Quintana Minerals Corporation. Mr. Robertson was elected as an officer of the partnership in October 2003. During 2003, Quintana Minerals Corporation was reimbursed in the amount of $83,500 for services performed by Corbin J. Robertson III. In each of 2002 and 2003, he also received $5,000 in bonus payments. During 2003 he was also awarded 3,560 phantom units under the LTIP.

The Audit Committee of the Board of Directors of GP Natural Resource Partners LLC recommended and we engaged Ernst & Young LLP to audit our accounts and assist with tax work for fiscal 2003 and 2002. Fees (including out-of-pocket costs) incurred from Ernst & Young LLP for services for fiscal years 2003 and 2002 totaled $0.3 million and $0.3 million, respectively. All of our audit, audit related fees and services have been approved by our board of directors. The following table presents fees for professional services rendered by Ernst & Young LLP:


(1)	Audit fees include fees associated with the annual audit of our consolidated financial statements and reviews of our quarterly reports on Form 10-Q. Audit fees also include fees associated with reviews of registration statements.

(2)	There were no audit related fees.

(3)	Tax fees include fees principally incurred for assistance with tax planning, compliance, tax return preparation and filing of Schedules K-1.

(4)	There were no other services or fees.

Under the Sarbanes-Oxley Act of 2002 (the “Act”), the Audit Committee of the Board of Directors is responsible for the appointment, compensation and oversight of the work of the independent auditor. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by the independent auditor in order to assure that they do not impair the auditor’s independence from the Partnership. To implement these provisions of the Act, the Securities and Exchange Commission (the “SEC”) has issued rules specifying the types of services that an independent auditor may not provide to its audit client, as well as the audit committee’s administration of the engagement of the independent auditor. Accordingly, the Audit Committee has adopted, and the Board of Directors has ratified, this Audit and Non-Audit Services Pre-Approval Policy (the “Policy”), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent auditor may be pre-approved.

The SEC’s rules establish two different approaches to pre-approving services, which the SEC considers to be equally valid. Proposed services may either be pre-approved without consideration of specific case-by-case services by the Audit Committee (“general pre-approval”) or require the specific pre-approval of the Audit Committee (“specific pre-approval”). The Audit Committee believes that the combination of these two approaches in this Policy will result in an effective and efficient procedure to pre-approve services performed by the independent auditor. As set forth in this Policy, unless a type of service has received general pre-approval, it will require specific pre-approval by the Audit Committee if it is to be provided by the independent auditor. Any proposed services exceeding pre-approved cost levels or budgeted amounts will also require specific pre-approval by the Audit Committee.

For both types of pre-approval, the Audit Committee will consider whether such services are consistent with the SEC’s rules on auditor independence. The Audit Committee will also consider whether the independent auditor is best positioned to provide the most effective and efficient service for reasons such as its familiarity with our business, employees, culture, accounting systems, risk profile and other factors, and whether the service might enhance the Partnership’s ability to manage or control risk or improve audit quality. All such factors will be considered as a whole, and no one factor will necessarily be determinative.

The Audit Committee is also mindful of the relationship between fees for audit and non-audit services in deciding whether to pre-approve any such services and may determine, for each fiscal year, the appropriate ratio between the total amount of fees for audit, audit-related and tax services.

The appendices to this Policy describe the audit, audit-related and tax services that have the general pre-approval of the Audit Committee. The term of any general pre-approval is 12 months from the date of pre-approval, unless the Audit Committee considers a different period and states otherwise. The Audit Committee will annually review and pre-approve the services that may be provided by the independent auditor without obtaining specific pre-approval from the Audit Committee. The Audit Committee will add or subtract to the list of general pre-approved services from time to time, based on subsequent determinations.

The purpose of this Policy is to set forth the procedures by which the Audit Committee intends to fulfill its responsibilities. It does not delegate the Audit Committee’s responsibilities to pre-approve services performed by the independent auditor to management.

Ernst & Young LLP, our independent auditor has reviewed this Policy and believes that implementation of the policy will not adversely affect its independence.

