NATURAL RESOURCE PARTNERS LP - Annual Report: 2004 (Form 10-K)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Commission file number: 1-31465

NATURAL RESOURCE PARTNERS L.P.

(Exact name of registrant as specified in its charter)

(713) 751-7507

(Registrant’s Telephone Number, Including Area Code)

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

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

None.

     Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to 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 $399.8 million on June 30, 2004 based on a price of $38.07 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date.

     As of February 28, 2005, there were 13,986,906 Common Units outstanding and 11,353,658 Subordinated Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE.

None.

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TABLE OF CONTENTS

Forward-Looking Statements

      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, 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 of 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” beginning on page 36 for important factors that could cause our actual results of operations or our actual financial condition to differ.

PART I

      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, 2004, we controlled approximately 1.8 billion tons of proven and probable coal reserves in nine states. We do not operate any mines, but 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. As of December 31, 2004, our reserves were subject to 125 leases with 52 lessees. In 2004, our lessees produced 48.4 million tons of coal from our properties and our coal royalty revenues were $106.5 million.

Partnership Structure and Management

      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. 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. Mr. Robertson is entitled to nominate six directors, three of whom must be independent directors, to the board of directors of GP Natural Resource Partners LLC. An affiliate of First Reserve Corporation, which led an investor group that purchased a number of subordinated units from Arch Coal in December 2003, has the right to nominate two directors, one of whom must be independent.

      Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation and Great Northern Properties Limited Partnership are three privately held companies that are primarily engaged in owning and managing mineral properties. We refer to these companies collectively as the WPP Group. 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 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. Neither our general partner, GP Natural Resource Partners LLC, nor 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.

Acquisitions of Coal Properties

      Plum Creek. On January 28, 2005, we signed a definitive agreement to purchase mineral rights to approximately 85 million tons of coal reserves from Plum Creek Timber Company, Inc. for $22 million. The transaction is subject to customary closing conditions and is expected to close in March. The purchase

will be funded through a combination of our credit facility and cash on hand. The coal reserves are located on approximately 175,000 acres in Virginia, West Virginia and Kentucky, with most of the reserves leased under 29 different leases.

      Clinchfield. In September 2004, we purchased a tract of coal reserves from Clinchfield Coal Company in Dickenson County, Virginia for $0.4 million. This property adjoins other property we own and represents approximately 0.8 million tons. We subsequently combined this property with other properties under an existing lease to a subsidiary of Alpha Natural Resources.

      Pardee Minerals. In May 2004, we purchased a tract of coal reserves from Pardee Minerals LLC in Wise County, Virginia for $1.6 million. This property adjoins other property we own and represents approximately 1.0 million tons. As a part of this transaction, we took an assignment of a coal lease under which a subsidiary of Alpha Natural Resources is the lessee.

      Appolo. In February 2004, we purchased two tracts of property from Appolo Fuels, Inc. in Bell County, Kentucky for $2.5 million. This property adjoins the properties purchased in the BLC acquisition and represents approximately 2.5 million tons. As a part of this transaction, an older below market lease affecting approximately 2.5 million additional tons of adjacent reserves was renegotiated to current royalty rates.

      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 acres. The properties are located in Kentucky, Tennessee, West Virginia, Virginia, and Alabama. BLC retained a 35% non-participating royalty interest in the oil and gas and other mineral rights.

Major Coal Properties

      The following is a summary of our major coal producing properties:

      VICC/ Alpha. The VICC/ Alpha property is located in Wise, Dickenson, Russell and Buchanan Counties, Virginia. In 2004, 7.1 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, Southern Company, TVA, VEPCO and U.S. Steel.

      Lynch. The Lynch property is located in Harlan and Letcher Counties, Kentucky. In 2004, 4.5 million tons were produced from this property. We primarily lease the property to Resource Development, LLC, 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.

      BLC Properties. The BLC Properties are located in Kentucky, Tennessee, West Virginia, Virginia and Alabama. In 2004, 3.5 million tons were produced from these properties. We purchased these properties in January 2004 from BLC Properties LLC. We lease this property to a number of operators including Appolo Fuels Inc., Bell County Coal Corporation and Kopper-Glo Fuels. Production comes from both underground and surface mines and is trucked to preparation plants and loading facilities operated by our lessees. Coal is transported by truck and is shipped via both CSX and Norfolk & Southern railroads to utility and industrial customers. Major customers include Southern Company, SCE&G, and numerous medium and small industrial customers.

