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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
 
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
    For the fiscal year ended December 31, 2004
 
or
 
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
    For the transition period from           to
Commission file number: 1-31465
NATURAL RESOURCE PARTNERS L.P.
(Exact name of registrant as specified in its charter)
     
Delaware
  35-2164875
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification Number)
601 Jefferson, Suite 3600
Houston, Texas
(Address of principal executive offices)
  77002
(Zip Code)
(713) 751-7507
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
     
Title of Each Class   Name of Each Exchange on Which Registered
     
Common Units representing limited partnership interests
  New York Stock Exchange
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.



TABLE OF CONTENTS
             
Item       Page
         
 PART I
   Business and Properties     2  
 3.
   Legal Proceedings     14  
 4.
   Submission of Matters to a Vote of Securities Holders     14  
 PART II
 5.
   Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities     15  
 6.
   Selected Financial Data     17  
 7.
   Management’s Discussion and Analysis of Financial Condition and Results of Operations     23  
 7A.
   Quantitative and Qualitative Disclosures About Market Risk     37  
 8.
   Financial Statements and Supplementary Data     38  
 9.
   Changes In and Disagreements with Accountants on Accounting and Financial Disclosure     88  
 9A.
   Controls and Procedures     88  
 9B.
   Other Information     89  
 PART III
 10.
   Directors and Executive Officers of the General Partner     90  
 11.
   Executive Compensation     95  
 12.
   Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters     97  
 13.
   Certain Relationships and Related Transactions     98  
 14.
   Principal Accountant Fees and Services     104  
 PART IV
 15.
   Exhibits and Financial Statement Schedules     108  
 Summary of director and exec. officer compensation
 List of subsidiaries
 Consent of Ernst & Young LLP
 Consent of Ernst & Young LLP
 Certification of CEO pursuant to Section 302
 Certification of CFO pursuant to Section 302
 Certification of CEO pursuant to Sec. 1350
 Certification of CFO pursuant to Sec. 1350
 Audited balance sheet of NRP(GP)LP
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.

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PART I
Items 1 and 2. Business and Properties
      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

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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:
Appalachia
      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.

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      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.
Illinois Basin
      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.

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Northern Powder River Basin
      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.

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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
                           
    Year Ended December 31,
     
    2004   2003   2002
             
    (In thousands)
Area
                       
Appalachia
  $ 98,541     $ 63,855     $ 40,688  
Illinois Basin
    3,852       3,566       2,994  
Northern Powder River Basin
    4,063       6,349       5,926  
                   
 
Total
  $ 106,456     $ 73,770     $ 49,608  
                   
      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
                                                   
    Production Year Ended   Proven and Probable Reserves at
    December 31,   December 31, 2004
         
    2004   2003   2002   Underground   Surface   Total
                         
    (Tons in thousands)
Area
                                               
Appalachia
    42,089       35,998       22,600       1,443,678       152,077       1,595,755  
Illinois Basin
    3,138       3,034       2,433             19,794       19,794  
Northern Powder River Basin
    3,130       5,312       5,474             153,023       153,023  
                                     
 
Total
    48,357       44,344       30,507       1,443,678       324,894       1,768,572  
                                     
      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.

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      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
                                                                           
    Sulfur Content   Typical Quality   Type of Coal
             
        Low       High       Heat        
        (Less   Medium   (Greater       Content        
    Compliance   than   (1.0% to   than       (Btu per   Sulfur    
Area   Coal(1)   1.0%)   1.5%)   1.5%)   Total   Pound)   (%)   Steam   Metallurgical(2)
                                     
    (Tons in thousands)           (Tons in thousands)
Appalachia
    651,548       1,061,596       305,722       228,437       1,595,755       13,032       0.98       1,199,342       396,413  
Illinois Basin
                4,628       15,166       19,794       11,466       2.67       19,794        
Northern Powder River Basin
          153,023                   153,023       8,486       0.75       153,023        
                                                       
 
Total
    651,548       1,214,619       310,350       243,603       1,768,572                       1,372,159       396,413  
                                                       
 
(1)  Compliance coal meets the sulfur dioxide emission standards imposed by Phase II of the Clean Air Act without blending with other coals or using sulfur dioxide reduction technologies. Compliance coal is a subset of low sulfur coal and is, therefore, also reported within the amounts for low sulfur coal.
 
(2)  For purposes of this table, we have defined metallurgical coal reserves as reserves located in those seams that historically have been of sufficient quality and characteristics to be able to be used in the steel making process. Some of the reserves in the metallurgical category can also be used as steam coal.
      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:
  •  future coal prices, mining economics, capital expenditures, severance and excise taxes, and development and reclamation costs;
 
  •  future mining technology improvements;
 
  •  the effects of regulation by governmental agencies; and
 
  •  geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experiences in other areas of our reserves.
      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.

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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:
  •  the discharge of materials into the environment;
 
  •  employee health and safety;
 
  •  mine permits and other licensing requirements;
 
  •  reclamation and restoration of mining properties after mining is completed;
 
  •  management of materials generated by mining operations;
 
  •  surface subsidence from underground mining;
 
  •  water pollution;
 
  •  legislatively mandated benefits for some current and retired coal miners;
 
  •  air quality standards;
 
  •  protection of wetlands;
 
  •  endangered plant and wildlife protection;
 
  •  limitations on land use;
 
  •  storage of petroleum products and substances that are regarded as hazardous under applicable laws; and
 
  •  management of electrical equipment containing polychlorinated biphenyls, or PCBs.
      In addition, the electricity generation industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our lessees’ coal. New legislation or regulations may be adopted or enforcement of existing laws could become more stringent, either of which may have a significant impact on the mining operations of our lessees or their customers’ ability to use coal. Potential regulation may require our lessees or their customers to change operations significantly or incur substantial costs.
      Our lessees are obligated to conduct mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, we do not believe violations by our lessees can be eliminated completely. We do not currently expect that future compliance will have a material adverse effect on us, our unitholders or our minimum quarterly distributions.

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      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

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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

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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.

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      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

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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.

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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.
Item 3. Legal Proceedings
      Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.
Item 4. Submission of Matters to a Vote of Securities Holders
      None.

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PART II
Item 5. Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities
      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.
                         
    Price Range    
        Cash
    High   Low   Distributions
             
2003
                       
First Quarter
  $ 23.98     $ 20.45     $ 0.5225  
Second Quarter
  $ 31.84     $ 22.90     $ 0.5225  
Third Quarter
  $ 37.00     $ 29.60     $ 0.5375  
Fourth Quarter
  $ 41.49     $ 28.25     $ 0.5625  
2004
                       
First Quarter
  $ 43.53     $ 35.50     $ 0.5750  
Second Quarter
  $ 38.98     $ 34.30     $ 0.6000  
Third Quarter
  $ 40.50     $ 37.31     $ 0.6375  
Fourth Quarter
  $ 57.98     $ 40.00     $ 0.6625  
      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.

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      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
                             
        Marginal Percentage Interest in
        Distributions
         
            Holders of
    Total Quarterly       Incentive
    Distribution Target       General   Distribution
    Amount   Unitholders   Partner   Rights
                 
Minimum Quarterly Distribution
  $0.5125     98%       2%        
First Target Distribution
  $0.5125 up to $0.5625     98%       2%        
Second Target Distribution
  above $0.5625 up to $0.6625     85%       2%       13%  
Third Target Distribution
  above $0.6625 up to $0.7625     75%       2%       23%  
Thereafter
  above $0.7625     50%       2%       48%  
      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.

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Item 6. Selected Financial Data
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.

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NATURAL RESOURCE PARTNERS L.P.
                                           
            From Commencement    
    For the Year   For the Year   of Operations   Year Ended
    Ended   Ended   (October 17, 2002)   December 31,
    December 31,   December 31,   through    
    2004   2003   December 31, 2002   2001   2000
                     
    (In thousands, except per unit and per ton data)
Income Statement Data:
                                       
Revenues:
                                       
 
Coal royalties
  $ 106,456     $ 73,770     $ 11,532       (1 )     (1 )
 
Property taxes
    5,349       5,069       1,047                  
 
Minimums recognized as revenue
    1,763       2,033       872                  
 
Override royalties
    3,222       1,022       226                  
 
Other
    4,642       3,572       216                  
                               
 
Total revenues
    121,432       85,466       13,893                  
Expenses:
                                       
 
Depletion and amortization
    30,957       25,365       4,526                  
 
General and administrative
    11,503       8,923       1,059                  
 
Taxes other than income
    6,835       5,810       1,296                  
 
Coal royalty payments
    2,045       1,299       397                  
                               
 
Total expenses
    51,340       41,397       7,278                  
                               
Income from operations
    70,092       44,069       6,615                  
 
Interest expense
    (10,312 )     (6,814 )     (200 )                
 
Interest income
    349       206                        
 
Loss from early extinguishment of debt
    (1,135 )                            
 
Loss on sale of assets
          (55 )                      
 
Loss from interest rate hedge
          (499 )                      
                               
Net income
  $ 58,994     $ 36,907     $ 6,415                  
                               
Balance Sheet Data (at period end):
                                       
Total assets
  $ 599,926     $ 531,676     $ 392,719                  
Deferred revenue
    15,847       15,054       13,252                  
Long-term debt
    156,300       192,650       57,500                  
Total liabilities
    190,734       223,518       74,085                  
Partners’ capital
    409,192       308,158       318,634                  
Cash Flow Data:
                                       
Net cash flow provided by (used in):
                                       
 
Operating activities
  $ 90,847     $ 64,528     $ 6,738                  
 
Investing activities
    (77,733 )     (142,511 )     (57,449 )                
 
Financing activities
    4,669       94,550       58,463                  
Other Data:
                                       
Royalty coal tons produced by lessees
    48,357       44,344       7,314                  
Average gross coal royalty per ton
  $ 2.20     $ 1.66     $ 1.58                  
Basic and diluted net income per limited partner unit:
                                       
 
Common
  $ 2.29     $ 1.59     $ 0.28                  
 
Subordinated
  $ 2.29     $ 1.59     $ 0.28                  
Weighted average number of units outstanding:
                                       
 
Common
    13,447       11,354       11,354                  
 
Subordinated
    11,354       11,354       11,354                  
Distributions per limited partner unit:
                                       
 
Common
  $ 2.4750     $ 2.1450     $ 0.4234                  
 
Subordinated
  $ 2.4750     $ 2.1450     $ 0.4234                  
 
(1)  No financial data is presented for these periods because Natural Resource Partners L.P. was not formed until April 9, 2002 and did not commence operations until October 17, 2002.

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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
                           
    For the        
    Period from        
    January 1    
    through   Year Ended December 31,
    October 16,    
    2002(1)   2001   2000
             
    (In thousands, except per ton data)
Income Statement Data:
                       
Revenues:
                       
 
Coal royalties
  $ 17,261     $ 15,458     $ 11,585  
 
Timber royalties
    2,774       3,691       4,236  
 
Gain on sale of property
    92       3,125       3,982  
 
Property taxes
    1,221       1,184       1,404  
 
Other
    1,219       2,512       1,342  
                   
 
Total revenues
    22,567       25,970       22,549  
Expenses:
                       
 
General and administrative
    2,291       2,981       3,009  
 
Taxes other than income
    1,438       1,457       1,701  
 
Depreciation, depletion and amortization
    3,544       1,369       1,168  
                   
 
Total expenses
    7,273       5,807       5,878  
                   
Income from operations
    15,294       20,163       16,671  
Other income (expense):
                       
 
Interest expense
    (4,786 )     (3,966 )     (4,167 )
 
Interest income
    114       270       321  
 
Reversionary interest
    (561 )     (1,924 )      
                   
Net income
  $ 10,061     $ 14,543     $ 12,825  
                   
Balance Sheet Data (at period end):
                       
Total assets
          $ 88,224     $ 76,510  
Deferred revenue
            7,916       7,468  
Long-term debt
            47,716       50,681  
Total liabilities
            68,055       61,584  
Partners’ capital
            20,169       14,926  
Cash Flow Data:
                       
Net cash flow provided by (used in):
                       
 
Operating activities
  $ 8,676     $ 13,056     $ 10,670  
 
Investing activities
    (35,028 )     2,685       3,976  
 
Financing activities
    27,899       (15,434 )     (14,630 )
Other Data:
                       
Royalty coal tons produced by lessees
    9,572       10,309       7,422  
Average gross coal royalty per ton
  $ 1.80     $ 1.50     $ 1.56  
 
(1)  Up to the date of contribution of assets to Natural Resource Partners L.P.

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GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP
                           
    For the        
    Period from    
    January 1   Year Ended
    through   December 31,
    October 16,    
    2002(1)   2001   2000
             
    (In thousands, except per ton data)
Income Statement Data:
                       
Revenues:
                       
 
Coal royalties
  $ 5,895     $ 7,457     $ 7,966  
 
Lease and easement income
    474       787       583  
 
Gain on sale of property
          439       709  
 
Property taxes
    61       88       87  
 
Other
    71       31       45  
                   
 
Total revenues
    6,501       8,802       9,390  
Expenses:
                       
 
General and administrative
    417       611       481  
 
Taxes other than income
    69       110       107  
 
Depreciation, depletion and amortization
    1,979       2,144       2,244  
                   
 
Total expenses
    2,465       2,865       2,832  
                   
Income from operations
    4,036       5,937       6,558  
Other income (expense):
                       
 
Interest expense
    (1,877 )     (3,652 )     (4,657 )
 
Interest income
    115       307       376  
                   
Net income
  $ 2,274     $ 2,592     $ 2,277  
                   
Balance Sheet Data (at period end):
                       
Total assets
          $ 70,236     $ 70,514  
Deferred revenue
            1,034       1,297  
Long-term debt
            47,125       48,625  
Total liabilities
            50,110       52,129  
Partners’ capital
            20,126       18,385  
Cash Flow Data:
                       
Net cash flow provided by (used in):
                       
 
Operating activities
  $ 3,725     $ 3,677     $ 5,731  
 
Investing activities
          475       726  
 
Financing activities
    (4,069 )     (4,564 )     (6,205 )
Other Data:
                       
Royalty coal tons produced by lessees
    4,970       8,509       9,172  
Average gross coal royalty per ton
  $ 1.19     $ 0.88     $ 0.87  
 
(1)  Up to the date of contribution of assets to Natural Resource Partners L.P.

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NEW GAULEY COAL CORPORATION
                           
    For the        
    Period from    
    January 1   Year Ended
    through   December 31,
    October 16,    
    2002(1)   2001   2000
             
    (In thousands, except per ton data)
Income Statement Data:
                       
Revenues:
                       
 
Coal royalties
  $ 1,434     $ 1,609     $ 955  
 
Gain on sale of property
          25        
 
Property taxes
    20       28       25  
 
Other
    53       61       32  
                   
 
Total revenues
    1,507       1,723       1,012  
Expenses:
                       
 
General and administrative
    52       41       32  
 
Taxes other than income
    42       45       48  
 
Depreciation, depletion and amortization
    138       212       132  
                   
 
Total expenses
    232       298       212  
                   
Income from operations
    1,275       1,425       800  
Other income (expense):
                       
 
Interest expense
    (97 )     (132 )     (139 )
 
Interest income
    24       15        
 
Reversionary interest
    (104 )     (85 )      
                   
Net income
  $ 1,098     $ 1,223     $ 661  
                   
Balance Sheet Data (at period end):
                       
Total assets
          $ 4,625     $ 4,553  
Deferred revenue
            3,601       3,747  
Long-term debt
            1,584       1,682  
Total liabilities
            5,391       5,542  
Stockholders’ deficit
            (766 )     (989 )
Cash Flow Data:
                       
Net cash flow provided by (used in):
                       
 
Operating activities
  $ 867     $ 1,323     $ 604  
 
Investing activities
          (175 )      
 
Financing activities
    (474 )     (1,091 )     (591 )
Other Data:
                       
Royalty coal tons produced by lessees
    479       718       356  
Average gross coal royalty per ton
  $ 2.99     $ 2.24     $ 2.68  
 
(1)  Up to the date of contribution of assets to Natural Resource Partners L.P.

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ARCH COAL CONTRIBUTED PROPERTIES
                         
    For the        
    Period from    
    January 1   Year Ended
    through   December 31,
    October 16,    
    2002(1)   2001   2000
             
    (In thousands, except per ton data)
Income Statement Data:
                       
Revenues:
                       
Coal royalties
  $ 14,768     $ 18,415     $ 16,152  
Other royalties
    1,349       1,363       907  
Property taxes
    1,179       1,033       1,204  
                   
Total revenues
    17,296       20,811       18,263  
Direct costs and expenses:
                       
Depletion
    4,889       6,382       5,395  
Property taxes
    1,179       1,033       1,204  
Other expense
    528       283       18  
Write-down of impaired assets
                 
                   
Total expenses
    6,596       7,698       6,617  
                   
Excess (deficit) of revenues over direct costs and expenses
  $ 10,700     $ 13,113     $ 11,646  
                   
Balance Sheet Data (at period end):
                       
Total assets
          $ 90,733     $ 97,230  
Deferred revenue
            10,409       10,035  
Total liabilities
            11,180       10,954  
Net assets purchased
            79,553       86,276  
Cash Flow Data:
                       
Direct cash flow from contributed properties
  $ 15,181     $ 19,836     $ 16,601  
Other Data:
                       
Royalty coal tons produced by lessees
    8,791       11,281       9,862  
Average gross coal royalty per ton
  $ 1.68     $ 1.63     $ 1.64  
 
(1)  Up to the date of contribution of assets to Natural Resource Partners L.P.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
      The following discussion of the financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included elsewhere in this filing. For more detailed information regarding the basis of presentation for the following financial information, see the notes to the historical financial statements.
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

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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

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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”
                 
    For the Year Ended
    December 31,
     
    2004   2003
         
    (Unaudited)
Cash flow from operations
  $ 90,847     $ 64,528  
Less scheduled principal payments
    (9,350 )      
Less reserves for future principal payments
    (9,400 )     (4,700 )
Add reserves used for scheduled principal payments
    9,400        
             
Distributable cash flow
  $ 81,497     $ 59,828  
             
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.
2004 Acquisitions
      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.
2003 Acquisitions
      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

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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.
2002 Acquisitions
      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

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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.
New Accounting Standards
      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.

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Results of Operations
Natural Resource Partners L.P.
                             
            For the
            Period from
            Commencement
    For the Year   For the Year   of Operations
    Ended   Ended   (October 17, 2002)
    December 31,   December 31,   through
    2004   2003   December 31, 2002
             
    (In thousands, except per ton data)
Revenues:
                       
 
Coal royalties
  $ 106,456     $ 73,770     $ 11,532  
 
Property taxes
    5,349       5,069       1,047  
 
Minimums recognized as revenue
    1,763       2,033       872  
 
Override royalties
    3,222       1,022       226  
 
Other
    4,642       3,572       216  
                   
 
Total revenues
    121,432       85,466       13,893  
Expenses:
                       
 
Depletion and amortization
    30,957       25,365       4,526  
 
General and administrative
    11,503       8,923       1,059  
 
Taxes other than income
    6,835       5,810       1,296  
 
Coal royalty payments
    2,045       1,299       397  
                   
 
Total expenses
    51,340       41,397       7,278  
                   
Income from operations
    70,092       44,069       6,615  
Other income (expense):
                       
 
Interest expense
    (10,312 )     (6,814 )     (200 )
 
Interest income
    349       206        
 
Loss on early extinguishment of debt
    (1,135 )            
 
Loss on sale of oil and gas properties
          (55 )      
 
Loss from interest rate hedge
          (499 )      
                   
Net income
  $ 58,994     $ 36,907     $ 6,415  
                   
Other Data:
                       
Royalties
                       
 
Appalachia
  $ 98,541     $ 63,855     $ 9,492  
 
Illinois Basin
    3,852       3,566       727  
 
Northern Powder River Basin
    4,063       6,349       1,313  
                   
   
Total
  $ 106,456     $ 73,770     $ 11,532  
                   
Production
                       
 
Appalachia
    42,089       35,998       5,448  
 
Illinois Basin
    3,138       3,034       601  
 
Northern Powder River Basin
    3,130       5,312       1,265  
                   
   
Total
    48,357       44,344       7,314  
                   
Average gross royalty
                       
 
Appalachia
  $ 2.34     $ 1.77     $ 1.74  
 
Illinois Basin
    1.23       1.18       1.21  
 
Northern Powder River Basin
    1.30       1.20       1.04  
                   
   
Total
  $ 2.20     $ 1.66     $ 1.58  
                   

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Year ended December 31, 2004 compared to year ended December 31, 2003
      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:
  •  Pinnacle — production increased from 830,000 tons to 1.8 million tons and coal royalty revenues increased from $1.8 million to $6.0 million. The mine operated on our property for two months in 2003 before ceasing production due to a ventilation disruption. The mine resumed production in late April 2004.
 