As provided in the Act and the SEC’s rules, the Audit Committee has delegated either type of pre-approval authority to Robert B. Karn III, the Chairman of the Audit Committee. Mr. Karn must report, for informational purposes only, any pre-approval decisions to the Audit Committee at its next scheduled meeting.

The annual Audit services engagement terms and fees will be subject to the specific pre-approval of the Audit Committee. Audit services include the annual financial statement audit (including required quarterly reviews), subsidiary audits, equity investment audits and other procedures required to be performed by the independent auditor to be able to form an opinion on the Partnership’s consolidated financial statements. These other procedures include information systems and procedural reviews and testing performed in order to understand and place reliance on the systems of internal control, and consultations relating to the audit or quarterly review. Audit services also include the attestation engagement for the independent auditor’s report on management’s report on internal controls for financial reporting. The Audit Committee monitors the audit services engagement as necessary, but not less than on a quarterly basis, and approves, if necessary, any changes in terms, conditions and fees resulting from changes in audit scope, partnership structure or other items.

In addition to the annual audit services engagement approved by the Audit Committee, the Audit Committee may grant general pre-approval to other audit services, which are those services that only the independent auditor reasonably can provide. Other audit services may include statutory audits or financial audits for our subsidiaries or our affiliates and services associated with SEC registration statements, periodic reports and other documents filed with the SEC or other documents issued in connection with securities offerings.

Audit-related services are assurance and related services that are reasonably related to the performance of the audit or review of the Partnership’s financial statements or that are traditionally performed by the independent auditor. Because the Audit Committee believes that the provision of audit-related services does not impair the independence of the auditor and is consistent with the SEC’s rules on auditor independence, the Audit Committee may grant general pre-approval to audit-related services. Audit-related services include, among others, due diligence services pertaining to potential business acquisitions/dispositions; accounting consultations related to accounting, financial reporting or disclosure matters not classified as “Audit services”; assistance with understanding and implementing new accounting and financial reporting guidance from

rulemaking authorities; financial audits of employee benefit plans; agreed-upon or expanded audit procedures related to accounting and/or billing records required to respond to or comply with financial, accounting or regulatory reporting matters; and assistance with internal control reporting requirements.

The Audit Committee believes that the independent auditor can provide tax services to the Partnership such as tax compliance, tax planning and tax advice without impairing the auditor’s independence, and the SEC has stated that the independent auditor may provide such services. Hence, the Audit Committee believes it may grant general pre-approval to those tax services that have historically been provided by the auditor, that the Audit Committee has reviewed and believes would not impair the independence of the auditor and that are consistent with the SEC’s rules on auditor independence. The Audit Committee will not permit the retention of the independent auditor in connection with a transaction initially recommended by the independent auditor, the sole business purpose of which may be tax avoidance and the tax treatment of which may not be supported in the Internal Revenue Code and related regulations. The Audit Committee will consult with the Chief Financial Officer or outside counsel to determine that the tax planning and reporting positions are consistent with this policy.

Pre-approval fee levels or budgeted amounts for all services to be provided by the independent auditor will be established annually by the Audit Committee. Any proposed services exceeding these levels or amounts will require specific pre-approval by the Audit Committee. The Audit Committee is mindful of the overall relationship of fees for audit and non-audit services in determining whether to pre-approve any such services. For each fiscal year, the Audit Committee may determine the appropriate ratio between the total amount of fees for audit, audit-related and tax services.

All requests or applications for services to be provided by the independent auditor that do not require specific approval by the Audit Committee will be submitted to the Chief Financial Officer and must include a detailed description of the services to be rendered. The Chief Financial Officer will determine whether such services are included within the list of services that have received the general pre-approval of the Audit Committee. The Audit Committee will be informed on a timely basis of any such services rendered by the independent auditor.

Requests or applications to provide services that require specific approval by the Audit Committee will be submitted to the Audit Committee by both the independent auditor and the Chief Financial Officer, and must include a joint statement as to whether, in their view, the request or application is consistent with the SEC’s rules on auditor independence.

A current report on Form 8-K was furnished on November 5, 2003 in connection with disclosure of third quarter earnings and our outlook for 2003.

A current report on Form 8-K was filed on November 25, 2003 in connection with our acquisition of additional coal reserves in Kentucky.