      West Fork. The West Fork property is located in Boone County, West Virginia. In 2004, 2.7 million tons were produced from this property. We lease the property to Eastern Associated Coal Company, a subsidiary of publicly held Peabody Energy Company. 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. In 2004, the longwall mineable reserves were exhausted and we do not expect significant production from this property in the future.

      Evans-Laviers. The Evans-Laviers property is located in Breathitt, Floyd, Knott and Magoffin Counties, Kentucky. In 2004, 2.5 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.

      Lone Mountain. The Lone Mountain property is located in Harlan County, Kentucky. In 2004, 2.4 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 2004, 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.

      Eunice. The Eunice property is located in Raleigh and Boone Counties, West Virginia. In 2004, 2.0 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.

      Pinnacle Property. The Pinnacle property is located in Wyoming and McDowell Counties, West Virginia. We purchased the property in July 2003 from PinnOak Resources, LLC. In 2004, 1.8 million tons were produced from this property. Coal is produced from two underground mines and transported by belt or truck to a preparation plant operated by the lessee. The metallurgical coal is shipped via the Norfolk Southern railroad to customers such as U.S. Steel, National Steel, and is exported to a number of customers located in Europe.

      Hocking-Wolford/ Cummings. The Hocking-Wolford property and the Cummings property are both located in Sullivan County, Indiana. In 2004, 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 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 2004, 3.1 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 and by the Burlington Northern Santa Fe Railroad to Minnesota Power. A small amount of coal is transported by truck to other customers.

Coal Royalty Business

      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.

      Under our standard lease, third-party lessees calculate royalty and wheelage payments due us and are required to report tons of coal removed or hauled across our property as well as the sales prices of coal. Therefore, to a great extent, amounts reported as royalty and wheelage revenue are based upon the reports of our lessees. If permitted by the terms of the lease, we periodically audit this information by examining certain records and internal reports of our lessees and we perform periodic mine inspections to verify that the information that has been submitted to us is accurate. Our audits and inspections, however, are in periods subsequent to when the revenue is reported and any adjustment identified by these processes might be in a reporting period different from when the royalty or wheelage revenue was initially recorded. Our audit and inspection processes are designed to identify material variances from lease terms and reported information from actual results.

      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, global 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 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 two lessees who provided more than 10% of our total revenue in 2004: Alpha Natural Resources, Inc. and Arch Coal, Inc. Each of these companies has several different mines on our properties. While the loss of either 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.

Coal Royalty Revenues, Reserves and Production

      The following table sets forth coal royalty revenues from the properties that we own or control for the years ending December 31, 2004, 2003 and 2002. For the year ended December 31, 2002, the revenues 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 were generated from the properties in each of the areas as follows:

Coal Royalty Revenues

      The following table sets forth production data and reserve information for the properties that we own or control for the years ending December 31, 2004, 2003, and 2002. For the year ended December 31, 2002, the production data are attributable to the properties contributed to us at the time of our initial public offering and the properties we acquired in December 2002. Coal production data and reserve information for the properties in each of the areas is as follows:

Production and Reserves

      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, 2004, approximately 37% 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 2004, approximately 35% of the coal royalty revenues from our properties was 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, 2004.

Sulfur Content, Typical Quality and Type of Coal

      Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our estimates of reserve information on engineering, economic and geological data assembled and analyzed by our internal geologists and engineers and which is periodically reviewed by third party consultants. There are numerous uncertainties inherent in estimating the quantities and qualities of recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:

      As a result, actual coal tonnage recovered from identified reserve areas or properties may vary from estimates or may cause our estimates to change from time to time. Any inaccuracy in the estimates related to our reserves could result in decreased royalties from lower than expected production by our lessees.

Timber and Oil and Gas Properties

      For the year ended December 31, 2004, 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, Virginia and Tennessee.

Competition

      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 63% in 2003. 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.

Regulation

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

      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.

Specific Regulatory and Litigation Matters

      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 into 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. On March 29, 2004, EPA Region III sent a letter to the West Virginia Department of Environmental Protection that approved portions of the state’s antidegradation program, denied approval of portions pending further study, and recommended removal of certain language in the state’s regulations. The West Virginia Department of Environmental Protection is proceeding with a review. Our lessees are current NPDES or Section 404 permit holders that had been exempt from antidegradation review under the former policy. With exemptions not in place, our lessees that discharge into waters that have been designated as high quality by the state 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 permits increases the costs of coal production and could potentially reduce 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 March 15, 2004, the Supreme Court of West Virginia held that the circuit court erred in finding due process errors in the West Virginia Department of Environmental Protection hearing. Consequently, it reversed the lower decision and remanded the matter to the circuit court for consideration of the substantive issues raised by Marfork on its appeal from the West Virginia Department of Environmental Protection Order. A decision is currently pending in this matter. 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. In 2004, we received coal royalty revenues under this lease of $3.1 million.