  •  Lynch — production increased from 2.9 million tons to 4.5 million tons and coal royalty revenues increased from $4.7 million to $8.7 million. These increases were due in part to new mines being opened on the property and also to higher prices being realized by the lessee.
 
  •  Sincell — production increased from 95,000 tons to 1.6 million tons and coal royalty revenues increased from $119,000 to $2.8 million. These increases were due to production moving onto our property which also benefited from the higher coal prices.
 
  •  Oak Grove — production increased from 775,000 tons to 1.4 million tons and coal royalty revenues increased from $1.7 million to $3.1 million. These increases were due to higher prices and owning the property for the year of 2004 versus six months in 2003.
 
  •  Y&O — production increased from 133,000 tons to 696,000 tons and coal royalty revenues increased from $262,000 to $1.3 million. These increases were due to mines moving onto the property and higher prices being realized by the lessee.
      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.

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

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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
Partnership Agreement
      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.”
Alpha Natural Resources
      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:
  •  VICC/ Alpha in Virginia, which contains 362.5 million tons of proven and probable reserves as of December 31, 2004.
 
  •  Kingwood in West Virginia, which contains 17.8 million tons of proven and probable reserves as of December 31, 2004.
 
  •  Welch/ Wyoming in West Virginia, which contains 7.5 million tons of proven and probable reserves as of December 31, 2004.
 
  •  Kentucky Land in Kentucky, which contains 20.3 million tons of proven and probable reserves as of December 31, 2004.
      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

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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.
Foundation Coal Holdings, Inc.
      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
Cash Flows and Capital Expenditures
      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

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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.
Contractual Obligations and Commercial Commitments
      Our debt exists entirely at our wholly owned subsidiary, NRP Operating LLC, and at December 31, 2004 consists of:
  •  a $175 million revolving credit facility that matures in October 2008, and under which there were no outstanding borrowings;
 
  •  $56.7 million outstanding of our $60 million of 5.55% senior notes due 2023, with a 10-year average life;
 
  •  $73.9 million outstanding of our $80 million of 4.91% senior notes due 2018, with a 7.5-year average life; and
 
  •  $35 million of 5.55% senior notes due 2013.
      Credit Facility. 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.

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      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:
  •  the higher of the federal funds rate plus an applicable margin ranging from 0.25% to 1.00% or the prime rate as announced by the agent bank; or
 
  •  at a rate equal to LIBOR plus an applicable margin ranging from 1.25% to 2.00%.
      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:
  •  a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) of 3.75 to 1.0 for the four most recent quarters; provided however, if during one of those quarters we have made an acquisition, then the ratio shall not exceed 4.0 to 1.0 for the quarter in which the acquisition occurred and (1) if the acquisition is in the first half of the quarter, the next two quarters or (2) if the acquisition is in the second half of the quarter, the next three quarters; and
 
  •  a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of 4.0 to 1.0 for the four most recent quarters.
      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:
  •  not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and
 
  •  maintain the ratio of consolidated EBITDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.
      The following table reflects our long-term non-cancelable contractual obligations as of December 31, 2004 (in millions):
                                                         
    Payments Due by Period(1)
     
Contractual Obligations   Total   2005   2006   2007   2008   2009   Thereafter
                             
Long-term debt (including current maturities)
  $ 234.00     $ 17.82     $ 17.33     $ 16.85     $ 16.38     $ 15.90     $ 149.72  
                                           
 
(1)  The amounts indicated in the table include principal and interest due on our senior notes.
Shelf Registration Statement/ Equity Offering
      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.

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      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:
  •  repay the $102.5 million of debt under our credit facility; and
 
  •  redeem 2,616,752 common units from Arch Coal for $38.26 per unit ($39.96 offering price, less $1.70 for underwriting discounts and commissions).
      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

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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 may not have sufficient cash from operations to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
 
  •  A substantial or extended decline in coal prices could reduce our coal royalty revenues and the value of our coal reserves.
 
  •  Our lessees’ coal mining operations are subject to operating risks that could result in lower coal royalty revenues to us.
 
  •  We depend on a limited number of primary operators for a significant portion of our coal royalty revenues, and the loss of or reduction in production from any of our major operators could reduce our coal royalty revenues.
 
  •  We may not be able to terminate our leases, and we may experience delays and be unable to replace lessees that do not make royalty payments.
 
  •  If our lessees do not manage their operations well, their production volumes and our coal royalty revenues could decrease.
 
  •  Adverse developments in the coal industry could reduce our coal royalty revenues, and could substantially reduce our total revenues due to our lack of asset diversification.
 
  •  Any decrease in the demand for metallurgical coal could result in lower coal production by our lessees, which would thereby reduce our coal royalty revenues.
 
  •  We may not be able to expand and our business will be adversely affected if we are unable to replace or increase our reserves or obtain other mineral reserves through acquisitions.
 
  •  Any change in fuel consumption patterns by electric power generators resulting in a decrease in the use of coal could result in lower coal production by our lessees, which would reduce our coal royalty revenues.
 
  •  Competition within the coal industry may adversely affect the ability of our lessees to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.
 
  •  Lessees could satisfy obligations to their customers with coal from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments.
 
  •  Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from our properties.
 
  •  Our reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of our reserves.
 
  •  Our lessees’ work forces could become increasingly unionized in the future.
 
  •  We may be exposed to changes in interest rates because any current borrowings under our revolving credit facility may be subject to variable interest rates based upon LIBOR.
 
  •  Our lessees are subject to federal, state and local laws and regulations that may limit their ability to produce and sell coal from our properties.

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  •  A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
      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.

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Item 8.      Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS
               
    Page
     
Natural Resource Partners L.P.:
       
 
Report of independent auditors
    39  
 
Balance sheets as of December 31, 2004 and 2003
    40  
 
Income statements for the year ended December 31, 2004, 2003 and from commencement of operations (October 17, 2002) through December 31, 2002
    41  
 
Statements of partner’s capital for the year ended December 31, 2004, 2003 and from commencement of operations (October 17, 2002) through December 31, 2002
    42  
 
Statements of cash flows for the year ended December 31, 2004 and from commencement of operations (October 17, 2002) through December 31, 2002
    43  
 
Notes to financial statements
    44  
The WPP Group:
       
 
Western Pocahontas Properties Limited Partnership:
       
   
Report of independent auditors
    55  
   
Statements of income for the period ended October 16, 2002 and the year ended December 31, 2001
    56  
   
Statements of changes in partners’ capital for the period ended October 16, 2002 and the year ended December 31, 2001
    57  
   
Statements of cash flows for the period ended October 16, 2002 and the year ended December 31, 2001
    58  
   
Notes to financial statements
    59  
 
Great Northern Properties Limited Partnership:
       
   
Report of independent auditors
    66  
   
Statements of income for the period ended October 16, 2002 and year ended December 31, 2001
    67  
   
Statements of changes in partners’ capital for the period ended October 16, 2002 and the year ended December 31, 2001
    68  
   
Statements of cash flows for the period ended October 16, 2002 and the year ended December 31, 2001
    69  
   
Notes to financial statements
    70  
 
New Gauley Coal Corporation:
       
   
Report of independent auditors
    74  
   
Statements of income for the period ended October 16, 2002 and the year ended December 31, 2001
    75  
   
Statements of changes in stockholders’ deficit
    76  
   
Statements of cash flows for the period ended October 16, 2002 and the year ended December 31, 2001
    77  
     
Notes to financial statements
    78  
Arch Coal, Inc. Contributed Properties:
       
 
Report of independent auditors
    82  
 
Statements of revenues and direct costs and expenses for the period ended October 16, 2002 and the year ended December 31, 2001
    83  
 
Notes to financial statements
    84  

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NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Partners of Natural Resource Partners L.P.
      We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2004 and 2003, and the related consolidated statements of income, partners’ capital and cash flows for each of the two years in the period ended December 31, 2004 and for the period from commencement of operations (October 17, 2002) through December 31, 2002. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We have conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
      In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Natural Resource Partners L.P. at December 31, 2004 and 2003, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 2004 and for the period from commencement of operations (October 17, 2002) through December 31, 2002, in conformity with U.S. generally accepted accounting principles.
      We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (Untied States), the effectiveness of Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2005 expressed an unqualified opinion thereon.
  Ernst & Young LLP
Houston, Texas
February 21, 2005

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NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
                     
    December 31,   December 31,
    2004   2003
         
    (In thousands)
ASSETS
Current assets:
               
 
Cash and cash equivalents
  $ 42,103     $ 24,320  
 
Accounts receivable
    15,058       9,553  
 
Accounts receivable — affiliate
    25       1,437  
 
Other
    786       1,086  
             
   
Total current assets
    57,972       36,396  
Land
    13,721       13,532  
Coal and other mineral rights, net
    523,844       475,393  
Loan financing costs, net
    1,837       2,884  
Other assets, net
    2,552       3,471  
             
   
Total assets
  $ 599,926     $ 531,676  
             
 
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
               
 
Accounts payable
  $ 576     $ 423  
 
Accounts payable — affiliate
    105       305  
 
Current portion of long-term debt
    9,350       9,350  
 
Accrued incentive plan expenses — current portion
    1,559       1,186  
 
Property and franchise taxes payable
    3,460       2,799  
 
Accrued interest
    266       681  
             
   
Total current liabilities
    15,316       14,744  
Deferred revenue
    15,847       15,054  
Accrued incentive plan expenses
    3,271       1,070  
Long-term debt
    156,300       192,650  
Partners’ capital:
               
 
Common units (outstanding: 13,986,906 in 2004, 11,353,658 in 2003)
    243,814       143,956  
 
Subordinated units (outstanding: 11,353,658)
    157,324       158,633  
 
General partners’ interest
    8,802       6,474  
 
Holders of incentive distribution rights
    105        
 
Accumulated other comprehensive loss
    (853 )     (905 )
             
   
Total partners’ capital
    409,192       308,158  
             
   
Total liabilities and partners’ capital
  $ 599,926     $ 531,676  
             
The accompanying notes are an integral part of these financial statements.

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NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF INCOME
                             
            From
            Commencement of
    For the Year   For the Year   Operations
    Ended   Ended   (October 17, 2002)
    December 31,   December 31,   through
    2004   2003   December 31, 2002
             
    (In thousands, except per unit data)
Revenues:
                       
 
Coal royalties
  $ 106,456     $ 73,770     $ 11,532  
 
Property taxes
    5,349       5,069       1,047  
 
Minimums recognized as revenue
    1,763       2,033       872  
 
Override royalties
    3,222       1,022       226  
 
Other
    4,642       3,572       216  
                   
   
Total revenues
    121,432       85,466       13,893  
Operating costs and expenses:
                       
 
Depletion and amortization
    30,957       25,365       4,526  
 
General and administrative
    11,503       8,923       1,059  
 
Taxes other than income
    6,835       5,810       1,296  
 
Coal royalty payments
    2,045       1,299       397  
                   
   
Total operating costs and expenses
    51,340       41,397       7,278  
                   
Income from operations
    70,092       44,069       6,615  
Other income (expense)
                       
 
Interest expense
    (10,312 )     (6,814 )     (200 )
 
Interest income
    349       206        
 
Loss on early extinguishment of debt
    (1,135 )            
 
Loss from sale of oil and gas properties
          (55 )      
 
Loss from interest rate hedge
          (499 )      
                   
Net income
  $ 58,994     $ 36,907     $ 6,415  
                   
Net income attributable to:
                       
 
General partner(1)
  $ 1,705     $ 738     $ 128  
                   
 
Other holders of incentive distribution rights(1)
  $ 281     $     $  
                   
 
Limited partners
  $ 57,008     $ 36,169     $ 6,287  
                   
Basic and diluted net income per limited partner unit:
                       
 
Common
  $ 2.29     $ 1.59     $ 0.28  
                   
 
Subordinated
  $ 2.29     $ 1.59     $ 0.28  
                   
Weighted average number of units outstanding:
                       
 
Common
    13,447       11,354       11,354  
                   
 
Subordinated
    11,354       11,354       11,354  
                   
 
(1)  Other holders of the incentive distribution rights (IDRs) include the WPP Group (25%) and NRP Investment LP (10%). The net income allocated to the general partner includes the general partner’s portion of the IDRs (65%).
The accompanying notes are an integral part of these financial statements.

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NATURAL RESOURCE PARTNERS L.P.
STATEMENT OF PARTNERS’ CAPITAL
                                                                 
                        Holders of        
                Incentive   Accumulated    
    Common Units   Subordinated Units   General   Distribution   Other    
            Partner   Rights   Comprehensive    
    Units   Amounts   Units   Amounts   Amounts   Amounts   Loss   Total
                                 
    (In thousands, except unit data)
Balance at commencement of operations (October 17, 2002)
        $ 1                 $     $     $     $ 1  
Net assets contributed by sponsors on October 17, 2002
    8,679,405       96,691       11,353,658       160,179       6,538                   263,408  
Additional contribution by sponsors
          1,847                                     1,847  
Issuance of units to the public, net of offering and other costs
    2,598,750       45,453                                     45,453  
Additional units purchased by GNP and NGCC
    75,503       1,510                                     1,510  
Net income for the period from commencement of operations (October 17, 2002) through December 31, 2002
          3,144             3,143       128                   6,415  
                                                 
Balance at December 31, 2002
    11,353,658     $ 148,646       11,353,658     $ 163,322     $ 6,666                 $ 318,634  
                                                 
Distributions to unitholders
          (22,774 )           (22,774 )     (930 )                 (46,478 )
Net income for the year ended December 31, 2003
          18,084             18,085       738                   36,907  
Loss on interest hedge, net
                                        (905 )     (905 )
                                                 
Comprehensive income
                                              36,002  
                                                 
Balance at December 31, 2003
    11,353,658     $ 143,956       11,353,658     $ 158,633     $ 6,474     $     $ (905 )   $ 308,158  
                                                 
Issuance of units to the public, net of offering and other costs
    5,250,000       200,355                                     200,355  
Redemption of common units, net
    (2,616,752 )     (100,121 )                                   (100,121 )
Additional contribution by the General Partner
                            2,147                   2,147  
Distributions to unitholders
          (31,730 )           (26,963 )     (1,524 )     (176 )           (60,393 )
Net income for the year ended December 31, 2004
          31,354             25,654       1,705       281             58,994  
Loss on interest hedge
                                        52       52  
                                                 
Comprehensive income
                                        52       59,046  
                                                 
Balance at December 31, 2004
    13,986,906     $ 243,814       11,353,658     $ 157,324     $ 8,802     $ 105     $ (853 )   $ 409,192  
                                                 
The accompanying notes are an integral part of these financial statements.

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NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
                               
            From
            Commencement of
    For the Year   For the Year   Operations
    Ended   Ended   (October 17, 2002)
    December 31,   December 31,   through
    2004   2003   December 31, 2002
             
    (In thousands)
Cash flows from operating activities:
                       
 
Net income
  $ 58,994     $ 36,907     $ 6,415  
 
Adjustments to reconcile net income to net cash provided by operating activities:
                       
   
Depletion and amortization
    30,957       25,365       4,526  
   
Non-cash interest charge
    52       26        
   
Loss on early extinguishment of debt
    1,135              
   
Loss on sale of oil and gas properties
          55        
 
Change in operating assets and liabilities:
                       
   
Accounts receivable
    (4,093 )     (1,947 )     (9,043 )
   
Other assets
    236       (811 )     (511 )
   
Accounts payable and accrued liabilities
    (47 )     (674 )     1,602  
   
Accrued interest
    (415 )     481       2,018  
   
Deferred revenue
    793       1,802        
   
Accrued incentive plan expenses
    2,574       2,256        
   
Property and franchise taxes payable
    661       1,068       1,731  
                   
     
Net cash provided by operating activities
    90,847       64,528       6,738  
                   
Cash flows from investing activities:
                       
 
Acquisition of coal and other mineral rights
    (77,733 )     (142,541 )     (57,449 )
 
Proceeds from sale of oil and gas properties
          30        
                   
     
Net cash used in investing activities
    (77,733 )     (142,511 )     (57,449 )
                   
Cash flows from financing activities:
                       
 
Proceeds from loans
    75,500       317,100       57,500  
 
Deferred financing costs
    (969 )     (2,541 )     (1,316 )
 
Repayment of loans
    (111,850 )     (172,600 )     (46,531 )
 
Distributions to partners
    (60,393 )     (46,478 )      
 
Contributions by general partner and sponsors
    2,147             1,847  
 
Proceeds from initial sale of common units net of transaction costs
                45,453  
 
Proceeds from sale of common units to GNP and NGCC
                1,510  
 
Proceeds from sale of 5,250,000 common units, net of transaction costs
    200,355              
 
Redemption of 2,616,752 common units, net
    (100,121 )            
 
Settlement of hedge included in accumulated other comprehensive loss
          (931 )      
                   
     
Net cash provided by financing activities
    4,669       94,550       58,463  
                   
Net increase in cash
    17,783       16,567       7,752  
Cash at beginning of period
    24,320       7,753       1  
                   
Cash at end of period
  $ 42,103     $ 24,320     $ 7,753  
                   
Supplemental cash flow information:
                       
 
Cash paid during the period for interest
  $ 10,603     $ 5,778     $  
                   
Non-cash investing activities:
                       
 
Net assets contributed by partners
                153,091  
 
Excess of cost over net book value of Arch properties
                110,315  
 
Deferred revenue assumed on acquisition of property
                (2,152 )
The accompanying notes are an integral part of these financial statements.

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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation and Organization
      Natural Resource Partners L.P. (the “Partnership”), a Delaware limited partnership, was formed in April 2002 to own and manage certain coal royalty producing properties contributed to the Partnership by Western Pocahontas Properties Limited Partnership, (“WPP”), Great Northern Properties Limited Partnership, (“GNP”), New Gauley Coal Corporation, (“NGCC”) and Arch Coal, Inc. (“Arch”) (collectively “predecessors” or “predecessor companies”). The predecessor companies contributed assets to the Partnership on October 17, 2002. There were no operations in the Partnership prior to the contribution of the assets from the predecessor companies. Therefore, the 2002 statements of income, partners’ capital and cash flows are presented from the date of commencement of operations (October 17, 2002) through December 31, 2002.
      The general partner of the Partnership is NRP (GP) LP, a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The chief executive officer of GP Natural Resource Partners LLC controls the general partners of WPP and GNP and is the controlling shareholder of NGCC. He also controls the general partner of the Partnership. In accordance with EITF 87-21, “Change of Accounting Basis in Master Limited Partnership Transactions”, the assets of WPP, GNP and NGCC were contributed to the Partnership at historical costs. The assets contributed by Arch, which consisted solely of land, coal reserves and minerals and other rights were recorded at their fair values.
      The Partnership engages 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, the Partnership controlled approximately 1.8 billion tons of proven and probable coal reserves (unaudited) in nine states. The Partnership does not operate any mines, but leases coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine coal reserves in exchange for royalty payments. Lessees are generally required to make royalty payments 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.
2. Summary of Significant Accounting Policies
Principles of Consolidation
      The financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries. Intercompany transactions and balances have been eliminated.
Reclassification
      Certain reclassifications have been made to the prior year’s financial statements to conform to current year classifications.
Use of Estimates
      Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash Equivalents
      The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents.