A current report on Form 8-K was furnished on December 1, 2003 in connection with a presentation made by management at the Friedman Billings Ramsey 10th Annual Conference.

A current report on Form 8-K was filed on December 22, 2003 in connection with our acquisition of coal reserves from BLC Properties LLC and that acquisition by several investor groups of Arch Coal’s subordinated units and interests in GP Natural Resource Partners LLC and NRP (GP) LP.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.


	NATURAL RESOURCE PARTNERS L.P.


	By:	NRP (GP) LP, its general partner
	By:	GP NATURAL RESOURCE PARTNERS LLC,


	its general partner

Date: March 4, 2004


	By:	/s/ CORBIN J. ROBERTSON, JR.



	Corbin J. Robertson, Jr.,
	Chairman of the Board and Chief Executive Officer (Principal Executive Officer)

Date: March 4, 2004


	By:	/s/ DWIGHT L. DUNLAP



	Dwight L. Dunlap,
	Chief Financial Officer and Treasurer (Principal Financial Officer)

Date: March 4, 2004


	By:	/s/ KENNETH HUDSON



	Kenneth Hudson
	Controller (Principal Accounting Officer)

Date: March 4, 2004


	By:	/s/ DAVID M. CARMICHAEL



	David M. Carmichael
	Director


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

		For the fiscal year ended December 31, 2003

or

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

		For the transition period from to


Delaware		35-2164875
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)
610 Jefferson, Suite 3600 Houston, Texas (Address of principal executive offices)		77002 (Zip Code)


Title of Each Class		Name of Each Exchange on Which Registered

Common Units representing limited partnership interests		New York Stock Exchange


Item		Page

PART I
1 and 2.	Business and Properties		2
3.	Legal Proceedings		13
4.	Submission of Matters to a Vote of Securities Holders		13
PART II
5.	Market for Registrant’s Common Units and Related Unitholder Matters		14
6.	Selected Financial Data		16
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22
7A.	Quantitative and Qualitative Disclosures About Market Risk		44
8.	Financial Statements and Supplementary Data		46
9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure		95
9A.	Controls and Procedures		95
PART III
10.	Directors and Executive Officers of the General Partner		96
11.	Executive Compensation		101
12.	Security Ownership of Certain Beneficial Owners and Management		103
13.	Certain Relationships and Related Transactions		104
14.	Principal Accountant Fees and Services		111
PART IV
15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K		114
Long-Term Incentive Plan
1st Amendment to Long-Term Incentive Plan
Form of Coal Mining Lease
List of Subsidiaries
Consent of Ernst & Young LLP
Consent of Ernst & Young LLP
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906
Audited Balance Sheet of NRP (GP) LP



		Year Ended December 31,

Area		2003		2002		2001


		(In thousands)
Appalachia		$	63,855	$	40,688	$	31,719
Illinois Basin			3,566		2,994		3,155
Northern Powder River Basin			6,349		5,926		6,951

	Total	$	73,770	$	49,608	$	41,825



		Production Year Ended						Proven and Probable Reserves at
		December 31,						December 31, 2003

Area		2003		2002		2001		Underground		Surface		Total


		(Tons in thousands)
Appalachia			35,998		22,600		19,648		1,343,685		120,559		1,464,244
Illinois Basin			3,034		2,433		2,659		—		22,931		22,931
Northern Powder River Basin			5,312		5,474		6,683		—		156,153		156,153

	Total		44,344		30,507		28,990		1,343,685		299,643		1,643,328



				Sulfur Content								Typical Quality				Type of Coal

				Low
				(Less		Medium		High				Heat Content
		Compliance		than		(1.0% to		(Greater				(Btu per		Sulfur
Area		Coal(1)		1.0%)		1.5%)		than 1.5%)		Total		Pound)		(%)		Steam		Metallurgical(2)


		(Tons in thousands)														(Tons in thousands)
Appalachia			590,563		933,202		300,116		230,926		1,464,244		12,968		1.09		1,060,874		403,370
Illinois Basin			—		—		6,242		16,689		22,931		11,462		2.57		22,931		—
Northern Powder River Basin			—		156,153		—		—		156,153		8,441		0.75		156,153		—