      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 also 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 January 2005, legislation was re-introduced in Congress outlining the Bush administration’s Clear Skies Initiative, which calls for dramatic decreases in sulfur, nitrogen oxide, and mercury emissions from power plants. If emissions standards from power plants are required to be lowered under the act, it could result in a decrease in coal demand.

      If Clear Skies is not passed, EPA has announced an intention to take alternative action and finalize the Clean Air Interstate Rule (“CAIR”), and a related rule to reduce mercury emissions, under the existing Clean Air Act. The CAIR would mandate reductions in sulfur dioxide and nitrogen oxides in 29 states and the District of Columbia while the mercury rule would require mercury emissions reductions

on a national basis. EPA is seeking to lower mercury emissions at new and existing sources by requiring the use of Maximum Achievable Control Technology (“MACT”), or, in the alternative, by implementing a nationwide “cap and trade” program. Should either or both of these proposed rules become final, additional costs may be associated with operating coal-fired power generation facilities that may render coal a less attractive fuel source.

      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 was challenged in a lawsuit filed in October 2003 by the Ohio Valley Environmental Coalition and several other citizens groups. This lawsuit, Ohio Valley Environmental Coalition v. Bulen, was 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.

      In Ohio Valley Environmental Coalition v. Bulen, plaintiffs alleged 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. In July 2004, the district court enjoined the Corps of Engineers from issuing future authorizations under Nationwide Permit 21 in the Southern District of West Virginia. With respect to the eleven specific mining sites challenged by the plaintiffs, the Corps of Engineers was ordered to suspend those authorizations for valley fills and surface impoundments on which construction had not commenced as of July 8, 2004. In a subsequent order in August 2004, the district court clarified that the Corps of Engineers must suspend all existing authorizations under Nationwide Permit 21 for valley fills and surface impoundments in the Southern District of West Virginia on which construction had not commenced as of July 8, 2004. The Department of Justice has appealed these rulings. One permit for Green Valley was among the Nationwide Permit 21 permits being challenged. The August 2004 decision makes clear that Green Valley may not proceed under Nationwide Permit 21, but the lessee has applied for an individual permit. 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 in the Southern District of West Virginia may experience an increase in coal mining costs and they could mine less coal, which would adversely affect our coal royalty revenues.

      In January 2005, plaintiffs filed a lawsuit in the Eastern District of Kentucky on similar grounds challenging the legality of Nationwide Permit 21 and seeking to enjoin the Corps of Engineers from issuing general permits under that authority. Should the district court follow the reasoning of Ohio Valley Environmental Coalition v. Bulen and similarly enjoin the Corps of Engineers from authorizing further general permits under Nationwide Permit 21, permittees including our lessees, may have to file for individual permits for fills, which may result in increases in the costs of mining coal.

      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 subsequent 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 United Nations Framework Convention on Global Climate Change that is intended to limit or capture emissions of greenhouse gases such as carbon dioxide and methane. In December 1997, in Kyoto, Japan, the signatories to the convention established a potentially binding set of emissions targets for developed nations. In March 2001, the Bush Administration withdrew its support for the Kyoto Protocol, and the United States is not subject to its requirements. However, other countries have ratified the protocol, which will enter into force and require developing nations subject to it to reduce greenhouse gas emissions over a five-year period from 2008 to 2012. As an alternative to the Kyoto Protocol, in February 2002, the Bush administration announced a new approach to climate change, proposing voluntary actions to reduce the greenhouse gas intensity of the U.S. Greenhouse gas intensity measures the ratio of greenhouse gas emissions, such as carbon dioxide, to economic output. The Bush Administration continues to pursue this voluntary approach. Moreover, 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. Additionally, states, such as New Jersey and Maine, independently regulate emissions of certain greenhouse gases. 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. We believe that our lessees are in substantial compliance with all applicable environmental laws.

Title to Property

      Of the 1.8 billion tons of proven and probable coal reserves to which we had rights as of December 31, 2004, we owned approximately 99% of the reserves in fee. We lease approximately 19 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.

Employees and Labor Relations

      We do not have any employees. To carry out our operations, affiliates of our general partner employ approximately 48 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.

Segment Information

      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 do not meet the test for segment disclosure.

Website Access To Company Reports

      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, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the 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.

