e424b3
Table of Contents

The information in this preliminary prospectus supplement is not complete and may be changed. This preliminary prospectus supplement and the accompanying prospectus are not an offer to sell these securities, and we are not soliciting an offer to buy these securities, in any state where the offer or sale is not permitted.
Filed pursuant to Rule 424(B)(3)
Registration No. 333-126186
Subject to Completion, dated August 4, 2005
Prospectus Supplement
(To Prospectus dated August 2, 2005)
(Natural Resource Partners LP Logo)
Natural Resource Partners L.P.
4,200,000 Subordinated Units
Representing Limited Partner Interests
 
The selling unitholder named in this prospectus supplement is offering to sell 4,200,000 subordinated units with this prospectus supplement and the accompanying prospectus.
Natural Resource Partners L.P. will not receive any of the proceeds from this offering.
This is the initial public offering of our subordinated units. Prior to this offering, there has been no public market for our subordinated units. We expect the initial public offering price of the subordinated units to be at a discount of approximately 2% to 4% to the closing price of our common units on the date we determine the offering price of our subordinated units. The closing price of our common units, which trade on the NYSE under the symbol “NRP,” was $68.19 on August 3, 2005. The subordinated units have been approved for listing on the New York Stock Exchange under the symbol “NSP.”
Investing in our subordinated units involves risks. See “Risk Factors” beginning on page S-12 of this prospectus supplement and page 2 of the accompanying prospectus.
         
    Per Subordinated Unit   Total
         
Public offering price
  $   $
Underwriting discount
  $   $
Proceeds to the selling unitholder, before expenses
  $   $
The selling unitholder has granted the underwriters a 30-day option to purchase up to 596,920 additional subordinated units.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
Lehman Brothers, on behalf of the underwriters, expects to deliver the subordinated units on or about August      , 2005.
 
Joint Book-Running Managers
Lehman Brothers Citigroup
 
A.G. Edwards
  UBS Investment Bank
  Wachovia Securities
  Friedman Billings Ramsey
  Sanders Morris Harris
                    , 2005


      This document is in two parts. The first part is this prospectus supplement, which describes the terms of this offering of subordinated units. The second part is the accompanying prospectus, which gives more general information, some of which may not apply to the subordinated units. If the description of this subordinated unit offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement.
      You should rely only on the information contained or incorporated by reference in this prospectus supplement or the accompanying prospectus. We have not authorized anyone to provide you with additional or different information. These securities are not being offered in any state where the offer is not permitted. You should not assume that the information contained in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the date on the front cover of each document or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since those dates.
TABLE OF CONTENTS
Prospectus Supplement
         
    S-1  
    S-12  
    S-14  
    S-14  
    S-15  
    S-16  
    S-26  
    S-30  
    S-33  
    S-34  
    S-35  
    S-39  
    S-39  
    S-39  
    S-41  
Prospectus dated August 2, 2005
         
About This Prospectus
    1  
About Natural Resource Partners
    1  
Risk Factors
    2  
Use of Proceeds
    18  
Description of Our Units
    18  
Cash Distributions
    25  
Material Tax Consequences
    33  
Investment in US by Employee Benefit Plans
    48  
Selling Unitholder
    49  
Plan of Distribution
    50  
Where You Can Find More Information
    50  
Forward-Looking Statements
    52  
Legal Matters
    52  
Experts
    52  