	Total		590,563		1,089,355		306,358		247,615		1,643,328						1,239,958		403,370


Item 5.	*Market for Registrant’s Common Units and Related Unitholder Matters*



	Price Range
					Cash
	High		Low		Distributions

2002

Fourth Quarter	$	20.70	$	18.35	$	0.4234	(1)
2003

First Quarter	$	23.98	$	20.45	$	0.5225
Second Quarter	$	31.84	$	22.90	$	0.5225
Third Quarter	$	37.00	$	29.60	$	0.5375
Fourth Quarter	$	41.49	$	28.25	$	0.5625	(2)



		Marginal Percentage Interest in
		Distributions

						Holders of
	Total Quarterly					Incentive
	Distribution Target			General		Distribution
	Amount	Unitholders		Partner		Rights

Minimum Quarterly Distribution	$0.5125		98%		2%		—
First Target Distribution	$0.5125 up to $0.5625		98%		2%		—
Second Target Distribution	above $0.5625 up to $0.6625		85%		2%		13%
Third Target Distribution	above $0.6625 up to $0.7625		75%		2%		23%
Thereafter	above $0.7625		50%		2%		48%


					From
					commencement
					of operations
		For the			(October 17,			Year Ended
		year ended			2002) through			December 31,
		December 31,			December 31,
		2003			2002			2001		2000		1999

Income Statement Data:
Revenues:									(1)		(1)		(1)
	Coal royalties	$	73,770		$	11,532
	Property taxes		5,069			1,047
	Minimums recognized as revenue		2,033			872
	Override royalties		1,022			226
	Other		3,572			216

	Total revenues		85,466			13,893
Expenses:
	Depletion and amortization		25,365			4,526
	General and administrative		8,923			1,059
	Taxes other than income		5,810			1,296
	Override payments		386			226
	Coal royalty payments		913			171

	Total expenses		41,397			7,278

Income from operations			44,069			6,615
	Interest expense		(6,814	)		(200	)
	Interest income		206			—
	Loss on sale of assets		(55	)		—
	Loss from interest rate hedge		(499	)		—

Net income		$	36,907		$	6,415

Balance Sheet Data (at period end):
Total assets		$	531,676		$	392,719
Deferred revenue			15,054			13,252
Long-term debt			192,650			57,500
Total liabilities			223,518			74,085
Partners’ capital			308,158			318,634
Cash Flow Data:
Net cash flow provided by (used in):
	Operating activities	$	64,528		$	6,738
	Investing activities		(142,511	)		(57,449	)
	Financing activities		94,550			58,463
Other Data:
Royalty coal tons produced by Lessees			44,344			7,314
Average gross coal royalty per ton		$	1.66		$	1.58


		For the
		period
		from
		January 1
		through			Year ended December 31,
		October 16,
		2002(1)			2001			2000			1999

Income Statement Data:
Revenues:
	Coal royalties	$	17,261		$	15,458		$	11,585		$	15,754
	Timber royalties		2,774			3,691			4,236			3,770
	Gain on sale of property		92			3,125			3,982			205
	Property taxes		1,221			1,184			1,404			1,163
	Other		1,219			2,512			1,342			1,293

	Total revenues		22,567			25,970			22,549			22,185
Expenses:
	General and administrative		2,291			2,981			3,009			3,161
	Taxes other than income		1,438			1,457			1,701			1,447
	Depreciation, depletion and amortization		3,544			1,369			1,168			1,270

	Total expenses		7,273			5,807			5,878			5,878

Income from operations			15,294			20,163			16,671			16,307
Other income (expense):
	Interest expense		(4,786	)		(3,966	)		(4,167	)		(4,353	)
	Interest income		114			270			321			254
	Reversionary interest		(561	)		(1,924	)		—			—

Net income		$	10,061		$	14,543		$	12,825		$	12,208

Balance Sheet Data (at period end):
Total assets					$	88,224		$	76,510		$	76,089
Deferred revenue						7,916			7,468			7,301
Long-term debt						47,716			50,681			53,431
Total liabilities						68,055			61,584			64,038
Partners’ capital						20,169			14,926			12,051
Cash Flow Data:
Net cash flow provided by (used in):
	Operating activities	$	8,676		$	13,056		$	10,670		$	13,838
	Investing activities		(35,028	)		2,685			3,976			188
	Financing activities		27,899			(15,434	)		(14,630	)		(14,645	)
Other Data:
Royalty coal tons produced by Lessees			9,572			10,309			7,422			9,799
Average gross coal royalty per ton		$	1.80		$	1.50		$	1.56		$	1.61


(1)	Up to the date of contribution of assets to Natural Resource Partners L.P.