      None.

PART II

      Our common units are listed and traded on the New York Stock Exchange under the symbol “NRP.” As of February 15, 2005, there were an estimated 16,100 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 January 1, 2003 to December 31, 2004, and the quarterly cash distribution declared and paid with respect to each quarter per common and subordinated unit.

      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 affiliates of our general partner.

      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 common units will no longer be entitled to arrearages, the rights of the holders of subordinated units will no longer be subordinated to the rights of the holders of common units and the subordinated units may be converted into common units.

      Our general partner and affiliates of our general partner are entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

Percentage Allocations of Available Cash From Operating Surplus

      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. In general, we intend to increase our cash distributions in the future assuming we are able to increase our “available cash” from operations and through acquisitions, provided there is no adverse change in operations, economic conditions and other factors. However, we cannot guarantee that future distributions will continue at such levels.

SELECTED HISTORICAL FINANCIAL DATA

      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, 2004, 2003 and 2002, and for the years ended December 31, 2004 and 2003 and 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 members of the WPP Group (see page 2) for the period from January 1 through October 16, 2002 and as of and for the years ended December 31, 2001 and 2000 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 and 2000 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.

NATURAL RESOURCE PARTNERS L.P.

WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP

GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP

NEW GAULEY COAL CORPORATION

ARCH COAL CONTRIBUTED PROPERTIES

      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.

Executive Overview

      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. Coal produced from our properties is burned in electric power plants located east of the Mississippi River and in Montana and Minnesota. As of December 31, 2004, we controlled approximately 1.8 billion tons of proven and probable coal reserves in nine states. For the year ended December 31, 2004, approximately 67% of the coal produced from our properties came from underground mines and approximately 33% came from surface mines. As of December 31, 2004, approximately 69% of our reserves were low sulfur coal. Included in our low sulfur reserves is compliance coal, which constitutes approximately 37% of our reserves.

      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, 2004, our reserves were subject to 125 leases with 52 lessees. For the year ended December 31, 2004, our lessees produced 48.4 million tons of coal generating $106.5 million in coal royalty revenues from our properties and our total revenue was $121.4 million.

      Our revenue and profitability are dependent on our lessees’ ability to mine and market our coal reserves. Generally, our 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. 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 recorded as deferred revenue, a liability on our 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, over the long term, our coal royalty revenues are affected by changes in the 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. Beginning in the latter half of 2003, the combination of 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. Beginning in 2003, our lessees located in Appalachia experienced a greater demand for coal, and coal prices for both metallurgical and steam coal for those producers increased during 2004. Because of these generally higher prices, our revenues in Appalachia have increased to an average of $2.34 per ton for the year ended December 31, 2004 from an average of $1.77 per ton for the same period of 2003. Coal royalty revenues from our Appalachian properties represented 93% of our total coal royalty revenues for the full year of 2004. Our lessees have not appreciably increased production due to a number of constraints, including a shortage of labor, permitting and bonding issues and rail transportation problems.

      Approximately 35% of our 2004 coal royalty revenues were from metallurgical coal, which was sold to steel companies in the Eastern United States, South America, Europe and Asia. 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. The current pricing environment for U.S. metallurgical coal is strong in both the domestic and seaborne export markets. Demand for metallurgical coal in the United States has recently increased due to a recovery in the U.S. steel industry. Pricing for U.S. metallurgical coal has also been supported by reduced production at several U.S. metallurgical coal mines in 2004. In addition to increased demand for metallurgical coal in the United States, demand for metallurgical coal has increased in international markets. According to the International Iron and Steel Institute, Chinese steel consumption increased 25% in 2004, and Asia-Pacific Rim consumption of metallurgical coal continues to strain supply. The tightening supply of metallurgical coal in global markets has been due in part to recent supply disruptions in Australia, the world’s largest coal exporter, and the decision by China, the world’s second largest coal exporter, to restrict its metallurgical coal exports in order to satisfy domestic demand. Additionally, the recent weakness of the U.S. dollar has made U.S. metallurgical coal more competitive in international markets. Some steam coal with marginal metallurgical characteristics is now being sold in the metallurgical markets. If demand for metallurgical coal falls below historic levels, 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.