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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Land, Coal and Mineral Rights
      Land, coal and mineral rights are carried at historical cost for properties contributed by WPP, GNP and NGCC. The coal mineral rights contributed by Arch as well as the Partnership’s acquisitions have been accounted for using purchase accounting based on their estimated fair value. Coal mineral rights owned and leased are depleted on a unit-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein, or upon the amortization period of the contractual rights.
Asset Impairment
      If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset will not be recoverable, as determined based on projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value.
Concentration of Credit Risk
      Substantially all of the Partnership’s accounts receivable result from amounts due from third-party companies in the coal industry. This concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be affected by changes in economic or other conditions. Receivables are generally not collateralized. Historical credit losses incurred by the Partnership on receivables have not been significant.
Fair Value of Financial Instruments
      The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of the Partnership’s financial instruments included in current assets and current liabilities approximates their fair value due to their short-term nature. The fair market value of the Partnership’s long-term debt was estimated to be $159.1 million and $175.0 million at December 31, 2004 and 2003, respectively, for the unsecured senior notes. The fair values of the senior notes represents management’s best estimate based on other financial instruments with similar characteristics.
      Since the Partnership’s credit facility has variable rate debt, its fair value approximates its carrying amount. The Partnership had no outstanding debt under the credit facility at December 31, 2004.
Deferred Financing Costs
      Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s revolving credit facility and senior unsecured notes. These costs are amortized over the term of the debt.
Revenues
      Coal Royalties. Coal royalty revenues are recognized on the basis of tons of coal sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the coal lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.
      Minimum Royalties. Most of the Partnership’s lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue. The deferred revenue attributable to the minimum payment is recognized as

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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
coal royalty revenues either when the lessee recoups the minimum payment through production or when the period during which the lessee is allowed to recoup the minimum payment expires.
      Oil and Gas Royalties. Oil and gas royalties are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the lessees make payments based on a percentage of the selling price. Some are subject to minimum annual payments or delay rentals. The minimum annual payments that are recoupable are generally recoupable over certain periods. The minimum payments are initially recorded as deferred revenue and recognized either when the lessee recoups the minimum payments through production or when the period during which the lessee is allowed to recoup the minimum payment expires.
Property Taxes
      The Partnership is responsible for paying property taxes on the properties it owns. The lessees are typically contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The reimbursement of property taxes is included in revenues in the statement of income as property taxes.
Income Taxes
      The Partnership is not a taxpaying entity, as the individual partners are responsible for reporting their pro rata share of the Partnership’s taxable income or loss. In the event of an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities.
New Accounting Standards
      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 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 the Partnership’s 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 the Partnership to recognize a cumulative effect of the accounting change based on the difference between the fair value of the unvested awards and 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 the Partnership to estimate the fair value of

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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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. The Partnership is 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 the Partnership’s consolidated financial position, results of operations or cash flow. However, the Partnership may enter into future transactions that could be accounted for as a VIE pursuant to FIN 46R.
3. Acquisitions
      Clinchfield. In September 2004, the Partnership purchased a tract of coal reserves from Clinchfield Coal Company in Dickenson County, Virginia for $0.4 million. This property adjoins other property the Partnership owns and represents approximately 0.8 million tons (unaudited). The Partnership subsequently combined this property with other properties under an existing lease to a subsidiary of Alpha Natural Resources.
      Pardee Minerals. In May 2004, the Partnership purchased a tract of coal reserves from Pardee Minerals LLC in Wise County, Virginia for $1.6 million. This property adjoins other property the Partnership owns and represents approximately 1.0 million tons (unaudited). As a part of this transaction, the Partnership took an assignment of a coal lease under which a subsidiary of Alpha Natural Resources is the lessee.
      Appolo. In February 2004, the Partnership 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 (unaudited). As a part of this transaction, an older below market lease affecting approximately 2.5 million additional tons (unaudited) of adjacent reserves was renegotiated to current royalty rates.
      BLC Properties. In January 2004, the Partnership 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 (unaudited) that contain approximately 176 million tons of coal reserves (unaudited). The Partnership leases these reserves to eight different lessees. The transaction also included oil and gas and other mineral rights on approximately 205,000 additional acres (unaudited). 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.
      The factors used in determining the fair market value of the assets acquired included, but were not limited to, discounted future net cash flows, the quality of the reserves, the probability of continued coal mining on the property, and marketability of the coal.

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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
4. Coal and Other Mineral Rights
      The Partnership’s coal and other mineral rights consist of the following:
                 
    December 31,   December 31,
    2004   2003
         
    (In thousands)
Coal and other mineral rights
  $ 634,960     $ 557,415  
Less accumulated depletion and amortization
    111,116       82,022  
             
Net book value
  $ 523,844     $ 475,393  
             
                 
    For the Year Ended
    December 31,
     
    2004   2003
         
    (In thousands)
Total depletion and amortization expense on coal interests
  $ 29,093     $ 23,538  
             
5. Long-Term Debt
      Long-term debt consists of the following:
                 
    December 31,   December 31,
    2004   2003
         
    (In thousands)
$175 million floating rate revolving credit facility, due October 2008
  $     $  
$175 million floating rate revolving credit facility, due October 2005
          27,000  
5.55% senior notes maturing in June 2023
    56,700       60,000  
4.91% senior notes maturing in June 2018
    73,950       80,000  
5.55% senior notes maturing June 2013
    35,000       35,000  
             
Total debt
    165,650       202,000  
Less — current portion of long term debt
    (9,350 )     (9,350 )
             
Long-term debt
  $ 156,300     $ 192,650  
             
      Principal payments due in:
         
2005
  $ 9,350  
2006
    9,350  
2007
    9,350  
2008
    9,350  
2009
    9,350  
Thereafter
    118,900  
       
    $ 165,650  
       
      Under the terms of the Partnership’s senior debt, interest payments are due semi-annually in June and December. Principal payments are due annually in June.

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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The Partnership’s obligations under the credit facility are unsecured but are guaranteed by its operating subsidiaries. Indebtedness under the revolving credit facility bears interest, at the Partnership’s option, at either:
  •  the higher of the federal funds rate plus an applicable margin ranging from 0.25% to 1.00% or the prime rate as announced by the agent bank; or
 
  •  at a rate equal to LIBOR plus an applicable margin ranging from 1.25% to 2.00%.
      At December 31, 2003, the weighted average interest rate on the outstanding advances was 3.14%. The Partnership incurs 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 also contains covenants requiring the Partnership to maintain:
  •  a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) of 3.75 to 1.0 for the four most recent quarters; provided however, if during one of those quarters the Partnership has made an acquisition, then the ratio shall not exceed 4.0 to 1.0 for the quarter in which the acquisition occurred and (1) if the acquisition is in the first half of the quarter, the next two quarters or (2) if the acquisition is in the second half of the quarter, the next three quarters; and
 
  •  a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of 4.0 to 1.0 for the four most recent quarters.
      The Partnership also has outstanding $165.6 million in unsecured senior notes which are guaranteed by its operating subsidiaries. Proceeds from the issuance of the senior notes were used to repay borrowings under the Partnership’s revolving credit facility and for related expenses. The terms under the senior notes require that the Partnership maintain a fixed charge coverage ratio of not less than 3.50 to 1.0 and a limit on consolidated debt to consolidated EBITDA of not more than 4.0 to 1. 0.
      The Partnership was in compliance with all terms under its long-term debt as of December 31, 2004.
6. Equity Offering
      On March 16, 2004 the Partnership closed a public offering of 5,250,000 common units. The Partnership 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 less underwriting discounts, commissions and offering expenses. In connection with the offering, the Partnership also received a capital contribution of $2.1 million from its general partner.
      The Partnership used the net proceeds of this offering and its general partner’s capital contribution to:
  •  repay the $102.5 million of debt under the credit facility; and
 
  •  redeem 2,616,752 common units from Arch Coal for $38.26 per unit ($39.96 offering price, less $1.70 for underwriting discounts and commissions).
7. Net Income Per Unit Attributable to Limited Partners
      Net income per unit attributable to limited partners is based on the weighted-average number of common and subordinated units outstanding during the period and is allocated in the same ratio as quarterly cash distributions are made. Net income per unit attributable to limited partners is computed by dividing net income attributable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, by the weighted-average number of limited partnership units outstanding. Basic and

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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
diluted net income per unit attributable to limited partners are the same since the Partnership has no potentially dilutive securities outstanding.
8. Related Party Transactions
      Quintana Minerals Corporation, a company controlled by Corbin J. Robertson, Jr., Chairman and CEO of GP Natural Resource Partners LLC, provided certain administrative services to the Partnership and charged it for direct costs related to the administrative services. Total expenses charged to the Partnership under this arrangement were $1.1 million and $1.0 million for the years ending December 31, 2004 and 2003, respectively and $0.1 million from commencement of operations to December 31, 2002. These costs are reflected in general and administrative expenses in the accompanying statements of income. At December 31, 2004, 2003 and 2002, the Partnership also had accounts payable to affiliates of $0.1 million, which includes general and administrative expense payable to Quintana Minerals Corporation.
      WPP provides certain administrative services for the Partnership. Total expenses charged to the Partnership under this arrangement were $2.7 million and $1.9 million for the years ending December 31, 2004 and 2003, respectfully, and $0.3 million from commencement of operations to December 31, 2002. These costs are reflected in general and administrative expenses in the accompanying statements of income.
      At December 31, 2003, the Partnership had accounts receivable from affiliates of $1.4 million consisting of minimums due from Arch Coal, Inc. At December 31, 2004, accounts receivable from affiliates were less than $0.1 million. In conjunction with the Partnership’s public offering of 5,250,000 common units in 2004, the Partnership redeemed 2,616,752 of the common units held by Arch Coal, Inc. Please see Note 6. As a result of the redemption of Arch Coal’s common units in March 2004, Arch Coal is no longer an affiliate of the Partnership.
Alpha Natural Resources
      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 the Partnership’s largest lessee in 2004 based on revenues. The Partnership has entered into a number of coal mining leases with Alpha through a combination of new leases entered into upon the purchase of the Alpha property and through leases with entities that Alpha acquired. The leases with Alpha or related companies consist of the following properties:
  •  VICC/ Alpha in Virginia, which contains 362.5 million tons of proven and probable reserves (unaudited) as of December 31, 2004.
 
  •  Kingwood in West Virginia, which contains 17.8 million tons of proven and probable reserves (unaudited) as of December 31, 2004.
 
  •  Welch/ Wyoming in West Virginia, which contains 7.5 million tons of proven and probable reserves (unaudited) as of December 31, 2004.
 
  •  Kentucky Land in Kentucky, which contains 20.3 million tons of proven and probable reserves (unaudited) as of December 31, 2004.
      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

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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
payments are credited against future production royalties. The production and minimum royalty rates contained in the Alpha leases are consistent with current market royalty rates.
      Coal royalty revenues payable under these leases based on 2004 production totaled $18.7 million, representing 17.5% of 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, accounts receivable outstanding totaled $1.4 million with Alpha Natural Resources.
Foundation Coal Holdings, Inc.
      First Reserve also has a significant interest in Foundation Coal Holdings, Inc. who controls the lessee on the Kingston Property. The lease with this entity is located on the Kingston property in West Virginia, which contains 8.3 million tons of proven and probable reserves (unaudited) 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 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. 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 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, accounts receivable outstanding totaled $0.2 million with Foundation Coal Holdings, Inc.
9. Commitments and Contingencies
Legal
      The Partnership is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Partnership management believes these claims will not have a material effect on the Partnership’s financial position, liquidity or operations.
Environmental Compliance
      The operations conducted on the Partnership’s properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties for the period ended December 31, 2004. The Partnership is not associated with any environmental contamination that may require remediation costs.

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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
10. Major Lessees
      The Partnership has four lessees that generate a significant portion of its revenues. Revenues from major lessees that exceed ten percent of total revenues are as follows:
                                                 
                    Commencement of
                    Operations
            (October 17, 2002)
    Year Ended   Year Ended   through
    December 31, 2004   December 31, 2003   December 31, 2002
             
    Revenues   Percent   Revenues   Percent   Revenues   Percent
                         
    (Dollars in thousands)
Lessee A
  $ 13,770       11.3%     $ 9,532       11.2%     $ 1,815       13.1%  
Lessee B
  $ 9,542       7.9%     $ 8,774       10.3%     $ 2,120       15.3%  
Lessee C
  $ 10,340       8.5%     $ 8,879       10.4%     $ 1,994       14.4%  
Lessee D
  $ 18,705       15.4%     $ 15,102       17.7%     $ 710       0.5%  
11. Incentive Plans
      Prior to the Partnership’s initial public offering, GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the “Long-Term Incentive Plan”) for employees and directors of GP Natural Resource Partners LLC and its affiliates who perform services for the Partnership. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.
      On August 19, 2003, the compensation committee amended the Long-Term Incentive Plan to provide only for the issuance of phantom units that are payable solely in cash. In connection with the amendment to the Long-Term Incentive Plan, the compensation committee terminated all of the existing option grants and issued to all of the holders of terminated options a number of phantom units equivalent in value to the terminated options.
      A phantom unit entitles the grantee to receive the fair market value of a common unit in cash upon vesting. The fair market value is determined by taking the average closing price over the last 20 trading days prior to the vesting date. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines, including the period over which the phantom units will vest. Phantom units vest upon a change in control of the Partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s phantom units will be automatically forfeited unless and to the extent the compensation committee provides otherwise.
      GP Natural Resource Partners LLC adopted the Natural Resource Partners Annual Incentive Compensation Plan (the “Annual Incentive Plan”) in October 2002. The Annual Incentive Plan is designed to enhance the performance of GP Natural Resource Partners LLC’s and its affiliates’ key employees by rewarding them with cash awards for achieving annual financial and operational performance objectives. The compensation committee in its discretion may determine individual participants and payments, if any, for each year. The board of directors of GP Natural Resource Partners LLC may amend or change the Annual Incentive Plan at any time. The Partnership reimburses GP Natural Resource Partners LLC for payments and costs incurred under the Annual Incentive Plan.

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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      In February 2004, the board of directors of GP Natural Resource Partners LLC granted to directors and key employees 55,950 additional phantom units that vest in February 2008. There were 183,537 phantom units outstanding at December 31, 2004. The Partnership accrued expenses to be reimbursed to its general partner of $3.5 million and $2.2 million for the years ended December 31, 2004 and 2003 related to these plans. In connection with the Long-Term Incentive Plans, cash payments of $0.9 million and $0.5 million were paid for the years ended December 31, 2004 and 2003. There were no expenses related to these plans in 2002.
12. Subsequent Events
Distributions
      On January 20, 2005, the Partnership announced a $0.025 per unit increase in its quarterly distributions to $0.6625 per unit, or $2.65 per unit on an annualized basis. The distribution is payable on February 14, 2005 to unitholders of record on February 1, 2005.
Acquisitions
      On January 28, 2005, the Partnership signed a definitive agreement to purchase mineral rights to approximately 85 million tons of coal reserves (unaudited) 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 coal reserves are located on approximately 175,000 acres (unaudited) in Virginia, West Virginia and Kentucky with most of the reserves leased under 29 different leases.
13. Supplemental Financial Data
Selected Quarterly Financial Information
                                   
    First   Second   Third   Fourth
2004   Quarter   Quarter   Quarter   Quarter
                 
    (Unaudited)
    (In thousands, except unit data)
Total revenues
  $ 26,362     $ 29,497     $ 34,221     $ 31,352  
Operating income
    14,258       17,472       21,707       16,655  
Net income
  $ 11,174     $ 15,128     $ 19,368     $ 13,324  
Basic and diluted net income per limited partner unit:
                               
 
Common
  $ 0.47     $ 0.58     $ 0.74     $ 0.50  
 
Subordinated
  $ 0.47     $ 0.58     $ 0.74     $ 0.50  
Weighted average number of units outstanding,
                               
Basic and diluted:
                               
 
Common
    11,816       13,987       13,987       13,987  
 
Subordinated
    11,354       11,354       11,354       11,354  

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NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                                   
    First   Second   Third   Fourth
2003   Quarter   Quarter   Quarter   Quarter
                 
Total revenues
  $ 18,070     $ 21,839     $ 23,539     $ 22,018  
Operating income
    8,392       11,757       12,555       11,365  
Net income
  $ 7,973     $ 10,183     $ 10,112     $ 8,639  
Basic and diluted net income per limited partner unit:
                               
 
Common
  $ 0.34     $ 0.44     $ 0.44     $ 0.37  
 
Subordinated
  $ 0.34     $ 0.44     $ 0.44     $ 0.37  
Weighted average number of units outstanding,
                               
Basic and diluted:
                               
 
Common
    11,354       11,354       11,354       11,354  
 
Subordinated
    11,354       11,354       11,354       11,354  
                                   
                From
                Commencement of
                Operations
                (October 17, 2002)
    First   Second   Third   through
2002   Quarter   Quarter   Quarter   December 31, 2002
                 
Total revenues
      (1)       (1)       (1)   $ 13,893  
Operating income
                            6,615  
Net income
                          $ 6,415  
Basic and diluted net income per limited partner unit:
                               
 
Common
                          $ 0.28  
 
Subordinated
                          $ 0.28  
Weighted average number of units outstanding,
                               
Basic and diluted:
                               
 
Common
                            11,354  
 
Subordinated
                            11,354  
 
(1)  No financial data is present for these periods because Natural Resource Partners L.P. was not formed until April 9, 2002 and did not commence operations until October 17, 2002.

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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Partners of Western Pocahontas Properties Limited Partnership
      We have audited the accompanying statements of income, changes in partners’ capital and cash flows of Western Pocahontas Properties Limited Partnership for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We have conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
      In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Western Pocahontas Properties Limited Partnership for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001, in conformity with U.S. generally accepted accounting principles.
  Ernst & Young LLP
Houston, Texas
February 7, 2003

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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
STATEMENTS OF INCOME
                     
    For the    
    Period from    
    January 1    
    through   Year Ended
    October 16,   December 31,
    2002   2001
         
    (In thousands)
Revenues:
               
 
Coal royalties
  $ 17,261     $ 15,458  
 
Timber royalties
    2,774       3,691  
 
Gain on sale of property
    92       3,125  
 
Property tax
    1,221       1,184  
 
Other
    1,219       2,512  
             
   
Total revenues
    22,567       25,970  
Expenses:
               
 
General and administrative
    2,291       2,981  
 
Taxes other than income
    1,438       1,457  
 
Depreciation, depletion and amortization
    3,544       1,369  
             
   
Total expenses
    7,273       5,807  
             
Income from operations
    15,294       20,163  
Other income (expense):
               
 
Interest expense
    (4,786 )     (3,966 )
 
Interest income
    114       270  
 
Reversionary interest
    (561 )     (1,924 )
             
Net income
  $ 10,061     $ 14,543  
             
The accompanying notes are an integral part of these financial statements.

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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
                         
    General Partner   Limited Partners   Total
             
        (In thousands)    
Balance, December 31, 2000
  $ 193     $ 14,733     $ 14,926  
Net income
    146       14,397       14,543  
Cash distributions
    (93 )     9,207 )     (9,300 )
                   
Balance, December 31, 2001
    246       19,923       20,169  
Net income
    101       9,960       10,061  
Cash distributions
    (80 )     (7,920 )     (8,000 )
                   
Balance, October 16, 2002
  $ 267     $ 21,963     $ 22,230  
                   
The accompanying notes are an integral part of these financial statements.

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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
STATEMENTS OF CASH FLOWS
                         
    For the    
    Period from    
    January 1    
    through   Year Ended
    October 16,   December 31,
    2002   2001
         
    (In thousands)
Cash flows from operating activities:
               
 
Net income
  $ 10,061     $ 14,543  
 
Adjustments to reconcile net income to net cash provided by operating activities:
               
   
Depreciation, depletion and amortization
    3,544       1,369  
   
Gain on sale of property
    (92 )     (3,125 )
   
Change in operating assets and liabilities
               
     
Accounts receivable
    (3,684 )     (1,098 )
     
Other assets
    (1,355 )     (4 )
     
Accounts payable — affiliate
          9  
     
Accrued liabilities
    282       49  
     
Deferred revenues
    785       448  
     
Reversionary interest payable
    (865 )     865  
             
       
Net cash provided by operating activities
    8,676       13,056  
             
Cash flows from investing activities:
               
 
Proceeds from sale of properties
    92       3,659  
 
Capital expenditures
    (35,120 )     (974 )
             
       
Net cash provided by (used in) investing activities
    (35,028 )     2,685  
             
Cash flows from financing activities:
               
 
Proceeds from financing
    45,000        
 
Deferred financing costs
    173        
 
Repayment of notes payable
    (7,848 )      
 
Repayment of debt
    (2,377 )     (2,748 )
 
Distributions to partners
    (8,000 )     (9,300 )
 
Cash placed in restricted accounts, net
    (49 )     (2,386 )
 
Cash placed in (returned from) escrow
    1,000       (1,000 )
             
       
Net cash provided by (used in) financing activities
    27,899       (15,434 )
             
NET INCREASE IN CASH AND CASH EQUIVALENTS
    1,547       307  
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    4,415       4,108  
             
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 5,962     $ 4,415  
             
SUPPLEMENTAL CASH FLOW INFORMATION:
               
 
Cash paid during the period for interest
  $ 4,786     $ 3,966  
Non-cash transactions:
               
 
Issuance of note payable for reversionary interest
  $     $ 7,900  
The accompanying notes are an integral part of these financial statements.