i


Table of Contents

SUMMARY
      This summary highlights information contained elsewhere in this prospectus supplement and the accompanying prospectus. You should read the entire prospectus supplement, the accompanying prospectus, the documents incorporated by reference and the other documents to which we refer for a more complete understanding of this offering. You should read “Risk Factors” beginning on page 2 of the accompanying prospectus and S-12 of this prospectus supplement for more information about important factors that you should consider before buying subordinated units in this offering. Unless otherwise indicated, the information presented in this prospectus supplement assumes that the underwriters do not exercise their option to purchase additional subordinated units from the selling unitholder.
Natural Resource Partners L.P.
      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 June 30, 2005, our reserves were subject to 160 leases with 60 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. For the same period, our total revenues were $121.4 million, and our distributable cash flow was $81.5 million. For the six months ended June 30, 2005, our lessees produced 26.9 million tons of coal generating $70.5 million in coal royalty revenues from our properties. For the same period, our total revenues were $77.9 million, and our distributable cash flow was $52.8 million. Please read “— Summary Selected Financial and Operating Data” for a reconciliation of distributable cash flow to our most directly comparable financial measure calculated and presented in accordance with GAAP.
      On July 20, 2005, we declared a quarterly cash distribution of $0.7125 per unit for the quarter ended June 30, 2005, representing an annualized distribution of $2.85 per unit. The distribution is payable on August 12, 2005 to holders of record as of August 1, 2005. None of the purchasers of subordinated units in this offering will receive the declared distribution for the second quarter of 2005. We have increased our quarterly cash distribution nine times since our initial public offering in October 2002 for an aggregate increase of approximately 39%.
Business Strategies
      Our primary business strategies are:
  •  Maximize Royalty Revenues from Our Existing Properties. We will continue to work with our lessees to increase production and royalty revenues from our properties. We provide technical knowledge of our reserves, including information about title and geology, and also review mine plans to ensure efficient recovery of reserves. We regularly visit mines to ensure that our lessees are complying with the lease terms and approved mine plans.
 
  •  Expand and Diversify Our Coal Reserves. We intend to continue to expand and diversify our reserves by acquiring additional coal properties that generate royalty income. We review potential reserve acquisitions in all coal-producing regions of the United States in order to acquire marketable reserves that we believe will be attractive to lessees. We expect to fund any future acquisitions with cash on hand, borrowings under our credit facility and proceeds from the issuance of debt or equity securities. Since our initial public offering in October 2002, we have made a number of acquisitions of coal-producing properties or overriding royalty interests, which have increased our proven and probable coal reserves by approximately 725 million tons (net of production), or approximately 63%.

S-1


Table of Contents

  •  Explore New Opportunities with Our Existing Lessees. Many of our lessees are subsidiaries of large coal producers that have plans to expand their operations. We seek to strengthen our relationships with our current lessees in order to participate in future opportunities that our lessees may identify for acquiring or leasing new properties.
 
  •  Add New Lessees to Diversify our Base of Coal Mine Operators. We actively search for additional public and private coal mine operators that meet our guidelines as qualified lessee candidates. Our extensive experience with our properties and our industry knowledge enable us to identify potential lessees who are best suited to develop and market our reserves. The addition of these new lessees will allow us to further diversify our base of coal mine operators.
Competitive Strengths
      We believe we are well positioned to execute our business strategies successfully because of the following competitive strengths:
  •  Our Royalty Structure Generates Stable Cash Flow. Our leases generally provide for royalty rates equal to the higher of a percentage of the gross sales price or a fixed price per ton of coal mined, subject to a minimum monthly, quarterly or annual payment. This structure is designed to make our cash flow stable and predictable in periods of low coal prices, while enabling us to benefit during periods of higher coal prices.
 
  •  We Do Not Directly Bear Operating Costs and Risks. Because we do not operate any mines, we do not bear ordinary operating costs and have limited direct exposure to environmental compliance, permitting and labor risks. Our lessees bear all labor-related risks, such as health care legacy costs, black lung benefits and workers’ compensation costs. In addition, we are typically not responsible for property taxes, which are paid by us but reimbursed by the lessee under the terms of the lease.
 
  •  We Primarily Lease to Large Lessees That Have a Diverse Customer Base. Our royalty income is primarily from leases to large coal companies, many of which are publicly traded. In 2004, we derived approximately 41% of our coal royalty revenues from subsidiaries of six of the top ten coal producers in the United States. These companies have made significant capital investments in the infrastructure on our properties and have effective marketing organizations. Consequently, our lessees are able to produce, process and market our reserves efficiently and then sell to a diverse group of utilities, steel companies and industrial users.
 