      On July 8, 2004, the United States District Court for the Southern District of West Virginia issued an opinion and an injunctive order in the case of Ohio Valley Environmental Coalition, et al. v. William Bulen. Judge Joseph Goodwin granted summary judgment for the plaintiffs and enjoined further permitting by the Army Corps of Engineers in southern West Virginia under the Nationwide 21 permit program. His order only impacts counties in southern West Virginia and requires applicants in those counties to seek individual permits, which require a more intensive environmental review and public comment. Judge Goodwin also ordered the Corps of Engineers to tell the companies that had received 11 permits issued by the Corps’ office in Huntington, West Virginia since January 2002 to halt any work under those permits where construction of the fills had not started by the time of the July 8 order. Pending the resolution of any appeals, this decision will dramatically slow down the permitting process for our lessees in southern West Virginia, and the increased cost of obtaining permits could render some of our smaller blocks of reserves uneconomic to develop.

      In January of 2005, plaintiffs filed a lawsuit in the Eastern District of Kentucky on similar grounds challenging the legality of Nationwide Permit 21 and seeking to enjoin the Corps of Engineers from issuing general permits under that authority. Should the district court follow the reasoning of Ohio Valley Environmental Coalition v. Bulen and similarly enjoin the Corps of Engineers from authorizing further general permits under Nationwide Permit 21, permittees may have to file for individual permits for fills that may result in increases in the costs of mining coal. We will continue to monitor this litigation and its impact on the development of our coal reserves.

      In addition to coal royalty revenues, we generated approximately 4% and 3% of our revenues for the years ended December 31, 2004 and 2003, respectively, from rentals; royalties on oil and gas and coalbed methane leases; timber; overriding royalty arrangements; and wheelage payments, which are toll payments for the right to transport third-party coal over or through our property.

      Under our partnership agreement, we are required to distribute all of our available cash each quarter. Because distributable cash flow is a significant liquidity metric that is an indicator of our ability to generate cash flows at a level that can sustain or support an increase in quarterly cash distributions paid to our partners, we view it as the most critical measure of our success as a company. Distributable cash flow is also the quantitative standard used throughout the investment community with respect to publicly traded partnerships.

      Distributable cash flow represents cash flow from operations less actual principal payments and cash reserves set aside for scheduled principal payments on the senior notes. Although distributable cash flow is a “non-GAAP financial measure,” we believe it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable cash flow is not a measure of financial performance under GAAP

and should not be considered as an alternative to cash flows from operating, investing or financing activities. Distributable cash flow may not be calculated the same for NRP as for other companies. A reconciliation of distributable cash flow to net cash provided by operating activities is set forth below.

Reconciliation of GAAP “Net Cash Provided by Operating Activities”

to Non-GAAP “Distributable Cash Flow”

Acquisitions

      Since our initial public offering in October 2002, we have completed nine acquisitions for an aggregate purchase price of $274 million. These acquisitions included approximately 739 million tons of coal reserves on approximately 998,000 mineral acres.

      Clinchfield. In September 2004, we purchased a tract of coal reserves from Clinchfield Coal Company in Dickenson County, Virginia for $0.4 million. This property adjoins other property we own and represents approximately 0.8 million tons. We have subsequently combined this property with other properties under an existing lease to a subsidiary of Alpha Natural Resources.

      Pardee Minerals. In May 2004, we purchased a tract of coal reserves from Pardee Minerals LLC in Wise County, Virginia for $1.6 million. This property adjoins other property we own and represents approximately 1.0 million tons. As a part of this transaction, we took an assignment of a coal lease under which a subsidiary of Alpha Natural Resources is the lessee.

      Appolo. In February 2004, we purchased two tracts of property from Appolo Fuels, Inc. in Bell County, Kentucky for $2.5 million. This property adjoins the properties purchased in the BLC acquisition and represents approximately 2.5 million tons. As a part of this transaction, an older below market lease affecting approximately 2.5 million additional tons of adjacent reserves was renegotiated to current royalty rates.

      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 acres. The properties are located in Kentucky, Tennessee, West Virginia, Virginia, and Alabama. BLC retained a 35% non-participating royalty interest in the oil and gas and other mineral rights.

      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 some of 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.

Critical Accounting Policies

      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.

      Historical practice in the extractive industry has been to classify leased mineral interests on a 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”) established a Mining Industry Working Group that addressed this issue. At a March 17-18, 2004 meeting of the EITF, the Task Force reached consensus that an inconsistency existed as to the characterization of mineral rights as tangible assets as determined by the EITF and SFAS No. 141 and 142. As a result of the EITF’s consensus, the FASB issued FASB Staff Position (“FSP”) Nos. FAS 141-1 and FAS 142-1, “Interaction of FASB Statements No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-02, Whether Mineral Rights Are Tangible or Intangible Assets,” which amend SFAS No. 141 and 142 and result in the classification of mineral rights as tangible assets. Prior to this consensus, the Partnership provided separate line items for owned and leased coal interests within the consolidated balance sheet as of December 31, 2003. At December 31, 2004, leased coal interests are included within coal and mineral rights in the audited consolidated balance sheet. Prior year amounts have been reclassified to conform with the current year presentation.