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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS
1. Basis of Presentation and Organization
      Western Pocahontas Properties Limited Partnership (“the Partnership”), a Delaware limited partnership, was formed in 1986 to own and manage land and mineral rights and timber located in West Virginia, Kentucky, Alabama, Maryland and Indiana. Western Pocahontas Corporation (“WPC”), a Texas corporation, serves as the general partner. All items of income and loss of the Partnership are allocated 1% to the general partner and 99% to the limited partners.
      The Partnership enters into leases with various third-party operators for the right to mine coal reserves and harvest timber on the Partnership’s land in exchange for royalty payments. Generally, the coal lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments. The timber lessees make payments to the Partnership based on pre-determined rates per board foot harvested.
2. Summary of Significant Accounting Policies
Use of Estimates
      Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Property and Equipment
      Land, coal property and timberlands are carried at cost and include expenditures for additions and improvements, such as roads and land improvements, which substantially increase the productive lives of the existing assets. Maintenance and repair costs are expensed as incurred. Coal properties are depleted on a unit-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein. Timberlands are depleted based on the volume of timber harvested in relation to the amount of estimated merchantable timber volume.
Deferred Financing Costs
      Deferred financing costs consists of legal and other costs related to the issuance of the Partnership’s long-term note payable. These costs are amortized over the term of the note payable.
Revenues
      Coal Royalties. Coal royalty revenues are recognized on the basis of tons of coal sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the coal lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.
      Timber Royalties. Timber is sold on a contract basis where independent contractors harvest and sell the timber. Timber revenues are recognized when the timber has been harvested by the independent contractors.
      Minimum Royalties. Most of the Partnership’s lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue. The deferred revenue attributable to the minimum payment is recognized as coal royalty revenues either when the lessee recoups the minimum payment through production or when the period during which the lessee is allowed to recoup the minimum payment expires.

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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS — (Continued)
Property Taxes
      The Partnership is responsible for paying property taxes on the properties it owns. The lessees are responsible for reimbursing the Partnership for property taxes on the leased properties. The reimbursement of property taxes is included in revenues in the statement of income as property tax.
Income Taxes
      The Partnership is not a taxpaying entity, as the individual partners are responsible for reporting their pro-rata share of the Partnership’s taxable income or loss. In the event of an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities.
New Accounting Standards
      In June 2001, the FASB issued SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets.” SFAS No. 141 eliminates pooling-of-interests accounting and requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. With regard to intangible assets, SFAS No. 141 states that intangible assets acquired in a business combination subsequent to June 30, 2001 should be recognized separately if the benefit of the intangible asset is obtained through contractual rights or if the intangible asset can be sold, transferred, licensed, rented to or exchanged, without regard to the acquirer’s intent. The adoption of SFAS No. 141 did not have a material impact on the 2001 or 2002 financial statements. SFAS No. 142 discontinues goodwill amortization; rather, goodwill will be subject to at least an annual fair-value based impairment test. The adoption of SFAS No. 142 on January 1, 2002 did not have a material impact on our financial statements.
      In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement cost being capitalized as a part of the carrying amount of the long-lived asset. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and a reconciliation of changes in the components of those obligations. The adoption of SFAS No. 143 on January 1, 2003 did not have a material impact on our financial statements.
      In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of” and APB Opinion No. 30, “Reporting the Results of Operations — Reporting the Effects of the Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.” The objective of SFAS No. 144 is to establish one accounting model for long-lived assets to be disposed of by sale as well as resolve implementation issues related to SFAS No. 121. The adoption of SFAS No. 144 effective January 1, 2002 did not have a material impact on our financial position or results of operations.
      In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 62, Amendment of FASB Statement No. 13, and Technical Corrections.” Among other things, SFAS No. 145 will require gains and losses on extinguishments of debt to be classified as income or loss from continuing operations rather than as extraordinary items as previously required under SFAS No. 4. The provisions of this statement related to the rescission of SFAS No. 4 shall be applied in fiscal years beginning after May 15, 2002. Adoption of SFAS No. 145 on January 1, 2003 did not have a material impact on our financial position or results of operations. In July 2002, the FASB issued SFAS No. 146, “Accounting for

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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS — (Continued)
Costs Associated with Exit or Disposal Activities,” which supersedes EITF No. 94-3, “Liability Recognition for Certain Employment Termination Benefits and Other Costs to Exit an Activity.” SFAS No. 146 requires companies to record liabilities for costs associated with exit or disposal activities to be recognized only when the liability is incurred instead of at the date of commitment to an exit or disposal activity. Adoption of this standard is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this standard did not have a significant impact on our financial statements.
3. Reversionary Interest
      The previous owner of the Partnership’s coal and timber properties (CSX Corporation and certain of its affiliates, or “CSX”) retained a reversionary interest in those properties whereby it receives either a 25% or 28% interest in the properties and the net revenues, as defined, from the properties after July 1, 2001, and in the net proceeds, as defined, from any property sale occurring prior to July 1, 2001.
      In 2000, the Partnership sold 1,391 acres of surface land to a third party and paid $1.3 million to CSX related to its reversionary interest in the property. In 2001, the Partnership sold 1,928 acres of surface land to various third parties and paid $936,000 to CSX related to its reversionary interest in these properties (see Note 4).
      In December 2001, the Partnership purchased from CSX its reversionary interest in the Partnership’s Kentucky properties for $2.0 million in cash and a note payable of $7.9 million (see Note 5). The Partnership allocated $8.8 million to coal and timber properties and $1.1 million to a reduction in the reversionary interest payable for the six months ended December 31, 2001.
      In March 2002, the Partnership purchased from CSX its reversionary interest in the remaining assets subject to the reversionary interest. The Partnership allocated $35 million to coal and timber properties and $1.4 million to a reduction in the reversionary interest payable for the period ended October 16, 2002. The purchase was financed with a $45.0 million loan and a portion of the proceeds were used to retire the $7.9 million note that the Partnership issued in December 2001 as part of the consideration for the purchase of the reversionary interest in Kentucky (see Note 4).
4. Long-Term Debt
      Long-term debt consisted of the following:
         
    December 31,
    2001
     
    (In thousands)
7.6% fixed notes payable due April 1, 2013
  $ 50,682  
Less — Current portion of notes payable
    (2,966 )
       
Long-term debt
  $ 47,716  
       
      The notes are collateralized by a mortgage on the Partnership’s properties, a security interest in accounts receivable, other assets and the partners’ interest in the Partnership and the common stock of WPC. The Partnership is required to maintain an aggregate minimum balance of $3.0 million in cash and cash equivalents, which is pledged to its lenders. The Partnership is allowed to make cash distributions to its partners provided no event of default exists, as defined, and the aggregate cash balance is not reduced below $4.0 million by any distribution.
      The Partnership is required to contribute cash or cash equivalents to a debt service account when the Partnership receives royalties related to coal tonnage or timber harvested greater than a predetermined amount or sells certain properties. Pursuant to these provisions, the Partnership contributed $2.1 million

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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS — (Continued)
and $2.4 million to the debt service account for the years ended December 31, 2000 and 2001, respectively.
      On December 10, 2001, the Partnership issued a $7.9 million non-interest bearing note payable to an affiliate of CSX in conjunction with the purchase of CSX’s reversionary interest in properties located in Kentucky (see Note 3), and is subject to a Purchase and Sale Agreement between the CSX affiliate and the Partnership. The note was due and paid-off in March 2002. A discount of $152,000 was imputed for the period ended December 31, 2001 (see Note 3).
      For the nine and one half months ended October 16, 2002 and the year ended December 31, 2001 the Partnership had interest expense of $4.8 million and $3.0 million relating to long term debt.
5. Related Party Transactions
      A company controlled by the owner of WPC provides certain administrative services to the Partnership and charges the Partnership for the direct costs related to the administrative services. The total expenses charged to the Partnership under this arrangement were approximately $500,000 for each of the years ended December 31, 2000 and 2001, and $330,000 for the period from January 1, 2002 through October 16, 2002. These costs are reflected in the general and administrative expenses in the accompanying statements of income.
      The Partnership has a management contract to provide certain management, engineering and accounting services to Great Northern Properties Limited Partnership (“GNP”), a limited partnership which has certain common ownership with the Partnership. The contract provides for a $250,000 annual fee, which is intended to reimburse the Partnership for its expense. This fee is presented as other revenue in the accompanying statement of income. The contract may be canceled upon 90 days advance notice by GNP.
6. Employee Benefit Plans
      Substantially all employees of the Partnership are covered by a noncontributory retirement plan and a defined contribution thrift plan. Under the retirement plan, the Partnership contributes annually an amount equal to one-twelfth of each participant’s base compensation. Participants vest in the retirement plan based on the following:
         
Years of Service   Percent Vested
     
0-4
    50 %
5
    60 %
6
    80 %
7 or more
    100 %
      A participant is fully vested upon termination of employment as a result of death, disability, reduction of labor force or retirement on or after age 55. For each of the years ended December 31, 2000 and 2001, the Partnership contributed approximately $90,000 to the retirement plan. No contribution was required during the period from January 1, 2002 through October 16, 2002.
      Under the thrift plan, participants may contribute up to 12% of their base compensation, subject to a maximum set by IRS regulations, on a tax-deferred basis. The Partnership makes matching contributions equal to 100% of each participant’s contributions to the extent of 3% of base compensation and 50% of each participant’s contributions between 3% and 6% of base compensation. The Partnership’s contribution is 40% vested after two years of service with the vested interest increasing by 20% for each additional year of service. A participant is fully vested as to his own contributions and is fully vested as to the

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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS — (Continued)
Partnership’s contributions upon termination of employment as a result of death, reduction of labor force, disability or retirement on or after age 55. For each of the years ended December 31, 2000 and 2001, the Partnership made matching contributions in an amount of approximately $50,000, and $28,277 during the period from January 1, 2002 through October 16, 2002.
7. Major Lessees
      The Partnership depends on a few lessees for a significant portion of its revenues. Revenues from major lessees that exceed ten percent of total revenues are as follows:
                                 
    For the Period from        
    January 1, 2002    
    through   Year Ended
    October 16, 2002   December 31, 2001
         
    Revenues   Percent   Revenues   Percent
                 
    (Dollars in thousands)
Lessee A
  $ 5,659       25.1 %   $ 4,956       19.1 %
Lessee B
  $ 3,609       16.0 %     5,113       20.5 %
Lessee C
  $ 4,058       18.0 %   $ 2,123       8.2 %
8. Segment Information
      Segment information has been provided in accordance with SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information.” The Partnership’s reportable segments are as follows:
      Coal Royalty. The coal royalty segment is engaged in managing the Partnership’s coal properties.
      Timber Royalty. The Partnership’s timber segment is engaged in the selling of standing timber on the Partnership’s properties.

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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS — (Continued)
      The following is a summary of certain financial information relating to the Partnership’s segments:
                                 
    Coal   Timber   Other   Combined
                 
    (In thousands)
For the year ended December 31, 2001
                               
Revenues
  $ 16,642     $ 3,691     $ 5,637     $ 25,970  
Operating costs and expenses
    3,109       757       572       4,438  
Depreciation, depletion and amortization
    1,035       210       124       1,369  
                         
Operating income
  $ 12,498     $ 2,724     $ 4,941       20,163  
                         
Interest expense
                            (3,966 )
Interest income
                            270  
Reversionary interest
                            (1,924 )
                         
Net income
                          $ 14,543  
                         
Total assets
  $ 63,930     $ 5,903     $ 18,391     $ 88,224  
Capital expenditures
    8,447       494       33       8,974  
 
For the period from January 1, 2002 through October 16, 2002
                               
Revenues
  $ 18,482     $ 2,774     $ 1,311     $ 22,567  
Operating costs and expenses
    2,392       864       473       3,729  
Depreciation, depletion and amortization
    3,084       293       167       3,544  
                         
Operating income
  $ 13,006     $ 1,617     $ 671       15,294  
Interest expense
                            (4,786 )
Interest income
                            114  
Reversionary interest
                            (561 )
                         
Net income
                          $ 10,061  
                         
Total assets
  $ 92,299     $       $ 22,075     $ 125,435  
              11,061                  
Capital expenditures
    29,670       5,450             35,120  
9. Leases
      Total rental and lease expense for the year ended December 31, 2001 and for the period January 1, 2002 through October 16, 2002 were $142,000 and $114,000, respectively.
10. Commitments and Contingencies
Legal
      The Partnership is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Partnership management believes these claims will not have a material effect on the Partnership’s financial position, liquidity or operations.

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WESTERN POCAHONTAS PROPERTIES LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS — (Continued)
Environmental Compliance
      The operations conducted on Partnership properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental. The lessees obtain reclamation bonds and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Employees of the Partnership regularly visit the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. Management believes that the Partnership’s lessees will be able to comply with existing regulations and does not expect any material impact on its financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties for the years ended December 31, 2001, 2002 or the period ended October 16, 2002. The Partnership is not associated with any environmental contamination that may require remediation costs. However, our lessees do, from time to time, conduct reclamation work on our properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, it is not responsible for the costs associated with these reclamation operations. Each of our lessees is required to post a bond assuring that the reclamation will be completed as required by the permit. However, in the event any of our lessees is unable to complete the reclamation obligations and their bonding company likewise fails to meet the obligations or provide money to the state to perform the reclamation, the Partnership could be held liable for these costs.
11. Subsequent Event
      In connection with the formation of Natural Resource Partners L.P. and its public offering of limited partnership units, the Partnership transferred certain coal royalty producing properties that are currently under lease to coal mine operators to Natural Resource Partners L.P. on October 17, 2002, at historical cost. The Partnership also transferred a portion of its deferred revenue and long-term debt to Natural Resource Partners L.P. The Partnership retained a coal reserve property that is leased to a third party that is experiencing permitting problems. Additionally, the Partnership retained unleased coal reserve properties, surface land and timberlands.

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GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP
FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Partners of Great Northern Properties Limited Partnership
      We have audited the accompanying statements of income, changes in partners’ capital and cash flows of Great Northern Properties Limited Partnership for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We have conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
      In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Great Northern Properties Limited Partnership for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001, in conformity with U.S. generally accepted accounting principles.
  Ernst & Young LLP
Houston, Texas
February 7, 2003

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GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP
STATEMENTS OF INCOME
                     
    For the    
    Period from    
    January 1,    
    through   Year Ended
    October 16,   December 31,
    2002   2001
         
    (In thousands)
Revenues:
               
 
Coal royalties
  $ 5,895     $ 7,457  
 
Lease and easement income
    474       787  
 
Gain on sale of property
          439  
 
Property tax
    61       88  
 
Other
    71       31  
             
   
Total revenues
    6,501       8,802  
Expenses:
               
 
General and administrative
    417       611  
 
Taxes other than income
    69       110  
 
Depreciation, depletion, and amortization
    1,979       2,144  
             
   
Total expenses
    2,465       2,865  
             
Income from operations
    4,036       5,937  
Other income (expense):
               
 
Interest expense
    (1,877 )     (3,652 )
 
Interest income
    115       307  
             
Net income
  $ 2,274     $ 2,592  
             
The accompanying notes are an integral part of these financial statements.

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GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP
STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
                         
    General Partner   Limited Partners   Total
             
    (In thousands)
Balance, December 31, 2000
  $ 184     $ 18,201     $ 18,385  
Net income
    26       2,566       2,592  
Cash distributions
    (9 )     (842 )     (851 )
                   
Balance, December 31, 2001
    201       19,925       20,126  
Net income
    23       2,251       2,274  
Cash distributions
    (7 )     (654 )     (661 )
                   
Balance, October 16, 2002
  $ 217     $ 21,522     $ 21,739  
                   
The accompanying notes are an integral part of these financial statements.

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GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP
STATEMENTS OF CASH FLOWS
                         
    For the    
    Period from    
    January 1,    
    through   Year Ended
    October 16,   December 31,
    2002   2001
         
    (In thousands)
Cash flows from operating activities:
               
 
Net income
  $ 2,274     $ 2,592  
 
Adjustments to reconcile net income to net cash provided by operating activities:
               
   
Depletion and amortization
    1,979       2,144  
   
Gain on sale of property
          (439 )
   
Deferred revenue
    30       (263 )
   
Change in operating assets and liabilities
               
     
Accounts receivable
    (620 )     (99 )
     
Other assets
    (46 )     (2 )
     
Accounts payable and accrued interest
    108       (256 )
             
       
Net cash provided by operating activities
    3,725       3,677  
             
Cash flows from investing activities:
               
 
Proceeds from sale of properties
          475  
             
       
Net cash provided by investing activities
          475  
             
Cash flows from financing activities:
               
 
Repayment of debt
    (1,125 )     (1,500 )
 
Partners’ distributions
    (661 )     (851 )
 
Cash placed in restricted accounts, net
    (2,283 )     (2,213 )
             
       
Net cash used in financing activities
    (4,069 )     (4,564 )
             
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    (344 )     (412 )
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    749       1,161  
             
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 405     $ 749  
             
SUPPLEMENTAL CASH FLOW INFORMATION:
               
 
Cash paid during the period for interest
  $ 1,877     $ 4,018  
             
The accompanying notes are an integral part of these financial statements.

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GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS
1. Basis of Presentation and Organization
      Great Northern Properties Limited Partnership (“the Partnership”), a Delaware limited partnership, was formed in 1992 to own and manage land and mineral rights located in Montana, North Dakota, Wyoming, Illinois and Washington. GNP Management Corporation (“GNP”), a Delaware corporation, serves as its general partner. All items of income and loss of the Partnership are allocated 1% to the general partner and 99% to the limited partners. In 1999, a limited partner’s interest in the Partnership was redeemed by the partners for $1,000.
      The Partnership enters into leases with various coal mine operators for the right to mine coal reserves on the Partnership’s land in exchange for royalty payments. Generally, the lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.
2. Summary of Significant Accounting Policies
Use of Estimates
      Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Property and Equipment
      Land and coal property are carried at cost and include expenditures for additions and improvements, such as roads and land improvements, which substantially increase the productive lives of the existing assets. Maintenance and repair costs are expensed as incurred. Coal properties are depleted on a unit-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein.
Deferred Financing Costs
      Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s long-term debt. These costs are amortized over the term of the debt.
Revenues
      Coal Royalties. Coal royalty revenues are recognized on the basis of tons of coal sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.
      Lease and Easement Income. Lease and easement income is generated through contracts with third parties for use of the Partnership’s land for transportation of coal mined on adjacent properties, agricultural grazing and recreational uses.
      Minimum Royalties. Most of the Partnership’s lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue. The deferred revenue attributable to the minimum payment is recognized as coal royalty revenues either when the lessee recoups the minimum payment through production or when the period during which the lessee is allowed to recoup the minimum payment expires.

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GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS — (Continued)
Property Taxes
      The Partnership is responsible for paying property taxes on the properties it owns. The lessees are responsible for reimbursing the Partnership for property taxes on the leased properties. The reimbursement of property taxes is included in revenues in the statement of income as property tax.
Income Taxes
      The Partnership is not a taxpaying entity, as the individual partners are responsible for reporting their pro rata share of the Partnership’s taxable income or loss. In the event of an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities
New Accounting Standards
      In June 2001, the FASB issued SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets.” SFAS No. 141 eliminates pooling-of-interests accounting and requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. With regard to intangible assets, SFAS No. 141 states that intangible assets acquired in a business combination subsequent to June 30, 2001 should be recognized separately if the benefit of the intangible asset is obtained through contractual rights or if the intangible asset can be sold, transferred, licensed, rented to or exchanged, without regard to the acquirer’s intent. The adoption of SFAS No. 141 did not have a material impact on the 2001 or 2002 financial statements. SFAS No. 142 discontinues goodwill amortization; rather, goodwill will be subject to at least an annual fair-value based impairment test. The adoption of SFAS No. 142 on January 1, 2002 did not have a material impact on our financial statements.
      In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement cost being capitalized as a part of the carrying amount of the long-lived asset. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and a reconciliation of changes in the components of those obligations. The adoption of SFAS No. 143 on January 1, 2003 did not have a material impact on our financial statements.
      In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of” and APB Opinion No. 30, “Reporting the Results of Operations — Reporting the Effects of the Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.” The objective of SFAS No. 144 is to establish one accounting model for long-lived assets to be disposed of by sale as well as resolve implementation issues related to SFAS No. 121. The adoption of SFAS No. 144 effective January 1, 2002 did not have a material impact on our financial position or results of operations.
      In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 62, Amendment of FASB Statement No. 13, and Technical Corrections.” Among other things, SFAS No. 145 will require gains and losses on extinguishments of debt to be classified as income or loss from continuing operations rather than as extraordinary items as previously required under SFAS No. 4. The provisions of this statement related to the rescission of SFAS No. 4 shall be applied in fiscal years beginning after May 15, 2002. Adoption of SFAS No. 145 on January 1, 2003 did not have a material impact on our financial position or results of operations.