  •  Our Reserves are Diverse and Strategically Located. Our reserves are geographically diverse and cover a broad range of heat and sulfur content. Because our reserves consist of both metallurgical and steam coal, they are marketable to a diverse customer base. This enables our lessees to adjust to changing markets and sustain sales volumes and prices.
 
  •  We are Well Positioned to Pursue Acquisitions of Coal Reserves and Other Minerals. The coal royalty business is highly fragmented and characterized by numerous small companies that present potentially attractive acquisition opportunities. As the largest publicly traded coal royalty business, we are in a unique position to acquire additional coal reserves that complement our existing reserves. Our $175 million credit facility, all of which was available for borrowing as of August 3, 2005, and our ability to issue debt or equity securities provide the financial flexibility to pursue acquisitions.
 
  •  We Have an Experienced and Knowledgeable Management Team. Our management team has a successful record of managing, leasing and acquiring coal-producing properties. Each member of our management team who is responsible for operations has at least 20 years of experience in the mining industry. Our management team has a comprehensive understanding of the areas in which our lessees mine coal, the mining environment and the mining operators who serve as our lessees. Furthermore, our management team has demonstrated its skill and experience in identifying, negotiating and integrating acquisitions.

S-2


Table of Contents

Recent Developments
      Acquisition of Steelhead Reserves. On May 31, 2005, we entered into an agreement to purchase interests in approximately 144 million tons of reserves in the Illinois Basin for $105 million from Steelhead Development Company, LLC, an affiliate of Cline Resources & Development. We will acquire approximately 60% of the reserves in fee and will receive an override on the remaining tons. We anticipate funding the purchase with borrowings under our credit facility and proceeds from the sale of our senior notes, as described below. The reserves and the overriding royalty interest are located on 31,700 acres in Williamson and Franklin Counties in Illinois and are leased to Williamson Energy LLC, which is also an affiliate of Cline. We completed the first phase of this acquisition in July 2005, purchasing 47.5 million tons for $35 million. We expect the second and third phases, representing the remaining portions, to close in the first and third quarters of 2006, respectively.
      Private Placement of Senior Notes. On July 19, 2005, we completed a private placement of $50 million of senior unsecured notes and committed to issue an additional $50 million of senior notes on January 19, 2006. Proceeds from the first $50 million were used to repay borrowings under our existing revolving credit facility. The senior notes will begin amortizing in July 2008 and bear interest at 5.05% with an average life of approximately nine years.
      Second Quarter Financial Results. Our second quarter 2005 net income rose 65% to $25.0 million, or $0.92 per unit, compared to $15.1 million or $0.58 per unit for the same period in 2004. Distributable cash flow for the second quarter increased 90% to $29.1 million from $15.3 million in 2004. For the six months ended June 30, 2005, our net income increased 73% to $45.4 million compared to $26.3 million for the same period in 2004, while distributable cash flow rose 66% to $52.8 million from $31.8 million in 2004. Net income per unit improved 61% to $1.69 per unit from $1.05 per unit.