      Statement of Financial Accounting Standards No. 123R “Accounting for Stock-Based Compensation,” revised in 2004, superseded APB No. 25. Awards under our Long Term Incentive Plan have been accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R, effective for the third quarter of 2005, requires us to recognize a cumulative effect of the accounting change based on the difference between the fair value of the unvested awards and the intrinsic value recorded at the date of adoption. Additionally, FAS 123R provides that grants after the effective date must be accounted for using the fair value method which will require us to estimate the fair value of the grant using the Black-Scholes or another method and charge the estimated fair value to expense over the service or vesting period of the grant. FAS 123R requires that the fair value be recalculated at each reporting date over the service or vesting period of the grant. Use of the fair value method as compared with the intrinsic method, will not change the total expense to be reflected for a grant but it may impact the period in which expense is reflected by increasing expense in one period based upon the fair value calculation and lowering expense in a different period. We are in the process of evaluating the impact of the adoption of FAS 123R.

      In December 2003, The FASB issued FASB Interpretation No. 46R (“FIN 46R”), a revision to FIN 46 “Consolidation of Variable Interest Entities,” the objective of which was to provide guidance on how to identify a variable interest entity (“VIE”) and to determine when a VIE should be included in a company’s consolidated financial statements. In addition to increasing disclosures, FIN 46R requires a VIE to be consolidated by a company if that company’s variable interest will absorb a majority of the VIE’s expected losses and/or receive a majority of the entity’s expected residual returns. FIN 46R postponed the effective date for public companies to March 31, 2004, except for certain investee relationships. Adoption of FIN 46R did not have an impact on our consolidated financial position, results of operations or cash flow. However, we may enter into future transactions that could be accounted for as a VIE pursuant to FIN 46R.

Results of Operations

Natural Resource Partners L.P.

      Revenues. For the year ended December 31, 2004, total revenues were $121.4 million compared to $85.5 million for the same period in 2003, an increase of $35.9 million or 42%. Coal royalty revenues were $106.5 million, on 48.4 million tons of coal produced, for the year ending December 31, 2004, and represented 87.7% of total revenue. For the year ended December 31, 2003, coal royalty revenues were $73.8 million, on 44.3 million tons produced, and represented 86.3% of total revenue. Of the $35.9 million increase in total revenues, coal royalty revenues increased $32.7 million or 44% and override revenues increased $2.2 million or 215%. There was also an increase in wheelage revenue of $0.5 million or 35%, and modest increases in property tax reimbursements, rental income, oil and gas revenue and other totaling approximately $0.5 million or 9%.

      Coal royalty revenues. Coal royalty revenues increased to $106.5 million in 2004 from $73.8 million in 2003, an increase of $32.7 million or 44%. Coal production increased to 48.4 million tons from 44.3 million in 2003, an increase of 4.1 million tons or 9%. The substantial increase in coal royalty revenues is primarily due to the significantly higher sales prices realized by our lessees in 2004. In addition, approximately 3.6 million tons and $9.8 million of the increase in coal royalty revenues generated during the year ended December 31, 2004 were attributable to the acquisitions made subsequent to December 31, 2003. All of these acquisitions were in Appalachia.

      Appalachia. Coal royalty revenues in Appalachia in 2004 were $98.5 million compared to $63.9 million in 2003, an increase of $34.6 million, or 54%. In 2004, production in Appalachia was 42.0 million tons compared to 36.0 million tons in 2003, an increase of 6.0 million tons, or 16.7%.

      In addition to higher coal prices and acquisitions, the properties that had significant increases in production and coal royalty revenues were:

      These increases were partially offset by decreases in production and coal royalty revenues from our Boone-Lincoln, Chesapeake Minerals and Davis Lumber properties. On our Boone-Lincoln property, production decreased from 547,000 tons to 127,000 tons and coal royalty revenues decreased from $993,000 to $253,000. These decreases were due to a greater proportion of production occurring on adjacent property. On our Chesapeake Minerals property, production decreased from 475,000 tons to 136,000 tons and coal royalty revenues decreased from $942,000 to $366,000. These decreases were due to the depletion of reserves at one mine and a greater proportion of production occurring on adjacent property. On our Davis Lumber property, production decreased from 464,000 tons to 46,000 tons and coal royalty revenues decreased from $632,000 to $106,000. These decreases were due to a previously active mine exhausting reserves.