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GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS — (Continued)
      In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which supersedes EITF No. 94-3, “Liability Recognition for Certain Employment Termination Benefits and Other Costs to Exit an Activity.” SFAS No. 146 requires companies to record liabilities for costs associated with exit or disposal activities to be recognized only when the liability is incurred instead of at the date of commitment to an exit or disposal activity. Adoption of this standard is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this standard did not have a significant impact on our financial statements.
3. Nonparticipating Royalty Interest
      The previous owner of the Partnership’s coal properties, Meridian Minerals Company (“Meridian”), a subsidiary of Burlington Resources, Inc., retained a nonparticipating royalty interest in certain properties, which were not leased at the time of acquisition, at a royalty rate ranging from 2% to 5%. Such properties are presently not leased. In the event any of the properties subject to the nonparticipating royalty interest are sold to a third party, Meridian will receive a certain percentage of the selling price as defined in the asset purchase agreement.
4. Long-Term Debt
      Long-term debt consisted of the following:
         
    December 31,
    2001
     
    (In thousands)
Floating rate notes, bearing interest at 4.70 percent at December 31, 2001 due September 30, 2004
  $ 48,625  
Less — Current portion of notes payable
    (1,500 )
       
Long-term debt
  $ 47,125  
       
      The notes are collateralized by a mortgage on the Partnership’s properties, a security interest in accounts receivable, other assets, the partners’ interest in the Partnership and the debt service account established by the Partnership. The debt service account is funded quarterly with 100% of the Partnership’s cash flows, defined as all cash revenue received by the Partnership, net of any operating expenses, management fees and up to a maximum of 20% of positive operating income to be used to pay the income tax liabilities of the partners as they relate to the Partnership properties, except that the Partnership may maintain $250,000 in cash for general operating purposes. The debt service account will be used to collateralize the notes until the balance of the account reaches a minimum of $10.0 million, after which the amount in excess of $10.0 million may be applied directly to the outstanding balance of the notes. The Partnership contributed $4.7 million and $2.2 million to the debt service account for the years ended December 31, 2000 and 2001, respectively, and $2.3 million for the period from January 1, 2002 through October 16, 2002.
      For the nine and one half months ended October 16, 2002 and the year ended December 31, 2001 the Partnership had interest expense of $1.9 million and $3.7 million relating to long term debt.
5. Related Party Transactions
      The Partnership has a management contract to receive management, engineering and accounting services from Western Pocahontas Properties Limited Partnership (“WPP”), a limited partnership which has some common ownership with the Partnership. The contract provides for a $250,000 fee to be paid annually. Such amounts are reflected in general and administrative expenses in the statements of income. The contract may be canceled upon 90 days advance notice to the Partnership.

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GREAT NORTHERN PROPERTIES LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS — (Continued)
6. Major Lessees
      The Partnership depends on a few lessees for a significant portion of its revenues. Revenues from major lessees that exceed ten percent of total revenues are as follows:
                                 
    For the period from        
    January 1, 2002    
    through   Year Ended
    October 16, 2002   December 31, 2001
         
    Revenues   Percent   Revenues   Percent
                 
Lessee A
  $ 3,302       50.7 %   $ 5,324       60.5 %
Lessee B
    1,311       20.1 %     1,634       18.6 %
7. Commitments and Contingencies
Legal
      The Partnership is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Partnership management believes these claims will not have a material effect on the Partnership’s financial position, liquidity or operations.
Environmental Compliance
      The operations conducted on Partnership properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental. The lessees obtain reclamation bonds and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Employees regularly visit the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. Management believes that the Partnership’s lessees will be able to comply with existing regulations and does not expect any material impact on its financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties for the years ended December 31, 2000 and 2001 and for the period ended October 16, 2002. The Partnership is not associated with any environmental contamination that may require remediation costs. However, our lessees do, from time to time, conduct reclamation work on our properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, it is not responsible for the costs associated with these reclamation operations. Each of our lessees is required to post a bond assuring that the reclamation will be completed as required by the permit. However, in the event any of our lessees is unable to complete the reclamation obligations and their bonding company likewise fails to meet the obligations or provide money to the state to perform the reclamation, the Partnership could be held liable for these costs.
8. Subsequent Event
      In connection with the formation of Natural Resource Partners L.P. and its public offering of limited partnership units, the Partnership transferred certain coal royalty producing properties that are currently under lease to coal mine operators to Natural Resource Partners L.P. on October 17, 2002, at historical cost. The Partnership also transferred a portion of its deferred revenue and long-term debt to Natural Resource Partners L.P. The Partnership retained unleased coal reserve properties and surface land.

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NEW GAULEY COAL CORPORATION
FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Stockholders of New Gauley Coal Corporation
      We have audited the accompanying statements of income, changes in stockholders’ deficit and cash flows of New Gauley Coal Corporation for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We have conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
      In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of New Gauley Coal Corporation for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001, in conformity with U.S. generally accepted accounting principles.
  Ernst & Young LLP
Houston, Texas
February 7, 2003

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NEW GAULEY COAL CORPORATION
STATEMENTS OF INCOME
                     
    For the    
    Period From    
    January 1,    
    Through   Year Ended
    October 16,   December 31,
    2002   2001
         
    (In thousands)
Revenues:
               
 
Coal royalties
  $ 1,434     $ 1,609  
 
Gain on sale of property
          25  
 
Property tax
    20       28  
 
Other
    53       61  
             
   
Total revenues
    1,507       1,723  
Expenses:
               
 
General and administrative
    52       41  
 
Taxes other than income
    42       45  
 
Depletion and amortization
    138       212  
             
   
Total expenses
    232       298  
             
Income from operations
    1,275       1,425  
Other income (expense):
               
 
Interest expense
    (97 )     (132 )
 
Interest income
    24       15  
 
Reversionary interest
    (104 )     (85 )
             
Net income
  $ 1,098     $ 1,223  
             
The accompanying notes are an integral part of these financial statements.

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NEW GAULEY COAL CORPORATION
STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT
                         
        Accumulated    
    Common Stock   Deficit   Total
             
    (In thousands)
Balance, December 31, 2000
  $ 2,137     $ (3,126 )   $ (989 )
Net income
          1,223       1,223  
Dividends
          (1,000 )     (1,000 )
                   
Balance, December 31, 2001
    2,137       (2,903 )     (766 )
Net income
          1,098       1,098  
Dividends
          (400 )     (400 )
                   
Balance, October 16, 2002
  $ 2,137     $ (2,205 )   $ (68 )
                   
The accompanying notes are an integral part of these financial statements.

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NEW GAULEY COAL CORPORATION
STATEMENTS OF CASH FLOWS
                         
    For the    
    Period From    
    January 1,    
    Through   Year Ended
    October 16,   December 31,
    2002   2001
         
    (In thousands)
Cash flows from operating activities:
               
 
Net income
  $ 1,098     $ 1,223  
 
Adjustments to reconcile net income to net cash provided by operating activities:
               
   
Depletion and amortization
    138       212  
   
Decrease in deferred revenues
    (280 )     (146 )
   
Gain on sale of property
          (25 )
   
Change in operating assets and liabilities Accounts receivable
    (43 )     (12 )
     
Other assets
    (30 )     (15 )
     
Accrued liabilities
    (16 )     86  
             
       
Net cash provided by operating Activities
    867       1,323  
             
Cash flows from investing activities:
               
 
Investment in note receivable
          (200 )
 
Proceeds from sale of properties
          25  
             
       
Net cash used in investing activities
          (175 )
             
Cash flows from financing activities:
               
 
Repayment of debt
    (74 )     (91 )
 
Dividends
    (400 )     (1,000 )
             
       
Net cash used in financing activities
    (474 )     (1,091 )
             
NET INCREASE IN CASH AND CASH EQUIVALENTS
    393       57  
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    399       342  
             
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 792     $ 399  
             
SUPPLEMENTAL CASH FLOW INFORMATION:
               
 
Cash paid during the period for interest
  $ 97     $ 132  
The accompanying notes are an integral part of these financial statements.

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NEW GAULEY COAL CORPORATION
NOTES TO FINANCIAL STATEMENTS
1. Basis of Presentation and Organization
      New Gauley Coal Corporation (“the Company”), a West Virginia subchapter S corporation, was incorporated in 1918 to own and manage land and mineral rights. The Company owns property in Alabama and West Virginia.
      The Company enters into leases with various coal mine operators for the right to mine coal reserves on the Company’s land in exchange for royalty payments. Generally, the lessees make payments to the Company based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.
2. Summary of Significant Accounting Policies
Use of Estimates
      Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Property and Equipment
      Land and coal property are carried at cost and include expenditures for additions and improvements, such as roads and land improvements, which substantially increase the productive lives of the existing assets. Maintenance and repair costs are expensed as incurred. Coal properties are depleted on a unit-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein.
Deferred Financing Costs
      Deferred financing costs consist of legal and other costs related to the issuance of the Company’s long-term note payable. These costs are amortized over the term of the note payable.
Revenues
      Coal Royalties. Coal royalty revenues are recognized on the basis of tons of coal sold by the Company’s lessees and the corresponding revenue from those sales. Generally, the lessees make payments to the Company based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.
      Minimum Royalties. Most of the Company’s lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue. The deferred revenue attributable to the minimum payment is recognized as coal royalty revenues either when the lessee recoups the minimum payment through production or when the period during which the lessee is allowed to recoup the minimum payment expires.
Property Taxes
      The Company is responsible for paying property taxes on the properties it owns. One of the lessees is not responsible for reimbursing the Company for property taxes on the leased properties. The reimbursement of property taxes is included in revenues in the statement of income as property tax.

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NEW GAULEY COAL CORPORATION
NOTES TO FINANCIAL STATEMENTS — (Continued)
Income Taxes
      The Company is not a taxpaying entity, as the individual stockholders are responsible for reporting their pro rata share of the Company’s taxable income or loss. In the event of an examination of the shareholders’ tax return, the tax liability of the shareholders could be changed if an adjustment in the shareholders’ income is ultimately sustained by the taxing authorities.
New Accounting Standards
      In June 2001, the FASB issued SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets.” SFAS No. 141 eliminates pooling-of-interests accounting and requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. With regard to intangible assets, SFAS No. 141 states that intangible assets acquired in a business combination subsequent to June 30, 2001 should be recognized separately if the benefit of the intangible asset is obtained through contractual rights or if the intangible asset can be sold, transferred, licensed, rented to or exchanged, without regard to the acquirer’s intent. The adoption of SFAS No. 141 did not have a material impact on the 2001 or 2002 financial statements. SFAS No. 142 discontinues goodwill amortization; rather, goodwill will be subject to at least an annual fair-value based impairment test. The adoption of SFAS No. 142 on January 1, 2002 did not have a material impact on our financial statements.
      In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement cost being capitalized as a part of the carrying amount of the long-lived asset. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and a reconciliation of changes in the components of those obligations. The adoption of SFAS No. 143 on January 1, 2003 did not have a material impact on our financial statements.
      In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of” and APB Opinion No. 30, “Reporting the Results of Operations — Reporting the Effects of the Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.” The objective of SFAS No. 144 is to establish one accounting model for long-lived assets to be disposed of by sale as well as resolve implementation issues related to SFAS No. 121. The adoption of SFAS No. 144 effective January 1, 2002 did not have a material impact on our financial position or results of operations.
      In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 62, Amendment of FASB Statement No. 13, and Technical Corrections.” Among other things, SFAS No. 145 will require gains and losses on extinguishments of debt to be classified as income or loss from continuing operations rather than as extraordinary items as previously required under SFAS No. 4. The provisions of this statement related to the rescission of SFAS No. 4 shall be applied in fiscal years beginning after May 15, 2002. Adoption of SFAS No. 145 on January 1, 2003 did not have a material impact on our financial position or results of operations.
      In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which supersedes EITF No. 94-3, “Liability Recognition for Certain Employment Termination Benefits and Other Costs to Exit an Activity.” SFAS No. 146 requires companies to record liabilities for costs associated with exit or disposal activities to be recognized only when the liability is incurred instead of at the date of commitment to an exit or disposal activity. Adoption of this standard is

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NEW GAULEY COAL CORPORATION
NOTES TO FINANCIAL STATEMENTS — (Continued)
effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this standard did not have a significant impact on our financial statements.
3. Reversionary Interest
      The previous owner of a portion of the Company’s coal properties (CSX Corporation and certain of its affiliates, or “CSX”) retained a reversionary interest in certain of those properties whereby it receives a 25% interest in the properties and the net revenues, as defined, from the properties after July 1, 2001, and in the net proceeds, as defined, of any property sale occurring prior to July 1, 2001. The reversionary interest only applies to the Company’s Alabama property. In March 2002, Western Pocahontas Properties Limited Partnership (the “Partnership”), who formerly owned the Company, purchased the reversionary interest from CSX. As a result of this transaction, the Alabama property is now owned 25% by the Partnership and 75% by the Company.
4. Note Receivable
      In June 2001, the Company loaned $200,000 to a third party. The agreement requires the third party to use the proceeds to develop certain coal properties it owned. In exchange for the loan, the Company will receive a royalty on coal produced from the developed properties. The total royalty received by the Company is limited to the greater of $200,000 plus 15% interest per year or $240,000. If no royalties are received by June 2005, the third party is required to repay the note with interest. Through the period ended October 16, 2002, the Company has accrued approximately $39,000 of interest income related to this note. This agreement may be terminated at any time by the third party by repaying the note under the terms described above.
5. Long-Term Debt
      Long-term debt consisted of the following:
         
    December 31,
    2001
     
    (In thousands)
7.6% fixed note payable due April 1, 2013
  $ 1,683  
Less — Current portion of note payable
    (99 )
       
Long-term debt
  $ 1,584  
       
      The note is collateralized by a mortgage on the Company’s properties, a security interest in accounts receivable, other assets, the stockholders’ interest in the Company and the debt service account established by the Company. The notes are guaranteed by the Partnership.
      The Company is required to contribute cash or cash equivalents to a debt service account when the Company receives royalties greater than a predetermined amount or sells qualified properties. The Company was not required to contribute to the debt service account for the years ended December 31, 2001, or the period ended October 16, 2002.
      For the nine and one half months ended October 16, 2002 and the year ended December 31, 2001 the Partnership had interest expense of $0.1 million and $0.1 million relating to long term debt.

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NEW GAULEY COAL CORPORATION
NOTES TO FINANCIAL STATEMENTS — (Continued)
6. Major Lessees
      The Company depends on a few lessees for a significant portion of its revenues. Revenues from major lessees that exceed ten percent of total revenues are as follows:
                                 
    For the Period from        
    January 1, 2002    
    through   Year Ended
    October 16, 2002   December 31, 2001
         
    Revenues   Percent   Revenues   Percent
                 
Lessee A
  $ 561       37.2%     $ 985       57.2%  
Lessee B
    858       56.9%       624       36.2%  
7. Commitments and Contingencies
Legal
      The Company is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Company management believes these claims will not have a material effect on the Company’s financial position, liquidity or operations.
Environmental Compliance
      The operations conducted on Company properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Company may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Company’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental. The lessees obtain reclamation bonds and substantially all of the leases require the lessee to indemnify the Company against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Employees of the Company regularly visit the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. Management believes that the Company’s lessees will be able to comply with existing regulations and does not expect any material impact on its financial condition or results of operations. The Company has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties for the years ended December 31, 2001, and period ended October 16, 2002. The Company is not associated with any environmental contamination that may require remediation costs. However, our lessees do, from time to time, conduct reclamation work on our properties under lease to them. Because the Company is not the permittee of the mines being reclaimed, it is not responsible for the costs associated with these reclamation operations. Each of our lessees is required to post a bond assuring that the reclamation will be completed as required by the permit. However, in the event any of our lessees is unable to complete the reclamation obligations and their bonding company likewise fails to meet the obligations or provide money to the state to perform the reclamation, the Company could be held liable for these costs.
8. Subsequent Event
      In connection with the formation of Natural Resource Partners L.P. and its public offering of limited partnership units, the Company transferred certain coal royalty producing properties that are currently under lease to coal mine operators to Natural Resource Partners L.P. on October 17, 2002 at historical cost The Company transferred a portion of its deferred revenue and all its long-term debt to Natural Resource Partners L.P. The Company retained unleased coal reserve properties.

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ARCH COAL CONTRIBUTED PROPERTIES
FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Stockholders and Board of Directors
Arch Coal, Inc.
      We have audited the accompanying statements of revenues and direct coasts and expenses of Arch Coal Contributed Properties for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We have conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
      As described in Note 1, the accompanying financial statements have been prepared solely to present the revenue and direct costs and expenses of the acquired properties for the period January 1, 2002 through October 16, 2002 and the year ended December 31, 2001, for the purpose of complying with the requirements of the Securities and Exchange Commission and are not intended to be a complete presentation of the financial position and results of operations of the acquired properties on a stand-alone basis.
      In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct costs and expenses of Arch Coal Contributed Properties for the period January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001, in conformity with U.S. generally accepted accounting principles.
  Ernst & Young LLP
St. Louis, Missouri
February 11, 2003

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ARCH COAL CONTRIBUTED PROPERTIES
STATEMENTS OF REVENUES AND DIRECT COSTS AND EXPENSES
                   
    For the    
    Period    
    January 1    
    through   Year Ended
    October 16,   December 31,
    2002   2001
         
    (In thousands)
Revenues:
               
 
Coal royalties
  $ 14,768     $ 18,415  
 
Other royalties
    1,349       1,363  
 
Property taxes
    1,179       1,033  
             
 
Total revenues
    17,296       20,811  
Direct costs and expenses:
               
 
Depletion
    4,889       6,382  
 
Property taxes
    1,179       1,033  
 
Other expense
    528       283  
 
Total expenses
    6,596       7,698  
             
Excess of revenues over direct costs and expenses
  $ 10,700     $ 13,113  
             
The accompanying notes are an integral part of these financial statements.

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ARCH COAL CONTRIBUTED PROPERTIES
NOTES TO FINANCIAL STATEMENTS
1. Basis of Presentation
      Ark Land Company (“Ark Land”) is a wholly owned subsidiary of Arch Coal, Inc. (“Arch Coal”). Ark Land owns and manages land and mineral rights primarily located in the Western, Central Appalachian and the Illinois Basins. In conjunction with the formation of Natural Resource Partners L. P. (“NRP”), Ark Land contributed a number of owned land and coal interests on which coal leasing activity occurs (“Contributed Properties”) to NRP. Ark Land retained owned land and mineral reserves with no leasing activity as well as other land and mineral reserves controlled through leasing arrangements. The accompanying statements have been prepared on Ark Land’s historical cost basis in the Contributed Properties.
      The Contributed Properties was not a legal entity and, except for revenues earned from the properties and certain direct costs and expenses of the properties and assets acquired and liabilities assumed, no separate financial information was maintained. The Contributed Properties did not maintain stand-alone corporate treasury, legal, tax, human resources, general administration and other similar corporate support functions. Corporate general and administrative expenses have not been allocated to the Contributed Properties, nor were they allocated in connection with the preparation of the accompanying statements because there was not sufficient information to develop a reasonable cost allocation. Because the separate and distinct accounts necessary to present a balance sheet and income statements of the Contributed Properties were not maintained for the period from January 1 through October 16, 2002 and for the two years ended December 31, 2001. Statements of Revenues and Direct Costs and Expenses were prepared.
      The accompanying Statements of Revenues and Direct Costs and Expenses and Statement of Assets Purchased and Liabilities Assumed are not intended to be a complete presentation of financial position and the results of operations of the Contributed Properties. The accompanying financial statements have been prepared to comply with the requirements of the Securities and Exchange Commission for inclusion in the annual report on Form 10-K of NRP.
      With respect to cash flows, the Contributed Properties did not maintain cash accounts. Cash receipts and expenditures are maintained by Ark Land. A description of cash flows directly attributable to the Contributed Properties is included in Note 5.
2. Accounting Policies
Accounting Estimates
      Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Coal Properties
      Coal properties are carried at cost. Coal properties are depleted on a unit-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral properties and estimated proven tonnage therein. Depletion occurs either as Arch Coal mines on the property, or as others mine on the property through leasing transactions.
Revenues
      Coal Royalties. Coal royalty revenues are recognized on the basis of tons of coal sold by the Contributed Properties’ lessees and the corresponding revenue from those sales. Generally, the coal lessees

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ARCH COAL CONTRIBUTED PROPERTIES
NOTES TO FINANCIAL STATEMENTS — (Continued)
make payments to the Contributed Properties based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum annual or quarterly payments.
      Minimum Royalties. Most of the Contributed Properties’ lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue. The deferred revenue attributable to the minimum payment is recognized as coal royalty revenues either when the lessee recoups the minimum payment through production or when the period during which the lessee is allowed to recoup the minimum payment expires.
Property Taxes
      Ark Land is responsible for paying property taxes on the properties it owns. The lessees are responsible for reimbursing Ark Land for property taxes on the leased properties. The reimbursement of property taxes is included in revenues in the statement of revenues and direct costs and expenses as property tax.
New Accounting Standards
      While these financial statements are not intended to be a complete presentation of financial statements prepared in conformity with accounting principles generally accepted in the United States, the following recent accounting pronouncements are included in consideration of potential impacts associated with the accounts included in these financial statements.
      In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement cost being capitalized as a part of the carrying amount of the long-lived asset. SFAS No. 143 also includes disclosure requirements that provide a description of asset retirement obligations and a reconciliation of changes in the components of those obligations. The Contributed Properties have adopted SFAS No. 143 effective January 1, 2003 and it did not have a material affect.
3. Related Party Transactions
      Certain of the Contributed Properties were leased to affiliates of Arch Coal that mine on the properties. Contracted royalty rates from these affiliates (“affiliate royalties”) for the period from January 1, 2002 through October 16, 2002 and the two years ended December 31, 2001 were 6.5% of the gross sales price of coal sold from the property using underground mining methods and 7.5% of the gross sales price of coal sold from the property using surface mining methods, which are similar to those that are received from third parties. Affiliate royalties amounted to $7.7 million, $10.5 million and $10.2 million during the period from January 1, 2002 through October 16, 2002 and the two years ended December 31, 2001.