S-3


Table of Contents

Partnership Structure and Management
      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 make decisions on our behalf. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. As a result, Mr. Robertson is currently entitled to nominate six directors, three of whom must be independent directors, to the board of directors of GP Natural Resource Partners LLC.
      FRC-WPP NRP Investment L.P., the selling unitholder, is controlled by an affiliate of First Reserve Corporation and currently has the right to elect two directors, one of whom must be an independent director, to the board of directors of GP Natural Resource Partners LLC. FRC-WPP Investment L.P., an affiliate of Mr. Robertson, is a limited partner of the selling unitholder. See “Selling Unitholder” in this prospectus supplement and in the accompanying prospectus. Upon the completion of this offering, First Reserve will not have the right to elect any directors, and Mr. Robertson will be entitled to nominate all eight directors. We expect that Stephen P. Smith, an independent director and currently a First Reserve designee, and Alex T. Krueger, currently a First Reserve designee, will continue to serve as directors as designees of Mr. Robertson.
      The chart on the following page depicts our organizational and ownership structure, after giving effect to this offering. The percentages reflected in the organizational chart represent the approximate ownership interests in us after giving effect to this offering.
      The WPP Group includes Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation and Great Northern Properties Limited Partnership, three privately held companies that are primarily engaged in owning and managing mineral properties. Corbin J. Robertson, Jr. has a significant interest in each entity in 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. NRP Investment L.P., a limited partner of our general partner, is also an affiliate of the WPP Group.
      The senior executives and other officers who currently manage members of the WPP Group also manage us. They are employees of Western Pocahontas Properties Limited Partnership and Quintana Minerals Corporation, a company controlled by Mr. Robertson, and they allocate varying percentages of their time to managing our operations. None of our general partner, GP Natural Resource Partners LLC or any of their affiliates receive any management fee or other compensation in connection with the management of our business, but they are entitled to be reimbursed for all direct and indirect expenses incurred on our behalf.
      The offices of our operational 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.

S-4


Table of Contents

OWNERSHIP OF NATURAL RESOURCE PARTNERS L.P.
                             
 
    Common   Subordinated   Percentage    
    Units   Units   Interest    
                 
Public
    10,328,918       4,200,000       56.19 %    
WPP Group
    3,657,988       6,556,738       39.50 %    
FRC-WPP NRP Investment L.P. (1)
          596,920       2.31 %    
NRP (GP) LP
                2.00 %    
                       
Total
    13,986,906       11,353,658       100.00 %    
                       
 
LOGO
(1)  If the underwriters exercise their option to purchase additional subordinated units in full, FRC-WPP NRP Investment L.P. will not own any subordinated units upon the completion of the offering.

S-5


Table of Contents

The Offering
Subordinated units offered by the selling unitholder 4,200,000 subordinated units.
 
4,796,920 subordinated units if the underwriters exercise their option to purchase additional subordinated units.
 
Units outstanding after this offering 11,353,658 subordinated units and 13,986,906 common units.
 
Use of proceeds We will not receive any proceeds from the offering of the subordinated units by the selling unitholder. The selling unitholder will pay all expenses relating to this offering, including the underwriting discounts and commissions.
 
Cash distributions Under our partnership agreement, we must distribute all of our cash on hand as of the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define it in our partnership agreement.
 
On July 20, 2005, we declared a cash distribution of $0.7125 on all outstanding common and subordinated units for the second quarter of 2005. The distribution is payable on August 12, 2005 to holders of record as of August 1, 2005. None of the purchasers of subordinated units in this offering will receive the declared distribution for the second quarter of 2005.
 
If cash distributions per unit exceed $0.5625 in any quarter, the holders of the incentive distribution rights will receive, on a pro rata basis, a higher percentage of the cash we distribute in excess of that amount in increasing percentages up to an aggregate of 48%. We refer to these distributions as incentive distributions. For a description of our cash distribution policy, please read “Cash Distributions” in the accompanying prospectus.
 
Subordination to common units During the subordination period, subordinated units are not entitled to receive any distributions until the common units have received a minimum quarterly distribution of $0.5125 per unit, plus any arrearages in the payment of the minimum quarterly distributions from prior quarters. After the common units have received a minimum quarterly distribution of $0.5125 per unit, plus any such arrearages, the subordinated units are then entitled to receive a minimum quarterly distribution of $0.5125 per unit. With the exception of such arrearages, the common units do not have any priority over the subordinated units with respect to amounts distributed in excess of the minimum quarterly distribution of $0.5125.
 
End of subordination period The subordination period will end once we have “earned” and paid the minimum quarterly distribution on all outstanding common and subordinated units for three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2007. We will “earn” the minimum quarterly distribution if we generate adjusted operating surplus for a quarter in an amount greater than or equal to the sum of the minimum quarterly distributions on all outstanding common and subordinated units.