      Illinois Basin. On our Sato property, production increased from 909,000 tons to 963,000 tons and coal royalty revenues increased from $1.2 million to $1.4 million. These increases were due to slightly higher production and higher prices being realized by the lessee.

      Northern Powder River Basin. Production from our Western Energy property decreased from 4.3 million tons to 3.1 million tons and coal royalty revenues decreased from $5.4 million to $4.1 million. This decrease was due to the typical variations in production resulting from the checkerboard ownership pattern. On our Big Sky property production decreased from 983,000 tons to zero and coal royalty revenues decreased from $903,000 to zero as operations were idled at the Big Sky mine. Included in our coal royalty revenues for the year ended December 31, 2004 is a one-time settlement of $170,000, or $0.08 per ton, resulting from an arbitration award between our lessee and a third party.

      Expenses. Total expenses were $51.3 million, or 42%, of total revenues for the year ended December 31, 2004, compared to $41.3 million, or 48%, of total revenues for the year ended December 31, 2003. Depletion and amortization represented 61% of the total expenses for both 2004 and 2003. Although depletion and amortization was 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 16% of total expenses in both years, excluding accruals for incentive compensation of $3.4 million in 2004 and $2.8 million in 2003. Taxes other than income were $6.8 million, or 13%, of total expenses for 2004 and $5.8 million, or 14%, of total expenses for 2003. Coal royalty payments were $2.0 million or 4% of total expenses for 2004 and $1.3 million or 3% of total expenses for 2003. The increase in coal royalty payments is a direct result of the increase in coal prices.

      Other Income (Expense). Interest expense was $10.3 million for 2004 compared with $6.8 million for 2003. This increase in interest expense is a result of our senior debt being outstanding for a full year in 2004. Interest income increased from 2003 as a result of the investment of surplus cash. Other expense includes a one-time charge of $1.1 million for the early extinguishment of debt in connection with our new credit facility. In 2003, a $0.5 million expense was related to the hedge of interest rates on the issuance of the senior notes as well as a loss on the sale of oil and gas properties of $0.1 million incurred upon disposition of these properties in the fourth quarter.

      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

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.

Related Party Transactions

      Our general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. 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 $3.8 million in 2004, $2.9 million in 2003 and $0.3 million in 2002. For additional information, please read “Certain Relationships and Related Transactions — Omnibus Agreement.”

      First Reserve, which has the right to nominate two members to the board of directors of GP Natural Resource Partners LLC, has a significant interest in Alpha Natural Resources, which was our largest lessee in 2004 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 properties and through leases we had with entities that Alpha acquired. The leases we have with Alpha or related companies consist of the following properties:

      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.

      Coal royalty revenues payable under these leases based on 2004 production totaled $18.7 million, representing 17.5% of our total coal royalty revenues for the year ended December 31, 2004. If no production had taken place in 2004, minimum recoupable royalties of $4.7 million would have been payable under the leases. At December 31, 2004 we had accounts receivable outstanding of $1.4 million with Alpha Natural Resources.

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

      First Reserve also has a significant interest in Foundation Coal Holdings, Inc. who controls our lessee on our Kingston Property in West Virginia, which contains approximately 7.7 million tons of proven and probable reserves as of December 31, 2004.

      The Kingston lease has a term of ten years with the ability to renew the lease for subsequent terms of five years unless the lessee gives notice it will not renew the lease. The lease provides 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 annual minimum payments. Under the Kingston lease minimum royalty payments are credited against future production royalties. We believe the production and minimum royalty rates contained in the Kingston lease are consistent with current market royalty rates.

      Coal royalty revenues payable under the lease based on 2004 production totaled $2.1 million representing 1.9% of our coal royalty revenues for the year ended December 31, 2004. If no production had taken place in 2004, minimum recoupable royalties of $250,000 would have been payable under the lease. At December 31, 2004 we had accounts receivable outstanding of $0.2 million with Foundation Coal Holdings, Inc.

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

Liquidity and Capital Resources

      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, the issuance of our senior notes and the issuance of additional common units. We believe that cash generated from our operations, combined with the availability under our credit facility and the proceeds from the issuance of debt and equity, will be sufficient to fund working capital, capital expenditures and future acquisitions. 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 years ended December 31, 2004 and 2003 was $90.8 million and $64.5 million, respectively. For the period from commencement of operations (October 17, 2002) through December 31, 2002 it was $6.7 million. Substantially all of our cash provided by operations since inception has been from coal royalty revenues.