	(1) Up to the date of contribution of assets to Natural Resource Partners L.P.


						For the period from
						commencement of
						operations
						(October 17, 2002)
			For the year ended			through
			December 31, 2003			December 31, 2002


			(In thousands, except per ton data)
Revenues:
	Coal royalties		$	73,770		$	11,532
	Property taxes			5,069			1,047
	Minimums recognized as revenue			2,033			872
	Override royalties			1,022			226
	Other			3,572			216

	Total revenues			85,466			13,893
Expenses:
	Depletion and amortization			25,365			4,526
	General and administrative			8,923			1,059
	Taxes other than income			5,810			1,296
	Override payments			386			226
	Coal royalty payments			913			171

	Total expenses			41,397			7,278

Income from operations				44,069			6,615
Other income (expense):
	Interest expense			(6,814	)		(200	)
	Interest income			206			—
	Loss on sale of oil and gas properties			(55	)		—
	Loss from interest rate hedge			(499	)		—

Net income			$	36,907		$	6,415

Other Data:
Royalties
	Appalachia		$	63,855		$	9,492
	Illinois Basin			3,566			727
	Northern Powder River Basin			6,349			1,313

		Total	$	73,770		$	11,532

Production
	Appalachia			35,998			5,448
	Illinois Basin			3,034			601
	Northern Powder River Basin			5,312			1,265

		Total		44,344			7,314

Average gross royalty
	Appalachia		$	1.77		$	1.74
	Illinois Basin			1.18			1.21
	Northern Powder River Basin			1.20			1.04

		Total	$	1.66		$	1.58


	*Year ended December 31, 2003 compared to the period from commencement of operations (October 17, 2002) through December 31, 2002*


		For the period from
		January 1, through			Year Ending
		October 16, 2002			December 31, 2001

Revenues:
	Coal royalties	$	17,261		$	15,458
	Timber royalties		2,774			3,691
	Gain on sale of property		92			3,125
	Property taxes		1,221			1,184
	Other		1,219			2,512

	Total revenues		22,567			25,970
Expenses:
	General and administrative		2,291			2,981
	Taxes other than income		1,438			1,457
	Depreciation, depletion and amortization		3,544			1,369

	Total expenses		7,273			5,807

Income from operations			15,294			20,163
Other income (expense):
	Interest expense		(4,786	)		(3,966	)
	Interest income		114			270
	Reversionary interest		(561	)		(1,924	)

Net income		$	10,061		$	14,543

Production			9,572			10,309
Average gross royalty per ton		$	1.80		$	1.50



	Payments due by period(1)

Contractual Obligations	Total		2004		2005		2006		2007		2008		Thereafter

Long-term debt (including current maturities)	$	279.30	$	18.30	$	44.82	$	17.33	$	16.86	$	16.37	$	165.62