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ARCH COAL CONTRIBUTED PROPERTIES
NOTES TO FINANCIAL STATEMENTS — (Continued)
4. Major Lessees
      The Contributed Properties depended on a few lessees for a significant portion of its revenues. Revenues from major lessees that exceed 10% of total revenues, are as follows:
                                 
    For the Period from        
    January 1, 2002    
    through   Year Ended
    October 16, 2002   December 31, 2001
         
    Revenues   Percent   Revenues   Percent
                 
    (Dollars in thousands)
Arch Coal
  $ 7,741       45 %   $ 10,492       50 %
Lessee A
    4,093       24 %     4,895       23 %
5. Cash Flow
      The Contributed Properties do not maintain cash accounts. Cash receipts and expenditures are maintained by Ark Land. However, the following information is provided to identify direct cash flows generated from the Contributed properties:
                     
    Period Ended   Year Ended
    October 16,   December 31,
    2002   2001
         
Cash flows from Contributed Properties
               
 
Excess of revenues over direct costs and expenses
  $ 10,700     $ 13,113  
 
Adjustments to reconcile to net cash provided from Contributed Properties:
               
   
Depletion
    4,889       6,382  
   
Write-down of impaired assets
           
 
Change in working capital:
               
   
Accounts receivable
    (269 )     115  
   
Property tax payable
    (140 )     (148 )
   
Deferred royalties
    1       374  
             
 
Direct cash flow from Contributed Properties
  $ 15,181     $ 19,836  
             
6. Environmental Compliance
      The operations conducted on our property by our lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, Ark Land may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of Ark Land’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental. The lessees obtain reclamation bonds and substantially all of the leases require the lessee to indemnify the Contributed Properties against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Employees of Ark Land regularly visit the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. Management of Ark Land believes that Ark Land’s lessees will be able to comply with existing regulations and does not expect any material impact on its financial condition or results of operations of the Contributed Properties. Ark Land has neither incurred, nor is aware of, any material environmental charges imposed on it related to the Contributed Properties for the period from January 1, 2002 to October 16, 2002 and the two years ended December 31, 2001.

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ARCH COAL CONTRIBUTED PROPERTIES
NOTES TO FINANCIAL STATEMENTS — (Continued)
7. Subsequent Event
      In connection with the formation of Natural Resource Partners L.P. and the consummation of its initial public offering of limited partnership units, Arch Coal transferred certain coal royalty producing properties that are currently under lease to coal mine operators to Natural Resource Partners L.P. on October 17, 2002 at fair market value.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
      None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
      We carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act) as of December 31, 2004. This evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of GP Natural Resource Partners LLC, our managing general partner. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and procedures are effective in producing the timely recording, processing, summary and reporting of information and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure.
Management’s Report on Internal Control Over Financial Reporting
      Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2004 based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2004.
      Management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included below in this Item 9A.
Attestation Report of Independent Registered Public Accounting Firm
      We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Natural Resource Partners L.P. maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Natural Resource Partners L.P.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the partnership’s internal control over financial reporting based on our audit.
      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
      A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance

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of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
      In our opinion, management’s assessment that Natural Resource Partners L.P. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Natural Resource Partners L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.
      We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2004 and 2003, and the related consolidated statements of income, partners’ capital, and cash flows for each of the two years in the period ended December 31, 2004 and for the period from commencement of operations (October 17, 2002) through December 31, 2002 of Natural Resource Partners L.P. and our report dated February 21, 2005, expressed an unqualified opinion thereon.
  Ernst & Young LLP
Houston, Texas
February 21, 2005
Item 9B. Other Information
      None.

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PART III
Item 10. Directors and Executive Officers of the General Partner
      As a master limited partnership we do not employ any of the people responsible for the management of our properties. Instead, we reimburse our managing general partner, GP Natural Resource Partners LLC, for its services. All directors and officers are elected by our managing general partner. The following table sets forth information concerning the directors and officers of GP Natural Resource Partners LLC. Each officer and director is elected for their respective office or directorship on an annual basis. Unless otherwise noted below, the individuals served as officers or directors of the partnership since the initial public offering.
             
Name   Age   Position with the General Partner
         
Corbin J. Robertson, Jr
    57     Chairman of the Board and Chief Executive Officer
Nick Carter
    58     President and Chief Operating Officer
Dwight L. Dunlap
    51     Chief Financial Officer and Treasurer
Kevin F. Wall
    48     Vice President and Chief Engineer
Kathy E. Hager
    53     Vice President Investor Relations
Wyatt L. Hogan
    33     Vice President, General Counsel and Secretary
Corbin J. Robertson II
    34     Vice President Acquisitions
Kenneth Hudson
    50     Controller
Robert T. Blakely
    63     Director
David M. Carmichael
    66     Director
Robert B. Karn III
    63     Director
Alex T. Krueger
    31     Director
S. Reed Morian
    58     Director
W. W. Scott, Jr
    59     Director
Stephen P. Smith
    44     Director
      Corbin J. Robertson, Jr. is the Chief Executive Officer and Chairman of the Board of Directors of GP Natural Resource Partners LLC. Mr. Robertson has served as the Chief Executive Officer and Chairman of the Board of the general partners of Western Pocahontas Properties Limited Partnership since 1986, Great Northern Properties Limited Partnership since 1992 and Quintana Minerals Corporation since 1978 and as Chairman of the Board of Directors of New Gauley Coal Corporation since 1986. Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation are all affiliates of Natural Resource Partners L.P. He also serves as Chairman of the Board of the Baylor College of Medicine and of the Cullen Trust for Higher Education and on the boards of the American Petroleum Institute, the National Petroleum Council, the Texas Medical Center and the World Health and Golf Association. Mr. Robertson is the father of Corbin J. Robertson III, the Vice President — Acquisitions.
      Nick Carter is the President and Chief Operating Officer of GP Natural Resource Partners LLC. He has also served as President of the general partner of Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation since 1990 and as President of the general partner of Great Northern Properties Limited Partnership from 1992 to 1998. Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation are all affiliates of Natural Resource Partners L.P. Prior to 1990, Mr. Carter held various positions with MAPCO Coal Corporation and was engaged in the private practice of law. He is President of the National Council of Coal Lessors, a past Chair of the West Virginia Chamber of Commerce and a board member of the Kentucky Coal Association.

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      Dwight L. Dunlap is the Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC. Mr. Dunlap has served as Vice President and Treasurer of Quintana Minerals Corporation and as Chief Financial Officer, Treasurer and Secretary of the general partner of Western Pocahontas Properties Limited Partnership and Great Northern Properties Limited Partnership since 2000. Mr. Dunlap has worked for Quintana Minerals since 1982 and has served as Vice President and Treasurer since 1987. Mr. Dunlap is a Certified Public Accountant with over 28 years of experience in financial management, accounting and reporting including six years of audit experience with an international public accounting firm.
      Kevin F. Wall is Vice President and Chief Engineer of GP Natural Resource Partners LLC. Mr. Wall has served as Vice President — Engineering for the general partner of Western Pocahontas Properties Limited Partnership since 1998 and the general partner of Great Northern Properties Limited Partnership since 1992. He has also served as the Vice President — Engineering of New Gauley Coal Corporation since 1998. He has performed duties in the land management, planning, project evaluation, acquisition and engineering areas since 1981. He is a Registered Professional Engineer in West Virginia and is a member of the American Institute of Mining, Metallurgical, and Petroleum Engineers and of the National Society of Professional Engineers. Mr. Wall also serves on the Board of Directors of Leadership Tri-State and is a past president of the West Virginia Society of Professional Engineers
      Kathy E. Hager is Vice President — Investor Relations of GP Natural Resource Partners LLC. Ms. Hager joined NRP in July 2002. She was the Principal of IR Consulting Associates from 2001 to July 2002 and from 1980 through 2000 held various financial and investor relations positions with Santa Fe Energy Resources, most recently as Vice President — Public Affairs. She is a Certified Public Accountant. Ms. Hager has served on the local board of directors of the National Investor Relations Institute and has maintained professional affiliations with various energy industry organizations. She has also served on the Executive Committee and as a National Vice President of the Institute of Management Accountants.
      Wyatt L. Hogan is Vice President, General Counsel and Secretary of GP Natural Resource Partners LLC. Mr. Hogan joined NRP in May 2003 from Vinson & Elkins L.L.P., where he practiced corporate and securities law from August 2000 through April 2003. Prior to joining Vinson & Elkins in August 2000, he practiced corporate and securities law at Andrews & Kurth L.L.P. from September 1997 through July 2000.
      Corbin J. Robertson III is Vice President — Acquisitions of GP Natural Resource Partners LLC. Mr. Robertson was elected as an officer in October 2003. In addition to his duties at NRP, Mr. Robertson also co-manages a private hedge fund he founded in 2002 and serves as Vice President — Business Development for Quintana Minerals Corporation, a privately held oil and gas company that he joined in 1999. Mr. Robertson also served from 1996 to 1998 as a Vice President of Sandefer Capital Partners LLC, a private investment partnership focused on energy-related investments, and from 1994 to 1996 as a management consultant for Deloitte and Touche LLP. Mr. Robertson is the son of Corbin J. Robertson, Jr., the Chief Executive Officer and Chairman of the Board.
      Kenneth Hudson is the Controller of GP Natural Resource Partners LLC. He has served as Controller of the general partner of Western Pocahontas Properties Limited Partnership and of New Gauley Coal Corporation since 1988 and of the general partner of Great Northern Properties Limited Partnership since 1992. He was also Controller of Blackhawk Mining Co., Quintana Coal Co. and other related operations from 1985 to 1988. Prior to that time, Mr. Hudson worked in public accounting.
      Robert T. Blakely joined the Board of Directors of GP Natural Resource Partners LLC in January 2003. He currently serves as Executive Vice President and Chief Financial Officer of MCI, Inc. From mid-2002 through mid-2003, he served as President of Performance Enhancement Group, which was formed to acquire manufacturers of high performance and racing components designed for automotive and marine-engine applications. He previously served as Executive Vice President and Chief Financial Officer of Lyondell Chemical from 1999 through 2002, Executive Vice President and Chief Financial Officer of Tenneco, Inc. from 1981 until 1999 as well as a Managing Director at Morgan Stanley. He served a four-year term on the Financial Accounting Standards Advisory Council and currently serves as a trustee of

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Cornell University, where he serves as Chairman of Cornell’s Finance Committee and a member of the Executive Committee of the Board. He has served on the Board of Directors and as Chairman of the Audit Committee of Westlake Chemical Corporation since August 2004.
      David M. Carmichael is a member of the Board of Directors of GP Natural Resource Partners LLC. He currently is a private investor. Mr. Carmichael is the former Vice Chairman of KN Energy and the former Chairman and Chief Executive Officer of American Oil and Gas Corporation, CARCON Corporation and WellTech, Inc. He has served on the Board of Directors of ENSCO International since 2001 and Tom Brown, Inc. from 1997 until 2004. He also currently serves as a trustee of the Texas Heart Institute.
      Robert B. Karn III is a member of the Board of Directors of GP Natural Resource Partners LLC. He currently is a consultant and serves on the Board of Directors of various entities. He was the partner in charge of the coal mining practice worldwide for Arthur Andersen from 1981 until his retirement in 1998. He retired as Managing Partner of the St. Louis office’s Financial and Economic Consulting Practice. Mr. Karn is a Certified Public Accountant, Certified Fraud Examiner and has served as president of numerous organizations. He also currently serves on the Board of Directors of Peabody Energy Company and the Board of Trustees of Fiduciary Claymore MLP Opportunity Fund.
      Alex T. Krueger is a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Krueger joined First Reserve Corporation in 1999 and is currently a Managing Director of First Reserve focused on investment efforts in the coal and energy infrastructure sectors. Mr. Krueger also serves on the board of Alpha Natural Resources, Inc. (a successor to Alpha Natural Resources LLC), a significant lessee of NRP, and Foundation Coal Holdings, Inc., also a lessee of NRP. Prior to joining First Reserve, Mr. Krueger worked in the Houston office of Donaldson, Lufkin & Jenrette in the Energy Group.
      S. Reed Morian is a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Morian has served as a member of the Board of Directors of the general partner of Western Pocahontas Properties Limited Partnership since 1986, New Gauley Coal Corporation since 1992 and the general partner of Great Northern Properties Limited Partnership since 1992. Mr. Morian has worked for Dixie Chemical Company since 1971 and has served as its Chairman and Chief Executive Officer since 1981. He has also served as Chairman, Chief Executive Officer and President of DX Holding Company since 1989.
      W. W. Scott, Jr. is a member of the Board of Directors of GP Natural Resource Partners LLC. Mr. Scott was Executive Vice President and Chief Financial Officer of Quintana Minerals Corporation from 1985 to 1999. He served as Executive Vice President and Chief Financial Officer of the general partner of Western Pocahontas Properties Limited Partnership and New Gauley Coal Corporation from 1986 to 1999. He served as Executive Vice President and Chief Financial Officer of the general partner of Great Northern Properties Limited Partnership from 1992 to 1999. Since 1999, he has continued to serve as a director of the general partner of Western Pocahontas Properties Limited Partnership and Quintana Minerals Corporation.
      Stephen P. Smith joined the Board of Directors of GP Natural Resource Partners LLC on March 5, 2004. Mr. Smith is the Senior Vice President and Treasurer of American Electric Power Company, Inc. From November 2000 to January 2003, Mr. Smith served as President and Chief Operating Officer — Corporate Services for NiSource Inc. Prior to joining NiSource, Mr. Smith served as Deputy Chief Financial Officer for Columbia Energy Group from November 1999 to November 2000 and Chief Financial Officer for Columbia Gas Transmission Corporation and Columbia Gulf Transmission Company from 1996 to 1999.
Independence of Directors
      The Board of Directors has determined that Messrs. Blakely, Carmichael, Karn and Smith are independent under the standards set forth in Section 303.01(B)(2)(a) and (3) of the New York Stock Exchange’s listing standards and under Item 7(d)(3)(iv) of Schedule 14A under the Securities Exchange Act of 1934. Because we are a limited partnership as defined in Section 303A of the New York Stock

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Exchange’s listing standards, we are not required to have a majority of independent directors. The Board has three committees staffed solely by independent directors.
Audit Committee:
       *Robert B. Karn, III – Chairman
       *Robert T. Blakely – Member
       *Stephen P. Smith – Member
          David M. Carmichael – Member
 
Determined to be Audit Committee Financial Experts pursuant to Item 401(h) of Regulation S-K.
Compensation, Nominating and Governance Committee:
    David M. Carmichael – Chairman
    Robert T. Blakely – Member
    Robert B. Karn, III – Member
Conflicts Committee:
    Robert T. Blakely – Chairman
    Robert B. Karn, III – Member
    David M. Carmichael – Member
Report of the Audit Committee
      Our Audit Committee is composed entirely of independent directors. The members of the Audit Committee meet the independence and experience requirements of the New York Stock Exchange. The Committee has adopted, and annually reviews, a charter outlining the practices it follows. The charter complies with all current regulatory requirements.
      During the year 2004, at each of its meetings, the Committee met with the senior members of our financial management team, our general counsel and our independent auditors. The Committee had private sessions at certain of its meetings with our independent auditors at which candid discussions of financial management, accounting and internal control issues took place.
      The Committee recommended to the Board of Directors the engagement of Ernst & Young LLP as our independent auditors for the year ended December 31, 2004 and reviewed with our financial managers and the independent auditors overall audit scopes and plans, the results of internal and external audit examinations, evaluations by the auditors of our internal controls and the quality of our financial reporting.
      Management has reviewed the audited financial statements in the Annual Report with the Audit Committee, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant accounting judgments and estimates, and the clarity of disclosures in the financial statements. In addressing the quality of management’s accounting judgments, members of the Audit Committee asked for management’s representations and reviewed certifications prepared by the Chief Executive Officer and Chief Financial Officer that our unaudited quarterly and audited consolidated financial statements fairly present, in all material respects, our financial condition and results of operations, and have expressed to both management and auditors their general preference for conservative policies when a range of accounting options is available.
      The Committee also discussed with the independent auditors other matters required to be discussed by the auditors with the Committee under Statement on Auditing Standards No. 61, as amended by Statement on Auditing Standards No. 90 (communications with audit committees). The Committee received and discussed with the auditors their annual written report on their independence from the partnership and its management, which is made under Rule 3600T of the Public Company Accounting Oversight Board, which has adopted on an interim basis Independence Standards Board Standard No. 1 (independence discussions with audit committees), and considered with the auditors whether the provision of non-audit services provided by them to the partnership during 2004 was compatible with the auditors’ independence.

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      In performing all of these functions, the Audit Committee acts only in an oversight capacity. The Committee reviews our quarterly and annual reporting on Form 10-Q and Form 10-K prior to filing with the Securities and Exchange Commission. In 2004, the Committee also reviewed quarterly earnings announcements with management and representatives of the independent auditor in advance of their issuance. In its oversight role, the Committee relies on the work and assurances of our management, which has the primary responsibility for financial statements and reports, and of the independent auditors, who, in their report, express an opinion on the conformity of our annual financial statements with generally accepted accounting principles.
      In reliance on these reviews and discussions, and the report of the independent auditors, the Audit Committee has recommended to the Board of Directors, and the Board has approved, that the audited financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2004, for filing with the Securities and Exchange Commission.
  Robert B. Karn, Chairman
  Robert T. Blakely
  Stephen P. Smith
  David M. Carmichael
Section 16(a) Beneficial Ownership Reporting Compliance
      Section 16(a) of the Securities and Exchange Act of 1934 requires directors, officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of their equity securities. These people are also required to furnish us with copies of all Section 16(a) forms that they file. Based solely upon a review of the copies of Forms 3, 4 and 5 furnished to us, or written representations from certain reporting persons that no Forms 5 were required, we believe that our officers and directors and persons who beneficially own more than ten percent of a registered class of our equity securities complied with all filing requirements with respect to transactions in our equity securities during 2004, except that Mr. Karn filed a late Form 4.
Code of Business Conduct and Ethics
      We have adopted a Code of Business Conduct and Ethics that applies to our management, including our Chief Executive Officer, Chief Financial Officer and Controller, and that complies with Item 406 of Regulation S-K. Our Code of Business Conduct and Ethics is available on the internet at www.nrplp.com.