      Net cash used in investing activities for the year ended December 31, 2004 was $77.7 million. The 2004 results include the BLC, Appolo, Pardee Minerals, and Clinchfield acquisitions. We funded these

acquisitions with available cash and borrowings under our revolving credit facility. Borrowings under our revolving credit facility were subsequently paid in full with the proceeds from our equity offering in March 2004. Net cash used in investing activities for the year ended December 31, 2003 was $142.5 million. This amount includes the acquisition of the Alpha Natural Resources reserves and overriding royalty interest and PinnOak Resources and Eastern Kentucky reserves. 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, 2004 was $4.7 million. The 2004 period includes $200.4 million in net proceeds from our equity offering in March 2004, a $2.1 million capital contribution from our general partner, as well as $75.5 million in proceeds from borrowings on our credit facility. We used $102.5 million of the net proceeds from the equity offering to pay the outstanding balance on our credit facility and $100.1 million to redeem 2.6 million common units owned by Arch Coal. In October of 2004 we refinanced our revolving credit facility with improved terms and limits as well as extending the due date three years until October 2008. As a result of this refinancing we incurred debt issuance costs of $1.0 million. We also paid distributions to our partners totaling $60.4 million. 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 amount 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 at December 31, 2004 consists of:

      Credit Facility. On October 29, 2004, NRP (Operating) LLC entered into a 5-year, $175 million revolving credit facility with Citigroup Global Markets, Inc. and Wachovia Capital Markets, LLC as joint lead arrangers. The new credit facility replaced NRP Operating’s previous 3-year facility, which would have expired in October 2005. In addition to substantially improved pricing terms, the new facility permits NRP Operating to increase the size of the facility up to $300 million without obtaining lender consents. As a result of entering into the new credit facility, we expensed $1.1 million of unamortized loan financing costs related to NRP Operating’s early extinguishment of its previous credit facility.

      Our obligations under the new credit facility are unsecured but are guaranteed by our operating subsidiaries. We may prepay all loans at any time without penalty. Indebtedness under the revolving credit facility bears interest, at our option, at either:

      We incur a commitment fee on the unused portion of the revolving credit facility at a rate ranging from 0.30% to 0.40% per annum.

      The credit agreement contains covenants requiring us to maintain:

      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 requiring our operating subsidiary to:

      The following table reflects our long-term non-cancelable contractual obligations as of December 31, 2004 (in millions):

      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 registration statement 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. In November 2004, Great Northern Properties sold 300,000 common units in a private placement, and used the proceeds to repay debt outstanding under its credit agreement.

      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 did not and will not receive any proceeds from the sale of common units by Great Northern Properties.

      On March 16, 2004, we closed our public offering of 5,250,000 common units. We received net proceeds of $200.4 million from the sale of the 5,250,000 common units. These proceeds were based on an offering price of $39.96 per common unit and after deducting underwriting discounts and commissions and estimated offering expenses. In connection with the offering, we also received a capital contribution of $2.1 million from our general partner.

      We used the net proceeds of this offering and our general partner’s capital contribution to:

      The weighted average interest rate on the debt we repaid was 4.4%. This indebtedness was incurred under our credit facility in connection with our acquisitions of coal reserves and other mineral rights.

      Arch had the right to designate two directors to the board of directors for so long as Arch continued to hold at least 10% of the common units of Natural Resource Partners. As a result of the redemption of the common units from Arch, and the subsequent sales by Arch of its remaining common units pursuant to Rule 144, Arch no longer has any interest in Natural Resource Partners and no longer has the right to designate any directors. Mr. Robert Karn III, the independent director originally designated by Arch, remains on the board and will continue to serve as chairman of NRP’s audit committee.

      Following the offering, approximately $290.2 million is available under our shelf registration statement.

Inflation

      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, 2002, 2003 and 2004.

Environmental

      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 Limited Partnership 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, 2004. 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 Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and Arch Coal, Inc., 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.

Risks Related to Our Business

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

Commodity Price Risk

      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 profitability of our lessees’ operations and adversely affect our coal royalty revenues. If more coal is sold on the spot market, coal royalty revenues may become more volatile due to fluctuations in spot coal prices.

Interest Rate Risk

      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. Management intends to monitor interest rates and may enter into interest rate instruments to protect against increased borrowing costs. At December 31, 2004, we had no debt outstanding that was subject to variable interest rates.

INDEX TO FINANCIAL STATEMENTS