			Page

Natural Resource Partners L.P.:
	Report of independent auditors			47
	Balance sheets as of December 31, 2003 and 2002			48
	Income statements for the year ended December 31, 2003 and from commencement of operations (October 17, 2002) through December 31, 2002			49
	Statements of partner’s capital for the year ended December 31, 2003 and from commencement of operations (October 17, 2002) through December 31, 2002			50
	Statements of cash flows for the year ended December 31, 2003 and from commencement of operations (October 17, 2002) through December 31, 2002			51
	Notes to financial statements			52
The WPP Group:
	Western Pocahontas Properties Limited Partnership:
		Report of independent auditors		63
		Statements of income for the period ended October 16, 2002 and the year ended December 31, 2001		64
		Statements of changes in partners’ capital for the period ended October 16, 2002 and the year ended December 31, 2001		65
		Statements of cash flows for the period ended October 16, 2002 and the year ended December 31, 2001		66
		Notes to financial statements		67
	Great Northern Properties Limited Partnership:
		Report of independent auditors		74
		Statements of income for the period ended October 16, 2002 and year ended December 31, 2001		75
		Statements of changes in partners’ capital for the period ended October 16, 2002 and the year ended December 31, 2001		76
		Statements of cash flows for the period ended October 16, 2002 and the year ended December 31, 2001		77
		Notes to financial statements		78
	New Gauley Coal Corporation:
		Report of independent auditors		82
		Statements of income for the period ended October 16, 2002 and the year ended December 31, 2001		83
		Statements of changes in stockholders’ deficit		84
		Statements of cash flows for the period ended October 16, 2002 and the year ended December 31, 2001		85
		Notes to financial statements		86
Arch Coal, Inc. Contributed Properties:
	Report of independent auditors			90
	Statements of revenues and direct costs and expenses for the period ended October 16, 2002 and the year ended December 31, 2001			91
	Notes to financial statements			92


															Accumulated
		Common Units					Subordinated Units					General			Other
												Partner			Comprehensive
		Units		Amounts			Units		Amounts			Amounts			Loss			Total

Balance at commencement of operations (October 17, 2002)			—	$	1			—		—		$	—		$	—		$	1
	Net assets contributed by sponsors on October 17, 2002		8,679,405		96,691			11,353,658		160,179		$	6,538			—			263,408
	Additional contribution by sponsors		—		1,847			—		—			—			—			1,847
	Issuance of units to the public, net of offering and other costs		2,598,750		45,453			—		—			—			—			45,453
	Additional units purchased by GNP and NGCC		75,503		1,510			—		—			—			—			1,510
	Net income for the period from commencement of operations (October 17, 2002) through December 31, 2002		—		3,144			—		3,143			128			—			6,415

Balance at December 31, 2002			11,353,658	$	148,646			11,353,658	$	163,322		$	6,666					$	318,634
Distributions to unitholders			—		(22,774	)		—		(22,774	)		(930	)		—			(46,478	)
Net income for the year ended December 31, 2003			—		18,084			—		18,085			738			—			36,907
Loss on interest hedge			—		—			—		—			—			(905	)		(905	)

Other comprehensive income			—		—			—		—			—			—			36,002
Balance at December 31, 2003			11,353,658	$	143,956			11,353,658	$	158,633		$	6,474		$	(905	)	$	308,158


							From
							commencement of
				For the year			operations
				ended			(October 17, 2002)
				December 31,			through
				2003			December 31, 2002

Cash flows from operating activities:
	Net income			$	36,907		$	6,415
	Adjustments to reconcile net income to net cash provided by operating activities:
			Depletion and amortization		25,365			4,526
			Non-cash interest charge		26			—
			Loss on sale of oil and gas properties		55			—
	Change in operating assets and liabilities:
			Accounts receivable		(1,947	)		(9,043	)
			Other assets		(811	)		(511	)
			Accounts payable and accrued liabilities		(193	)		1,602
			Deferred revenue		1,802			2,018
			Cash paid on accrued incentive plans		(507	)		—
			Accrued incentive plan expenses		2,763			—
			Property and franchise taxes payable		1,068			1,731

			Net cash provided by operating activities		64,528			6,738

Cash flows from investing activities:
	Acquisition of coal and other mineral rights				(142,541	)		(57,449	)
	Proceeds from sale of oil and gas properties				30			—

			Net cash used in investing activities		(142,511	)		(57,449	)

Cash flows from financing activities:
	Proceeds from loans				317,100			57,500
	Deferred financing costs				(2,541	)		(1,316	)
	Repayment of loans				(172,600	)		(46,531	)
	Distributions to partners				(46,478	)		—
	Contributions by sponsors				—			1,847
	Proceeds from initial sale of common units net of transaction costs				—			45,453
	Proceeds from sale of common units to GNP and NGCC Distributions to partners				—			1,510
	Settlement of hedge included in accumulated other comprehensive loss				(931	)		—