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Item 11. Executive Compensation
      We have no executive officers, but we reimburse affiliates of the general partner for compensation paid to the general partners’ executive officers in connection with managing us. We and our general partner were formed in April 2002, but did not conduct any operations until the completion of the initial public offering of common units on October 17, 2002. The following table sets forth amounts reimbursed to affiliates of our general partner for compensation expense in 2002, 2003 and 2004.
Summary Compensation Table
                                         
                Other Annual   LTIP
Name and Principal Position   Year   Salary   Bonus   Compensation(1)   Payout
                     
Corbin J. Robertson, Jr., Chairman of the Board and CEO
    2004     $     $     $ 5,000     $ 145,213  
      2003                          
      2002                          
Nick Carter, President and Chief Operating Officer
    2004       242,500       180,000       37,866       72,613  
      2003       232,800       140,000       33,626        
      2002 (2)     45,124       40,000       8,570        
Dwight L. Dunlap, Chief Financial Officer and Treasurer
    2004       160,240       75,000       29,641       45,289  
      2003       148,500       50,000       24,998        
      2002 (2)     17,334       15,000       3,186        
Wyatt L. Hogan, Vice President and General Counsel
    2004       160,390       35,000       23,585       7,568  
      2003       94,273       25,000       7,765        
      2002 (3)                        —  
Kevin F. Wall, Vice President and Chief Engineer
    2004       118,750       60,000       25,649       33,304  
      2003       114,000       50,000       22,040        
      2002 (2)     20,325             4,783        
 
(1)  Includes portions of automobile allowance, 401(k) matching and retirement contributions allocated to Natural Resource Partners by Quintana Minerals Corporation and Western Pocahontas Properties Limited Partnership. Also includes cash compensation paid by the general partner to each named executive officer. The general partner may distribute to the executive officers up to 7.5% of any cash it receives with respect to its incentive distribution rights. We do not reimburse the general partner for any of these payments.
 
(2)  Represents allocations for the period from commencement of operations (October 17, 2002) through December 31, 2002.
 
(3)  Began working for the company in May 2003.
      Corbin J. Robertson Jr., Chairman of the Board and CEO, did not receive any salary, bonus or other compensation during 2004, 2003 or 2002 that was reimbursed by us to affiliates of the general partner, except for his LTIP payments and incentive distribution rights from the General Partner.
Compensation of Directors
      Each non-employee director receives an annual retainer of $20,000, payable quarterly, plus $1,000 for attending board and committee meetings. The Chairman of the Audit Committee receives $6,000 annually and the Chairmen of the Conflicts and Compensation, Nominating and Governance Committees receive $2,000 annually. In February 2004, each of the non-employee directors received a grant of 1,350 phantom units, which will vest in February 2008. On October 18, 2004, upon the vesting of a portion of their

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phantom units granted in 2003, Messrs. Carmichael, Karn, Scott, Morian, Smith and Krueger each received a cash payment of $59,073, representing the market value of their vested phantom units. On January 25, 2005, Mr. Blakely received a cash payment of $74,364 upon the vesting of a portion of his phantom units.
Long-Term Incentive Plan
      Prior to our initial public offering, GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan for employees and directors of GP Natural Resource Partners LLC and its affiliates who perform services for us. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.
      A phantom unit entitles the grantee to receive the fair market value in cash of a common unit upon the vesting of the phantom unit. The fair market value is determined by the average closing price of the common units over the 20 trading days prior to vesting. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as the compensation committee determines. The compensation committee will determine the period over which the phantom units granted to employees and directors will vest. In addition, the phantom units will vest upon a change in control of the partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s phantom units will be automatically forfeited unless and to the extent the compensation committee provides otherwise.
Long Term Incentive Plan — Awards in Last Fiscal Year
                 
    Number of    
Name   Phantom Units   Payout Date
         
Corbin J. Robertson, Jr. 
    8,840       2/11/2008  
Nick Carter
    4,420       2/11/2008  
Dwight L. Dunlap
    3,120       2/11/2008  
Wyatt L. Hogan
    2,600       2/11/2008  
Kevin F. Wall
    2,340       2/11/2008  
 
(1)  The number of units granted is not subject to minimum thresholds, targets or maximum payout conditions.
Annual Incentive Plan
      The general partner also adopted the Natural Resource Partners Annual Incentive Compensation Plan in October 2002. The annual incentive plan is designed to enhance the performance of GP Natural Resource Partners LLC and its affiliates’ key employees by rewarding them with cash awards for achieving annual financial and operational performance objectives. The compensation committee in its discretion may determine individual participants and payments, if any, for each fiscal year. The board of directors of GP Natural Resource Partners LLC may amend or change the annual incentive plan at any time. We reimburse GP Natural Resource Partners LLC for payments and costs incurred under the plan.

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Item 12. Security Ownership of Certain Beneficial Owners and Management
      The following table sets forth, as of February 28, 2005 the amount and percentage of our common and subordinated units beneficially held by (1) each person known to us to beneficially own 5% or more of the stock, (2) by each of the directors and executive officers and (3) by all directors and executive officers as a group. Unless otherwise noted, each of the named persons and members of the group has sole voting and investment power with respect to the units shown.
                                         
        Percentage of       Percentage of   Percentage
    Common   Common   Subordinated   Subordinated   of Total
Name of Beneficial Owner   Units   Units(1)   Units   Units(1)   Units
                     
Corbin J. Robertson, Jr.(2)(6)
    3,439,103       24.6 %     5,440,673       47.9 %     35.0 %
Western Pocahontas Properties Limited Partnership(3)(4)
    3,158,166       22.6 %     5,231,766       46.1 %     33.1 %
First Reserve GP IX Inc.(4)(5)
                4,796,920       42.3 %     18.9 %
FRC-WPP NRP Investment L.P.(4)(5)
                4,796,920       42.3 %     18.9 %
Great Northern Properties Partnership(4)
    373,715       2.7 %     1,116,065       9.8 %     5.9 %
Nick Carter(6)(8)
    5,398                          
Dwight L. Dunlap(6)(9)
    4,000                          
Kevin F. Wall(8)
    500                          
Kathy E. Hager(6)(9)
    4,377                          
Wyatt L. Hogan(6)(7)(9)
    500                          
Corbin J. Robertson III(6)(9)
    7,500                          
Kenneth Hudson(8)
    500                          
Robert T. Blakely(10)
                             
David M. Carmichael(11)
    5,000                          
Robert B. Karn III(12)
    2,500                          
Alex T. Krueger(4)
                             
S. Reed Morian(13)
    10,000                          
W. W. Scott, Jr.(14)
    5,310                          
Stephen P. Smith(15)
                             
Directors and Officers as a Group
    3,484,688       24.9 %     5,440,673       47.9 %     35.2 %
 
  * Less than one percent.
  (1)  Based upon 13,986,906 common units issued and outstanding on February 28, 2005 and 11,353,658 subordinated units issued and outstanding on February 28, 2005. Unless otherwise noted, beneficial ownership is less than 1% of our units and subordinated units.
 
  (2)  Mr. Robertson may be deemed to beneficially own the 3,158,166 common units and 5,231,766 subordinated units owned by Western Pocahontas Properties Limited Partnership, and 126,107 common units and 208,907 subordinated units owned by New Gauley Coal Corporation. Also included are 69,530 common units held by William K. Robertson 1992 Management Trust and 69,530 units held by Frances C. Robertson 1992 Management Trust, both of which Mr. Robertson is the trustee, and has voting control, but not direct ownership. Also included are 15,770 common units held by Barbara Robertson, Mr. Robertson’s spouse. Mr. Robertson’s address is 601 Jefferson Street, Suite 3600, Houston, Texas 77002.
 
  (3)  These units may be deemed to be beneficially owned by Mr. Robertson.
 
  (4)  The address of Western Pocahontas Properties Limited Partnership and Great Northern Properties Limited Partnership is 601 Jefferson Street, Suite 3600, Houston, Texas 77002. The address of Mr. Krueger and First Reserve GP IX Inc. and FRC-WPP NRP Investment L.P. is One Lafayette Place, Greenwich, CT 06830.

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  (5)  The subordinated units are directly owned by FRC-WPP NRP Investment L.P. (the “Unit Holder”). FRC-WPP GP LLC (the “Investment GP”) is the general partner of the Unit Holder. FRC-NRP A.V. Holdings, L.P. (“A.V.”) holds a majority of the limited partnership interests and member interests of the Unit Holder and the Investment GP, respectively. FRC-NRP, Inc. (“Blocker”) and First Reserve GP IX, L.P. (“GP IX”) are the general partners of A.V., and First Reserve Fund IX, L.P. (“Fund IX”) is the sole stockholder of Blocker. GP IX is the general partner of Fund IX, and First Reserve GP IX, Inc. (“First Reserve”) is the general partner of GP IX. Each of the Unit Holder, the Investment GP, A.V., Blocker, Fund IX and GP IX are controlled by First Reserve.
 
  (6)  These officers purchased interests in FRC-WPP Investment L.P., which owns an approximate 37% limited partnership interest in FRC-WPP NRP Investment L.P., which purchased 4,796,920 subordinated units from Ark Land Company on December 22, 2003. Mr. Carter’s interest was purchased by his wife, Mary Carolyn Carter.
 
  (7)  Of these common units, 250 common units are owned by the Anna Margaret Hogan 2002 Trust and 250 common units are owned by the Alice Elizabeth Hogan 2002 Trust. Mr. Hogan is a trustee of each of these trusts.
 
  (8)  The address of Messrs. Carter, Wall and Hudson is 1035 Third Avenue, Suite 300, Huntington, West Virginia 25727.
 
  (9)  The address of Messrs. Dunlap, Hogan, Corbin J. Robertson III and Ms. Hager is 601 Jefferson Street, Suite 3600, Houston, Texas 77002.
(10)  The address of Mr. Blakely is MCI, 22001 Loudoun County Parkway, Ashburn, Virginia 20147.
 
(11)  The address of Mr. Carmichael is 910 Travis Street, Suite 1930, Houston, Texas 77002.
 
(12)  The address of Mr. Karn is 3709 Ascot Bend Court, Bonita Springs, Florida 34134.
 
(13)  The address of Mr. Morian is DX Service Co., Inc., 300 Jackson Hill, Houston, Texas 77007.
 
(14)  The address of Mr. Scott is 2606 West Lane Drive, Houston, Texas 77027.
 
(15)  The address of Mr. Smith is American Electric Power, 1 Riverside Plaza, 28th Floor, Columbus, Ohio, 43215.
Item 13. Certain Relationships and Related Transactions
Distributions and Payments to the General Partner and its Affiliates
      The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing operation and any liquidation of Natural Resource Partners. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Distributions of available cash to our general partner and its affiliates We will generally make cash distributions 98% to the unitholders, including affiliates of our general partner, as holders of all of the subordinated units, and 2% to the general partner. In addition, if distributions exceed the target distribution levels, the holders of the incentive distribution rights, including our general partner, will be entitled to increasing percentages of the distributions, up to an aggregate of 48% of the distributions above the highest target level.
 
Assuming we have sufficient available cash to pay the current quarterly distribution of $0.6625 on all of our outstanding units for four quarters, our general partner would receive distributions of approximately $1.4 million on its 2% general partner interest and our affiliates would receive distributions of approximately

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$9.7 million on their common units and $30.1 million on their subordinated units. In addition, our general partner and affiliates of our general partner would receive an aggregate of approximately $1.6 million with respect to their incentive distribution rights.
 
Other payments to our general partner and its affiliates Our general partner and its affiliates will not receive any management fee or other compensation for the management of our partnership. Our general partner and its affiliates will be reimbursed, however, for all direct and indirect expenses incurred on our behalf. Our general partner has the sole discretion in determining the amount of these expenses.
 
Withdrawal or removal of our general partner If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
 
Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
Omnibus Agreement
Non-competition Provisions
      As part of the omnibus agreement entered into concurrently with the closing of our initial public offering, the WPP Group and any entity controlled by Corbin J. Robertson, Jr., which we refer to in this section as the GP affiliates, each agreed that neither they nor their affiliates will, directly or indirectly, engage or invest in entities that engage in the following activities (each, a “restricted business”) in the specific circumstances described below:
  •  the entering into or holding of leases with a party other than an affiliate of the GP affiliate for any GP affiliate-owned fee coal reserves within the United States; and
 
  •  the entering into or holding of subleases with a party other than an affiliate of the GP affiliate for coal reserves within the United States controlled by a paid-up lease owned by any GP affiliate or its affiliate.
      “Affiliate” means, with respect to any GP affiliate or, any other entity in which such GP affiliate owns, through one or more intermediaries, 50% or more of the then outstanding voting securities or other ownership interests of such entity. Except as described below, the WPP Group and their respective controlled affiliates will not be prohibited from engaging in activities in which they compete directly with us.
      A GP affiliate may, directly or indirectly, engage in a restricted business if:
  •  the GP affiliate was engaged in the restricted business at the closing of the offering; provided that if the fair market value of the asset or group of related assets of the restricted business subsequently exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.
 
  •  the asset or group of related assets of the restricted business have a fair market value of $10 million or less; provided that if the fair market value of the assets of the restricted business subsequently

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  exceeds $10 million, the GP affiliate must offer the restricted business to us under the offer procedures described below.
 
  •  the asset or group of related assets of the restricted business have a fair market value of more than $10 million and the general partner (with the approval of the conflicts committee) has elected not to cause us to purchase these assets under the procedures described below.
 
  •  its ownership in the restricted business consists solely of a noncontrolling equity interest.
      For purposes of this paragraph, “fair market value” means the fair market value as determined in good faith by the relevant GP affiliate.
      The total fair market value in the good faith opinion of the WPP Group of all restricted businesses engaged in by the WPP Group, other than those engaged in by the WPP Group at closing of our initial public offering, may not exceed $75 million. For purposes of this restriction, the fair market value of any entity engaging in a restricted business purchased by the WPP Group will be determined based on the fair market value of the entity as a whole, without regard for any lesser ownership interest to be acquired.
      If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a fair market value in excess of $10 million and the restricted business constitutes greater than 50% of the value of the business to be acquired, then the WPP Group must first offer us the opportunity to purchase the restricted business. If the WPP Group desires to acquire a restricted business or an entity that engages in a restricted business with a value in excess of $10 million and the restricted business constitutes 50% or less of the value of the business to be acquired, then the GP affiliate may purchase the restricted business first and then offer us the opportunity to purchase the restricted business within six months of acquisition. For purposes of this paragraph, “restricted business” excludes a general partner interest or managing member interest, which is addressed in a separate restriction summarized below. For purposes of this paragraph only, “fair market value” means the fair market value as determined in good faith by the relevant GP affiliate.
      If we want to purchase the restricted business and the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP affiliate and the general partner, with the approval of the conflicts committee, are unable to agree in good faith on the fair market value and other terms of the offer within 60 days after the general partner receives the offer, then the GP affiliate may sell the restricted business to a third party within two years for no less than the purchase price and on terms no less favorable to the GP affiliate than last offered by us. During this two-year period, the GP affiliate may operate the restricted business in competition with us, subject to the restriction on total fair market value of restricted businesses owned in the case of the WPP Group.
      If, at the end of the two year period, the restricted business has not been sold to a third party and the restricted business retains a value, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, then the GP affiliate must reoffer the restricted business to the general partner. If the GP affiliate and the general partner, with the approval of the conflicts committee, agree on the fair market value and other terms of the offer within 60 days after the general partner receives the second offer from the GP affiliate, we will purchase the restricted business as soon as commercially practicable. If the GP Affiliate and the general partner, with the concurrence of the conflicts committee, again fail to agree after negotiation in good faith on the fair market value of the restricted business, then the GP affiliate will be under no further obligation to us with respect to the restricted business, subject to the restriction on total fair market value of restricted businesses owned.
      In addition, if during the two-year period described above, a change occurs in the restricted business that, in the good faith opinion of the GP affiliate, affects the fair market value of the restricted business by more than 10 percent and the fair market value of the restricted business remains, in the good faith opinion of the relevant GP affiliate, in excess of $10 million, the GP affiliate will be obligated to reoffer

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the restricted business to the general partner at the new fair market value, and the offer procedures described above will recommence.
      If the restricted business to be acquired is in the form of a general partner interest in a publicly held partnership or a managing member interest in a publicly held limited liability company, the WPP Group may not acquire such restricted business even if we decline to purchase the restricted business. If the restricted business to be acquired is in the form of a general partner interest in a non-publicly held partnership or a managing member of a non-publicly held limited liability company, the WPP Group may acquire such restricted business subject to the restriction on total fair market value of restricted businesses owned and the offer procedures described above.
Indemnification
      Under the omnibus agreement, the WPP Group and Arch Coal, jointly and severally, will indemnify us for (1) three years after the closing of the initial public offering against environmental liabilities associated with the properties contributed to us and occurring before the closing date of the initial public offering and (2) all tax liabilities attributable to the ownership or operation of the partnership assets prior to the closing of the initial public offering. The environmental indemnity will be limited to a maximum amount of $10.0 million. Liabilities resulting from a change in law after the closing of the offering are excluded from the environmental indemnity.
      The omnibus agreement may be amended at any time by the general partner, with the concurrence of the conflicts committee. The respective obligations of the WPP Group under the omnibus agreement terminate when the WPP Group and its affiliates cease to participate in the control of the general partner.
Conflicts of Interest
      Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the WPP Group and First Reserve Corporation and its affiliates) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of GP Natural Resource Partners LLC have fiduciary duties to manage GP Natural Resource Partners LLC and our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.
      Whenever a conflict arises between our general partner or its affiliates, on the one hand, and our partnership or any other partner, on the other, our general partner will resolve that conflict. Our general partner may, but is not required to, seek the approval of the conflicts committee of the board of directors of our general partner of such resolution. The partnership agreement contains provisions that allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. In effect, these provisions limit our general partner’s fiduciary duties to our unitholders. Delaware case law has not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties. The partnership agreement also restricts the remedies available to unitholders for actions taken by our general partner that might, without those limitations, constitute breaches of fiduciary duty.
      Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is considered to be fair and reasonable to us. Any resolution is considered to be fair and reasonable to us if that resolution is:
  •  approved by the conflicts committee, although our general partner is not obligated to seek such approval and our general partner may adopt a resolution or course of action that has not received approval;
 
  •  on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

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  •  fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
      In resolving a conflict, our general partner, including its conflicts committee, may, unless the resolution is specifically provided for in the partnership agreement, consider:
  •  the relative interests of any party to such conflict and the benefits and burdens relating to such interest;
 
  •  any customary or accepted industry practices or historical dealings with a particular person or entity;
 
  •  generally accepted accounting practices or principles; and
 
  •  such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.
      Conflicts of interest could arise in the situations described below, among others.
Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.
      The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:
  •  amount and timing of asset purchases and sales;
 
  •  cash expenditures;
 
  •  borrowings;
 
  •  the issuance of additional units; and
 
  •  the creation, reduction or increase of reserves in any quarter.
      In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to the unitholders, including borrowings that have the purpose or effect of:
  •  enabling our general partner to receive distributions on any subordinated units held by our general partner or the incentive distribution rights; or
 
  •  hastening the expiration of the subordination period.
      For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and subordinated units, our partnership agreement permits us to borrow funds which may enable us to make this distribution on all outstanding units.
      The partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us or our subsidiaries.
We do not have any officers or employees and rely solely on officers and employees of GP Natural Resource Partners LLC and its affiliates.
      We do not have any officers or employees and rely solely on officers and employees of GP Natural Resource Partners LLC, its affiliates and the employees of our subsidiaries. Affiliates of GP Natural Resource Partners LLC conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner. The officers of GP Natural Resource Partners LLC are not required to work full time on our affairs. These officers devote significant time to the affairs of the WPP Group or its affiliates and are compensated by these affiliates for the services rendered to them.