S-6


Table of Contents

Adjusted operating surplus is defined in our partnership agreement and, for any period, generally means:
  •  operating surplus generated with respect to that period; less
 
  •  any net increase in working capital borrowings with respect to that period; less
 
  •  any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus
 
  •  any net decrease in working capital borrowings with respect to that period; plus
 
  •  any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.
When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.
 
Early conversion of subordinated units If we earn and pay the minimum quarterly distribution on all outstanding common and subordinated units for three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2005, 25% of the subordinated units will convert into common units. If we earn and pay the minimum quarterly distribution on all outstanding common and subordinated units for three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2006, an additional 25% of the subordinated units will convert into common units. The early conversion of the second 25% of the subordinated units may not occur until at least one year after the early conversion of the first 25% of the subordinated units.
 
Our status with respect to satisfying the financial tests required for the conversion of subordinated units We have earned and paid the minimum quarterly distribution on all of our outstanding common and subordinated units for each quarter since our initial public offering in October 2002. Accordingly, if we earn and pay in the second and third quarters of 2005 distributions in an amount sufficient so that we will have earned and paid the minimum quarterly distribution for the four-quarter period ending on September 30, 2005, 25% of our outstanding subordinated units will convert into common units immediately after the quarterly distribution made with respect to the third quarter of 2005.
 
Common units to be received upon conversion of subordinated units; allocation of subordinated units to be converted A holder of subordinated units will receive one common unit for each subordinated unit that is converted. If less than all the outstanding subordinated units convert at one time (as in the case of early conversion described above), the subordinated units to be converted will be allocated pro rata among all of the subordinated unitholders as of the effective date of such conversion.

S-7


Table of Contents

Subordinated unitholders will receive cash in lieu of the issuance of fractional common or subordinated units To the extent the pro rata allocation of subordinated units to be converted would result in the issuance of a fractional common unit to any holder of subordinated units, then the number of common units issuable upon conversion of subordinated units held by such holder will be rounded down to the nearest whole number of common units, and, in lieu of issuing a fractional common unit, we will pay to such holder cash in an amount equal to the product of the last reported sales price of a common unit on the NYSE on the day before the conversion of such subordinated units and such fractional common unit. Similarly, if the pro rata allocation of subordinated units to be converted would result in the retention of a fractional subordinated unit by any holder of subordinated units, then the number of subordinated units held by such holder on the conversion date will be rounded down to the nearest whole number of subordinated units, and, in lieu of retaining the fractional subordinated unit, we will pay to such holder cash in an amount equal to the product of the last reported sales price of a subordinated unit on the NYSE on the day before the conversion of such subordinated units and the fractional common unit.
 
Tax consequences of conversion A holder of subordinated units generally will not recognize any income, gain, loss or deduction upon the conversion of subordinated units into common units. If a unitholder receives cash in lieu of a fractional common or retained subordinated unit upon conversion, such distribution of cash generally will not be taxable to the unitholder for federal income tax purposes to the extent of the unitholder’s tax basis in his units immediately before the distribution. The unitholder’s aggregate basis in the common units issued upon conversion of the subordinated units will equal the unitholder’s adjusted basis in the corresponding converted subordinated units, less any amount of cash distributed with respect to a fractional unit and any decrease in the unitholder’s share of our nonrecourse liabilities. The unitholder’s aggregate basis in the retained subordinated units will be reduced by any amount of cash distributed with respect to a fractional unit and any decrease in the unitholder’s share of our nonrecourse liabilities. Please read “Tax Considerations” in this prospectus supplement and “Material Tax Consequences — Tax Consequences of Unit Ownership” in the accompanying prospectus. The unitholder’s holding period for the common units will include the holding period for the corresponding converted subordinated unit.
 