			Net cash provided by financing activities		94,550			58,463

Net increase in cash					16,567			7,752
Cash at beginning of period					7,753			1

Cash at end of period				$	24,320		$	7,753

Supplemental cash flow information:
	Cash paid during the period for interest			$	5,778		$	—
Non-cash investing activities:
		Net assets contributed by partners			—			153,091
		Excess of cost over net book value of Arch properties			—			110,315
		Deferred revenue assumed on acquisition of property			—			(2,152	)


		First		Second		Third		Fourth
		Quarter		Quarter		Quarter		Quarter


		(Unaudited)
		(In thousands, except unit data)
2003
Total revenues		$	18,070	$	21,839	$	23,539	$	22,018
Operating income			8,392		11,757		12,555		11,365
Net income		$	7,973	$	10,183	$	10,112	$	8,639
Basic and diluted net income per limited partner unit:
	Common	$	0.34	$	0.44	$	0.44	$	0.37
	Subordinated	$	0.34	$	0.44	$	0.44	$	0.37
Weighted average number of units outstanding,
	Basic and diluted:
Common			11,354		11,354		11,354		11,354
Subordinated			11,354		11,354		11,354		11,354


			For the
			Period From
			January 1
			Through
			October 16,			Year Ended
			2002			December 31, 2001


			(In thousands)
Revenues:
	Coal royalties		$	17,261		$	15,458
	Timber royalties			2,774			3,691
	Gain on sale of property			92			3,125
	Property tax			1,221			1,184
	Other			1,219			2,512

		Total revenues		22,567			25,970
Expenses:
	General and administrative			2,291			2,981
	Taxes other than income			1,438			1,457
	Depreciation, depletion and amortization			3,544			1,369

		Total expenses		7,273			5,807

Income from operations				15,294			20,163
Other income (expense):
	Interest expense			(4,786	)		(3,966	)
	Interest income			114			270
	Reversionary interest			(561	)		(1,924	)

Net income			$	10,061		$	14,543


	General Partner			Limited Partners			Total


	(In thousands)
Balance, December 31, 2000	$	193		$	14,733		$	14,926
Net income		146			14,397			14,543
Cash distributions		(93	)		(9,207	)		(9,300	)

Balance, December 31, 2001		246			19,923			20,169
Net income		101			9,960			10,061
Cash distributions		(80	)		(7,920	)		(8,000	)

Balance, October 16, 2002.	$	267		$	21,963		$	22,230


Years of Service	Percent Vested

0-4		50	%
5		60	%
6		80	%
7 or more		100	%



	For the period from
	January 1, 2002
	through October 16,					Year ended
	2002					December 31, 2001


	(Dollars in thousands)

	Revenues		Percent			Revenues		Percent

Lessee A	$	5,659		25.1	%	$	4,956		19.1	%
Lessee B	$	3,609		16.0	%		5,113		20.5	%
Lessee C	$	4,058		18.0	%	$	2,123		8.2	%


	Coal		Timber		Other		Combined


	(In thousands)
For the year ended December 31, 2001
Revenues	$	16,642	$	3,691	$	5,637	$	25,970
Operating costs and expenses		3,109		757		572		4,438
Depreciation, depletion and amortization		1,035		210		124		1,369

Operating income	$	12,498	$	2,724	$	4,941		20,163

Interest expense								(3,966	)
Interest income								270
Reversionary interest								(1,924	)

Net income							$	14,543

Total assets	$	63,930	$	5,903	$	18,391	$	88,224
Capital expenditures		8,447		494		33		8,974


			For the
			period from
			January 1,
			through
			October 16,			Year ended
			2002			December 31, 2001


			(In thousands)
Revenues:
	Coal royalties		$	5,895		$	7,457
	Lease and easement income			474			787
	Gain on sale of property			—			439
	Property tax			61			88
	Other			71			31

		Total revenues		6,501			8,802
Expenses:
	General and administrative			417			611
	Taxes other than income			69			110
	Depreciation, depletion, and amortization			1,979			2,144