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We reimburse our general partner and its affiliates for expenses.
      We reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.
Our general partner intends to limit its liability regarding our obligations.
      Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.
Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.
      Any agreements between us on the one hand, and our general partner and its affiliates, on the other, do not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not the result of arm’s-length negotiations.
      The partnership agreement allows our general partner to pay itself or its affiliates for any services rendered to us, provided these services are rendered on terms that are fair and reasonable. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are the result of arm’s-length negotiations.
      All of these transactions entered into after our initial public offering are on terms that are fair and reasonable to us.
      Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.
We may not choose to retain separate counsel for ourselves or for the holders of common units.
      The attorneys, independent auditors and others who have performed services for us in the past were retained by our general partner, its affiliates and us and have continued to be retained by our general partner, its affiliates and us. Attorneys, independent auditors and others who perform services for us are selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases. Delaware case law has not definitively established the limits on the ability of a partnership agreement to restrict such fiduciary duties.
Our general partner’s affiliates may compete with us.
      The partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in our partnership agreement and in the omnibus agreement, affiliates of our general partner will not be

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prohibited from engaging in activities in which they compete directly with us. Please read “Omnibus Agreement.”
Miscellaneous
      Corbin J. Robertson III, the son of our managing general partner’s Chief Executive Officer, Corbin J. Robertson, Jr., is Vice President — Acquisitions for GP Natural Resource Partners LLC and is an employee of Quintana Minerals Corporation. Mr. Robertson was elected as an officer of the partnership in October 2003. During 2004, Quintana Minerals Corporation was reimbursed in the amount of $76,464 for services performed by Corbin J. Robertson III. In each of 2004 and 2003, he also received bonus payments of $10,000 and $5,000 respectively. During 2004 he was also awarded 1,300 phantom units under the LTIP plan and received $14,967 in payments upon vesting of a portion of his LTIP units that were granted in 2003.
Item 14. Principal Accountant Fees and Services
      The Audit Committee of the Board of Directors of GP Natural Resource Partners LLC recommended and we engaged Ernst & Young LLP to audit our accounts and assist with tax work for fiscal 2004 and 2003. Fees (including out-of-pocket costs) incurred from Ernst & Young LLP for services for fiscal years 2004 and 2003 totaled $0.6 million and $0.3 million, respectively. All of our audit, audit-related fees and tax services have been approved by the Audit Committee of our Board of Directors. The following table presents fees for professional services rendered by Ernst &Young LLP:
                 
    2004   2003
         
Audit Fees(1)
  $ 454,811     $ 194,108  
Audit-Related Fees(2)
           
Tax Fees(3)
    244,694       108,241  
All Other Fees
           
 
(1)  Audit fees include fees associated with the annual audit of our consolidated financial statements and reviews of our quarterly reports on Form 10-Q. Audit fees also include fees associated with reviews of registration statements and costs associated for compliance with the Sarbanes-Oxley Act of 2002.
 
(2)  There were no audit-related fees.
 
(3)  Tax fees include fees principally incurred for assistance with tax planning, compliance, tax return preparation and filing of Schedules K-1.
Audit and Non-Audit Services Pre-Approval Policy
I. Statement of Principles
      Under the Sarbanes-Oxley Act of 2002 (the “Act”), the Audit Committee of the Board of Directors is responsible for the appointment, compensation and oversight of the work of the independent auditor. As part of this responsibility, the Audit Committee is required to pre-approve the audit and non-audit services performed by the independent auditor in order to assure that they do not impair the auditor’s independence from the Partnership. To implement these provisions of the Act, the Securities and Exchange Commission (the “SEC”) has issued rules specifying the types of services that an independent auditor may not provide to its audit client, as well as the audit committee’s administration of the engagement of the independent auditor. Accordingly, the Audit Committee has adopted, and the Board of Directors has ratified, this Audit and Non-Audit Services Pre-Approval Policy (the “Policy”), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent auditor may be pre-approved.
      The SEC’s rules establish two different approaches to pre-approving services, which the SEC considers to be equally valid. Proposed services may either be pre-approved without consideration of specific case-by-case services by the Audit Committee (“general pre-approval”) or require the specific

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pre-approval of the Audit Committee (“specific pre-approval”). The Audit Committee believes that the combination of these two approaches in this Policy will result in an effective and efficient procedure to pre-approve services performed by the independent auditor. As set forth in this Policy, unless a type of service has received general pre-approval, it will require specific pre-approval by the Audit Committee if it is to be provided by the independent auditor. Any proposed services exceeding pre-approved cost levels or budgeted amounts will also require specific pre-approval by the Audit Committee.
      For both types of pre-approval, the Audit Committee will consider whether such services are consistent with the SEC’s rules on auditor independence. The Audit Committee will also consider whether the independent auditor is best positioned to provide the most effective and efficient service for reasons such as its familiarity with our business, employees, culture, accounting systems, risk profile and other factors, and whether the service might enhance the Partnership’s ability to manage or control risk or improve audit quality. All such factors will be considered as a whole, and no one factor will necessarily be determinative.
      The Audit Committee is also mindful of the relationship between fees for audit and non-audit services in deciding whether to pre-approve any such services and may determine, for each fiscal year, the appropriate ratio between the total amount of fees for audit, audit-related and tax services.
      The appendices to this Policy describe the audit, audit-related and tax services that have the general pre-approval of the Audit Committee. The term of any general pre-approval is 12 months from the date of pre-approval, unless the Audit Committee considers a different period and states otherwise. The Audit Committee will annually review and pre-approve the services that may be provided by the independent auditor without obtaining specific pre-approval from the Audit Committee. The Audit Committee will add or subtract to the list of general pre-approved services from time to time, based on subsequent determinations.
      The purpose of this Policy is to set forth the procedures by which the Audit Committee intends to fulfill its responsibilities. It does not delegate the Audit Committee’s responsibilities to pre-approve services performed by the independent auditor to management.
      Ernst & Young LLP, our independent auditor has reviewed this Policy and believes that implementation of the policy will not adversely affect its independence.
II. Delegation
      As provided in the Act and the SEC’s rules, the Audit Committee has delegated either type of pre-approval authority to Robert B. Karn III, the Chairman of the Audit Committee. Mr. Karn must report, for informational purposes only, any pre-approval decisions to the Audit Committee at its next scheduled meeting.
III. Audit Services
      The annual Audit services engagement terms and fees will be subject to the specific pre-approval of the Audit Committee. Audit services include the annual financial statement audit (including required quarterly reviews), subsidiary audits, equity investment audits and other procedures required to be performed by the independent auditor to be able to form an opinion on the Partnership’s consolidated financial statements. These other procedures include information systems and procedural reviews and testing performed in order to understand and place reliance on the systems of internal control, and consultations relating to the audit or quarterly review. Audit services also include the attestation engagement for the independent auditor’s report on management’s report on internal controls for financial reporting. The Audit Committee monitors the audit services engagement as necessary, but not less than on a quarterly basis, and approves, if necessary, any changes in terms, conditions and fees resulting from changes in audit scope, partnership structure or other items.
      In addition to the annual audit services engagement approved by the Audit Committee, the Audit Committee may grant general pre-approval to other audit services, which are those services that only the

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independent auditor reasonably can provide. Other audit services may include statutory audits or financial audits for our subsidiaries or our affiliates and services associated with SEC registration statements, periodic reports and other documents filed with the SEC or other documents issued in connection with securities offerings.
IV. Audit-related Services
      Audit-related services are assurance and related services that are reasonably related to the performance of the audit or review of the Partnership’s financial statements or that are traditionally performed by the independent auditor. Because the Audit Committee believes that the provision of audit-related services does not impair the independence of the auditor and is consistent with the SEC’s rules on auditor independence, the Audit Committee may grant general pre-approval to audit-related services. Audit-related services include, among others, due diligence services pertaining to potential business acquisitions/dispositions; accounting consultations related to accounting, financial reporting or disclosure matters not classified as “Audit services” assistance with understanding and implementing new accounting and financial reporting guidance from rulemaking authorities; financial audits of employee benefit plans; agreed-upon or expanded audit procedures related to accounting and/or billing records required to respond to or comply with financial, accounting or regulatory reporting matters; and assistance with internal control reporting requirements.
V. Tax Services
      The Audit Committee believes that the independent auditor can provide tax services to the Partnership such as tax compliance, tax planning and tax advice without impairing the auditor’s independence, and the SEC has stated that the independent auditor may provide such services. Hence, the Audit Committee believes it may grant general pre-approval to those tax services that have historically been provided by the auditor, that the Audit Committee has reviewed and believes would not impair the independence of the auditor and that are consistent with the SEC’s rules on auditor independence. The Audit Committee will not permit the retention of the independent auditor in connection with a transaction initially recommended by the independent auditor, the sole business purpose of which may be tax avoidance and the tax treatment of which may not be supported in the Internal Revenue Code and related regulations. The Audit Committee will consult with the Chief Financial Officer or outside counsel to determine that the tax planning and reporting positions are consistent with this policy.
VI. Pre-Approval Fee Levels or Budgeted Amounts
      Pre-approval fee levels or budgeted amounts for all services to be provided by the independent auditor will be established annually by the Audit Committee. Any proposed services exceeding these levels or amounts will require specific pre-approval by the Audit Committee. The Audit Committee is mindful of the overall relationship of fees for audit and non-audit services in determining whether to pre-approve any such services. For each fiscal year, the Audit Committee may determine the appropriate ratio between the total amount of fees for audit, audit-related and tax services.
VII. Procedures
      All requests or applications for services to be provided by the independent auditor that do not require specific approval by the Audit Committee will be submitted to the Chief Financial Officer and must include a detailed description of the services to be rendered. The Chief Financial Officer will determine whether such services are included within the list of services that have received the general pre-approval of the Audit Committee. The Audit Committee will be informed on a timely basis of any such services rendered by the independent auditor.

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

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PART IV
Item 15. Exhibits and Financial Statement Schedules
          (a)(1) and (2) Financial Statements and Schedules
      Please See Item 8, “Financial Statements and Supplementary Data”
          (a)(3) Exhibits
             
Exhibit        
Number       Description
         
  3.1       Second Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of December 22, 2003 (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532).
  3.2       Third Amended and Restated Limited Liability Company Agreement of GP Natural Resource Partners LLC, dated as of December 22, 2003 (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532).
  4.1       First Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of October 17, 2002 (incorporated by reference to Exhibit 3.2 of the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  4.2       Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of December 8, 2003 (incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532).
  4.3       Amended and Restated Limited Liability Company Agreement of NRP (Operating) LLC, dated as of October 17, 2002 (incorporated by reference to Exhibit 3.4 of the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  4.4       Form of Indenture of Natural Resource Partners L.P. (incorporated by reference to Exhibit 4.4 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532).
  4.5       Form of Indenture of NRP (Operating) LLC (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532).
  4.6       Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the Purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed June 23, 2003).
  4.7       Subsidiary Guarantee of Senior Notes of NRP (Operating) LLC, dated June 19, 2003 (incorporated by reference to Exhibit 4.5 to the Current Report on Form 8-K filed June 23, 2003).
  4.8       Form of Series A Note (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed June 23, 2003).
  4.9       Form of Series B Note (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed June 23, 2003).
  4.10       Form of Series C Note (incorporated by reference to Exhibit 4.4 to the Current Report on Form 8-K filed June 23, 2003).
  4.11       Investor Rights Agreement, dated as of December 22, 2003, among FRC-WPP NRP Investment L.P., Natural Resource Partners L.P., NRP (GP) LP and GP Natural Resource Partners LLC (incorporated by reference to Exhibit 4.13 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532).
  10.1       Credit Agreement, dated as of October 29, 2004, by and among NRP (Operating) LLC, as Borrower, Citibank, N.A., as Administrative Agent, the Banks and WBRD LLC and ACIN LLC, as Guarantors (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the period ended September 30, 2004, File No. 001-31465).

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Exhibit        
Number       Description
         
  10.2       Contribution, Conveyance and Assumption Agreement by and among Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, Ark Land Company, WPP LLC, GNP LLC, NNG LLC, ACIN LLC, Robertson Coal Management LLC, NRP (Operating) LLC, GP Natural Resource Partners LLC, NRP (GP) LP and Natural Resource Partners L.P., dated as of October 17, 2002 (incorporated by reference to Exhibit 10.2 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  10.3       Natural Resource Partners Long-Term Incentive Plan, as amended and restated (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-31465).
  10.4       First Amendment to the Natural Resource Partners Long-Term Incentive Plan dated December 8, 2003 (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-31465).
  10.5       Second Amendment to the Natural Resource Partners Long-Term Incentive Plan (incorporated by reference to the Current Report on Form 8-K, filed on December 13, 2004).
  10.6       Form of Phantom Unit Agreement (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the period ended September 30, 2004, File No. 001-31465).
  10.7       Natural Resource Partners Annual Incentive Plan (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465)
  10.8       Omnibus Agreement dated October 17, 2002, by and among Arch Coal, Inc., Ark Land Company, Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  10.9       Royalty Pass-Through Agreement and Guaranty dated as of October 17, 2002 among Arch Coal, Inc., Ark Land Company and ACIN LLC (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  10.10       Form of Coal Mining Lease between Ark Land Company and ACIN LLC (incorporated by reference to Exhibit 10.6 of the Registration Statement on Form S-1 filed September 9, 2002, File No. 333-86582)
  10.11       Lease Amendment No. 1 to Coal Mining Lease dated November 20, 2002 between ACIN LLC and Ark Land Company (incorporated by reference to Exhibit 10.10 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  10.12       Purchase and Sale Agreement dated November 6, 2002, by and among El Paso CGP Company, Coastal Coal Company, LLC, Coastal Coal — West Virginia LLC, ANR Western Coal Development Company and CSTL LLC (incorporated by reference to Exhibit 10.8 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465)
  10.13       First Amendment to Purchase and Sale Agreement dated December 4, 2002 (incorporated by reference to Exhibit 10.9 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  10.14       Purchase and Sale Agreement, dated April 9, 2003, between Alpha Land and Reserves, LLC and CSTL LLC (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the period ended June 30, 2003, File No. 001-31465).
  10.15       Purchase and Sale Agreement, dated June 30, 2003, by and among PinnOak Resources, LLC, Pinnacle Land Company, LLC, Oak Grove Land Company, LLC and WPP LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed July 14, 2003).
  10.16       Purchase and Sale Agreement by and between BLC Properties LLC and WPP LLC, dated December 22, 2003 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed January 5, 2004, File No. 001-31465).

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Exhibit        
Number       Description
         
  10.17       Form of Coal Mining Lease between Alpha Natural Resources, LLC and WPP LLC (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-31465).
  10.18*       Summary of director and executive officer compensation.
  21.1*       List of subsidiaries of Natural Resource Partners L.P.
  23.1*       Consent of Ernst & Young LLP
  23.2*       Consent of Ernst & Young LLP
  31.1*       Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.
  31.2*       Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.
  32.1**       Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.
  32.2**       Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.
  99.1*       Audited balance sheet of NRP (GP) LP
 
* Filed herewith
**  Furnished herewith

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SIGNATURES
      Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.
  Natural Resource Partners L.P.
  By: NRP (GP) LP, its general partner
  By:  GP NATURAL RESOURCE PARTNERS LLC,
its general partner
Date: February 28, 2005
  By:  /s/ Corbin J. Robertson, Jr.,
 
 
  Corbin J. Robertson, Jr.,
  Chairman of the Board and Chief Executive
  Officer (Principal Executive Officer)
Date: February 28, 2005
  By:  /s/ Dwight L. Dunlap
 
 
  Dwight L. Dunlap
  Chief Financial Officer and Treasurer
  (Principal Financial Officer)
Date: February 28, 2005
  By:  /s/ Kenneth Hudson
 
 
  Kenneth Hudson
  Controller (Principal Accounting Officer)
Date: February 28, 2005
  By:  /s/ Robert T. Blakely
 
 
  Robert T. Blakely
  Director
Date: February 28, 2005
  By:  /s/ David M. Carmichael
 
 
  David M. Carmichael
  Director
Date: February 28, 2005
  By:  /s/ Robert B. Karn III
 
 
  Robert B. Karn III
  Director
Date: February 28, 2005
  By:  /s/ Alex T. Krueger
 
 
  Alex T. Krueger
  Director

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Date: February 28, 2005
  By:  /s/ S. Reed Morian
 
 
  S. Reed Morian
  Director
Date: February 28, 2005
  By:  /s/ W.W. Scott, Jr.
 
 
  W.W. Scott, Jr.
  Director
Date: February 28, 2005
  By:  /s/ Stephen P. Smith
 
 
  Stephen P. Smith
  Director

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INDEX TO EXHIBITS
             
Exhibit        
Number       Description
         
  3.1       Second Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of December 22, 2003 (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532).
  3.2       Third Amended and Restated Limited Liability Company Agreement of GP Natural Resource Partners LLC, dated as of December 22, 2003 (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532).
  4.1       First Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of October 17, 2002 (incorporated by reference to Exhibit 3.2 of the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  4.2       Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of December 8, 2003 (incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532).
  4.3       Amended and Restated Limited Liability Company Agreement of NRP (Operating) LLC, dated as of October 17, 2002 (incorporated by reference to Exhibit 3.4 of the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  4.4       Form of Indenture of Natural Resource Partners L.P. (incorporated by reference to Exhibit 4.4 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532).
  4.5       Form of Indenture of NRP (Operating) LLC (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532).
  4.6       Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the Purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed June 23, 2003).
  4.7       Subsidiary Guarantee of Senior Notes of NRP (Operating) LLC, dated June 19, 2003 (incorporated by reference to Exhibit 4.5 to the Current Report on Form 8-K filed June 23, 2003).
  4.8       Form of Series A Note (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed June 23, 2003).
  4.9       Form of Series B Note (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed June 23, 2003).
  4.10       Form of Series C Note (incorporated by reference to Exhibit 4.4 to the Current Report on Form 8-K filed June 23, 2003).
  4.11       Investor Rights Agreement, dated as of December 22, 2003, among FRC-WPP NRP Investment L.P., Natural Resource Partners L.P., NRP (GP) LP and GP Natural Resource Partners LLC (incorporated by reference to Exhibit 4.13 to the Registration Statement on Form S-3, dated December 23, 2003, File No. 333-111532).
  10.1       Credit Agreement, dated as of October 29, 2004, by and among NRP (Operating) LLC, as Borrower, Citibank, N.A., as Administrative Agent, the Banks and WBRD LLC and ACIN LLC, as Guarantors (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the period ended September 30, 2004, File No. 001-31465).
  10.2       Contribution, Conveyance and Assumption Agreement by and among Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, Ark Land Company, WPP LLC, GNP LLC, NNG LLC, ACIN LLC, Robertson Coal Management LLC, NRP (Operating) LLC, GP Natural Resource Partners LLC, NRP (GP) LP and Natural Resource Partners L.P., dated as of October 17, 2002 (incorporated by reference to Exhibit 10.2 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  10.3       Natural Resource Partners Long-Term Incentive Plan, as amended and restated (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-31465).
  10.4       First Amendment to the Natural Resource Partners Long-Term Incentive Plan dated December 8, 2003 (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-31465).


Table of Contents

             
Exhibit        
Number       Description
         
  10.5       Second Amendment to the Natural Resource Partners Long-Term Incentive Plan (incorporated by reference to the Current Report on Form 8-K, filed on December 13, 2004).
  10.6       Form of Phantom Unit Agreement (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the period ended September 30, 2004, File No. 001-31465).
  10.7       Natural Resource Partners Annual Incentive Plan (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465)
  10.8       Omnibus Agreement dated October 17, 2002, by and among Arch Coal, Inc., Ark Land Company, Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  10.9       Royalty Pass-Through Agreement and Guaranty dated as of October 17, 2002 among Arch Coal, Inc., Ark Land Company and ACIN LLC (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  10.10       Form of Coal Mining Lease between Ark Land Company and ACIN LLC (incorporated by reference to Exhibit 10.6 of the Registration Statement on Form S-1 filed September 9, 2002, File No. 333-86582)
  10.11       Lease Amendment No. 1 to Coal Mining Lease dated November 20, 2002 between ACIN LLC and Ark Land Company (incorporated by reference to Exhibit 10.10 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  10.12       Purchase and Sale Agreement dated November 6, 2002, by and among El Paso CGP Company, Coastal Coal Company, LLC, Coastal Coal — West Virginia LLC, ANR Western Coal Development Company and CSTL LLC (incorporated by reference to Exhibit 10.8 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465)
  10.13       First Amendment to Purchase and Sale Agreement dated December 4, 2002 (incorporated by reference to Exhibit 10.9 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-31465).
  10.14       Purchase and Sale Agreement, dated April 9, 2003, between Alpha Land and Reserves, LLC and CSTL LLC (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the period ended June 30, 2003, File No. 001-31465).
  10.15       Purchase and Sale Agreement, dated June 30, 2003, by and among PinnOak Resources, LLC, Pinnacle Land Company, LLC, Oak Grove Land Company, LLC and WPP LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed July 14, 2003).
  10.16       Purchase and Sale Agreement by and between BLC Properties LLC and WPP LLC, dated December 22, 2003 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed January 5, 2004, File No. 001-31465).
  10.17       Form of Coal Mining Lease between Alpha Natural Resources, LLC and WPP LLC (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-31465).
  10.18*       Summary of director and executive officer compensation.
  21.1*       List of subsidiaries of Natural Resource Partners L.P.
  23.1*       Consent of Ernst & Young LLP
  23.2*       Consent of Ernst & Young LLP
  31.1*       Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.
  31.2*       Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.
  32.1**       Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.


Table of Contents

             
Exhibit        
Number       Description
         
  32.2**       Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.
  99.1*       Audited balance sheet of NRP (GP) LP
 
* Filed herewith
**  Furnished herewith