Estimated ratio of taxable income to distributions If you own the subordinated units you purchase in this offering, or the common units issued upon conversion thereof, through the record date for the distribution for the fourth quarter of 2007, we estimate that you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 40% of the cash distributed to you with respect to that period. A substantial portion of the income that will be allocated to you is expected to be long-term capital gain, which for individuals is subject to a significantly lower maximum federal

S-8


Table of Contents

income tax rate (currently 15%) than ordinary income (currently taxable at a maximum rate of 35%). If you are an individual taxable at the maximum rate of 35% on ordinary income, the effect of this lower capital gains rate is to produce an after-tax return to you that is the same as if the amount of federal ordinary taxable income allocated to you for that period were approximately 30% of the cash distributed to you for that period. Please read “Tax Considerations” in this prospectus supplement for the basis of this estimate.
 
New York Stock Exchange symbol The subordinated units have been approved for listing under the symbol “NSP.”

S-9


Table of Contents

Summary Selected Financial and Operating Data
      We derived the summary selected historical financial data for Natural Resource Partners L.P. as of and for the years ended December 31, 2003 and 2004 from our audited financial statements, and we derived the summary selected historical financial data for Natural Resource Partners L.P. as of and for the six-month periods ended June 30, 2004 and 2005 from our unaudited financial statements.
      The following table should be read together with, and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes incorporated by reference in this prospectus supplement.
                                   
    For the Year Ended   For the Six Months
    December 31,   Ended June 30,
         
    2003   2004   2004   2005
                 
    (In thousands, except price data)
Income Statement Data:
                               
Revenues:
                               
 
Coal royalties
  $ 73,770     $ 106,456     $ 49,027     $ 70,487  
 
Property taxes
    5,069       5,349       2,584       2,981  
 
Minimums recognized as revenue
    2,033       1,763       928       934  
 
Override royalties
    1,022       3,222       1,434       824  
 
Other
    3,572       4,642       1,886       2,718  
                         
 
Total revenues
    85,466       121,432       55,859       77,944  
Expenses:
                               
 
Depletion and amortization
    25,365       30,957       14,283       16,504  
 
General and administrative
    8,923       11,503       5,133       6,474  
 
Property, franchise and other taxes
    5,810       6,835       3,369       3,784  
 
Coal royalty and override payments
    1,299       2,045       786       1,298  
                         
 
Total expenses
    41,397       51,340       23,571       28,060  
                         
Income from operations
    44,069       70,092       32,288       49,884  
 
Interest expense
    (6,814 )     (10,312 )     (6,098 )     (5027 )
 
Interest income
    206       349       112       562  
 
Loss on early extinguishments of debt
          (1,135 )            
 
Loss from sale of oil and gas properties
    (55 )                  
 
Loss from interest rate hedge
    (499 )                  
                         
Net income
  $ 36,907     $ 58,994     $ 26,302     $ 45,419  
                         
Balance Sheet Data (at period end):
                               
Total assets
  $ 531,676     $ 599,926     $ 593,957     $ 618,273  
Deferred revenue
    15,054       15,847       13,262       15,498  
Long-term debt
    192,650       156,300       156,300       164,950  
Total liabilities
    223,518       190,734       185,040       199,534  
Partners’ capital
    308,158       409,192       408,917       418,739  
Cash Flow Data:
                               
Net cash flow provided by (used in):
                               
 
Operating activities
  $ 64,528     $ 90,847     $ 36,491     $ 57,448  
 
Investing activities
    (142,511 )     (77,733 )     (77,332 )     (21,544 )
 
Financing activities
    94,550       4,669       38,080       (27,247 )
Other Data:
                               
Royalty coal tons produced by lessees
    44,344       48,357       23,658       26,882  
Average gross coal royalty per ton
  $ 1.66     $ 2.20     $ 2.07     $ 2.62  
Distributable cash flow(1)
  $ 59,828     $ 81,497     $ 31,841     $ 52,762  

S-10


Table of Contents

(1)  Distributable cash flow represents cash flow from operations less actual principal payments and cash reserves for scheduled principal payments on our senior notes.
Distributable cash flow is a “non-GAAP financial measure” that is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable cash flow is a significant liquidity metric that indicates NRP’s ability to generate cash flows at a level that can sustain or support an increase in quarterly cash distributions paid to its partners. Distributable cash flow is also the quantitative standard used throughout the investment community with respect to publicly traded partnerships. Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. We believe that “net cash provided by operating activities” is the most comparable financial measure to distributable cash flow.
The following table reconciles distributable cash flow to net cash provided by operating activities.
                                   