		Total expenses		2,465			2,865

Income from operations				4,036			5,937
Other income (expense):
	Interest expense			(1,877	)		(3,652	)
	Interest income			115			307

Net income			$	2,274		$	2,592


	General			Limited
	Partner			Partners			Total


	(In thousands)
Balance, December 31, 2000	$	184		$	18,201		$	18,385
Net income		26			2,566			2,592
Cash distributions		(9	)		(842	)		(851	)

Balance, December 31, 2001		201			19,925			20,126
Net income		23			2,251			2,274
Cash distributions		(7	)		(654	)		(661	)

Balance, October 16, 2002	$	217		$	21,522		$	21,739


	December 31, 2001

	(In thousands)
Floating rate notes, bearing interest at 4.70 percent at December 31, 2001 due September 30, 2004.	$	48,625
Less — Current portion of notes payable		(1,500	)

Long-term debt	$	47,125


			Accumulated
	Common Stock		Deficit			Total


	(In thousands)
Balance, December 31, 2000	$	2,137	$	(3,126	)	$	(989	)
Net income		—		1,223			1,223
Dividends		—		(1,000	)		(1,000	)

Balance, December 31, 2001		2,137		(2,903	)		(766	)
Net income		—		1,098			1,098
Dividends		—		(400	)		(400	)

Balance, October 16, 2002	$	2,137	$	(2,205	)	$	(68	)


Name	Age		Position with the General Partner

Corbin J. Robertson, Jr.		56	Chairman of the Board and Chief Executive Officer
Nick Carter		57	President and Chief Operating Officer
Dwight L. Dunlap		50	Chief Financial Officer and Treasurer
Kevin F. Wall		47	Vice President and Chief Engineer
Kathy E. Hager		52	Vice President Investor Relations
Wyatt L. Hogan		32	Vice President, General Counsel and Secretary
Corbin J. Robertson III		33	Vice President Acquisitions
Kenneth Hudson		49	Controller
Charles H. Kerr		50	Assistant Secretary
Robert T. Blakely		62	Director
David M. Carmichael		65	Director
Robert B. Karn III		62	Director
Alex T. Krueger		30	Director
S. Reed Morian		57	Director
David B. Peugh		49	Director
W. W. Scott, Jr.		58	Director


	Robert B. Karn, Chairman Robert T. Blakely David M. Carmichael



				Annual Compensation

								Other Annual
Name and Principal Position	Year			Salary		Bonus		Compensation(1)

Corbin J. Robertson, Jr., Chairman of the Board and CEO		2003		$	—	$	—	$	—
		2002			—		—		—
Nick Carter, President and Chief Operating Officer		2003			242,500		140,000		35,001
		2002	(2)		45,124		40,000		8,570
Dwight L. Dunlap, Chief Financial Officer and Treasurer		2003			148,500		50,000		24,998
		2002	(2)		17,334		15,000		3,186
Kathy E. Hager, Vice President Investor Relations		2003			132,000		20,000		13,970
		2002	(2)		21,666		15,000		—
Kevin F. Wall, Vice President and Chief Engineer		2003			118,750		50,000		22,649
		2002	(2)		20,325		—		4,783


	Number of				Estimated
	Phantom		Period Until		Future
Name	Units		Payout		Payout(1)(2)

Corbin J. Robertson, Jr.		3,667		2/25/2004	$	151,814
		3,667		2/25/2005		151,814
		3,667		2/25/2006		151,814
		23,525		2/25/2007		973,935
Nick Carter		1,834		2/25/2004	$	75,928
		1,834		2/25/2005		75,928
		1,834		2/25/2006		75,928
		11,762		2/25/2007		486,947
Dwight L. Dunlap		1,144		2/25/2004	$	47,362
		1,144		2/25/2005		47,362
		1,143		2/25/2006		47,320
		7,337		2/25/2007		303,752
Kathy E. Hager		378		2/25/2004	$	15,649
		378		2/25/2005		15,649
		378		2/25/2006		15,649
		2,426		2/25/2007		100,436
Kevin F. Wall		841		2/25/2004	$	34,817
		841		2/25/2005		34,817
		841		2/25/2006		34,817
		5,396		2/25/2007		223,394