    For the Year Ended   For the Six Months
    December 31,   Ended June 30,
         
    2003   2004   2004   2005
                 
    (In thousands)
Cash flow from operations
  $ 64,528     $ 90,847     $ 36,491     $ 57,448  
Less scheduled principal payments
          (9,350 )     (9,350 )     (9,350 )
Less reserves for future principal payments
    (4,700 )     (9,400 )     (4,700 )     (4,700 )
Add reserves used for scheduled principal payments
          9,400       9,400       9,400  
                         
 
Distributable cash flow
  $ 59,828     $ 81,497     $ 31,841     $ 52,798  
                         

S-11


Table of Contents

RISK FACTORS
      An investment in our subordinated units involves risks. You should carefully consider the following risk factors, together with all of the other information included in, or incorporated by reference into, this prospectus supplement, when evaluating an investment in our subordinated units. If any of these risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our subordinated units or common units could decline, and you could lose all or part of your investment. For information concerning the other risks related to our business, please read the risk factors included under the caption “Risk Factors” beginning on page 2 of the accompanying prospectus as well as those risks discussed in our Annual Report on Form 10-K and Quarterly Reports on Form 10-Q, which are incorporated by reference in this prospectus supplement.
We may not be able to pay any or all of the minimum quarterly distribution on the subordinated units.
      During the subordination period, we are not permitted to make cash distributions on the subordinated units until the common units have received the minimum quarterly distribution for that quarter and any arrearages in the payment of this amount that might have accrued on the common units. As a result, we may not generate sufficient cash in any given quarter to pay the minimum quarterly distribution or any lesser amount on the subordinated units, even if we are able to pay the full minimum quarterly distribution on the common units.
The subordinated units may not convert at the expected time or at all.
      The subordinated units are subordinated to the common units during the subordination period. The subordination period will generally not end prior to September 30, 2007, although 25% of the subordinated units may convert as early as September 30, 2005, and another 25% may convert as early as September 30, 2006. We must satisfy a number of conditions in order for the subordination period to end, which will result in the conversion of the subordinated units into common units. In order for the subordination period to end, we must satisfy the following conditions:
  •  we must earn the amount of the full minimum quarterly distribution during those three four-quarter periods, as well as the related distribution on the general partner interest; and
 
  •  we must pay the minimum quarterly distribution on all the outstanding common and subordinated units for the three preceding consecutive, non-overlapping four-quarter periods preceding that date.
      When we refer to “earning” the amount of the minimum quarterly distribution, we mean that the amount of the minimum quarterly distribution must qualify as “adjusted operating surplus” under the terms of our partnership agreement. Adjusted operating surplus for any period generally means:
  •  operating surplus generated with respect to that period; less
 
  •  any net increase in working capital borrowings with respect to that period; less
 
  •  any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus
 
  •  any net decrease in working capital borrowings with respect to that period; plus
 
  •  any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.
      If we do not meet those tests, the subordination period will continue until we have satisfied these conditions, the subordinated units will remain subordinated to the common units, and the unit price of the subordinated units may decline. Please read “Cash Distributions” in the accompanying prospectus.

S-12


Table of Contents

There is no existing market for our subordinated units, and a trading market that will provide you with adequate liquidity may not develop or continue.
      Prior to this offering, there has been no public market for the subordinated units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. As a result, you may not be able to resell your subordinated units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the subordinated units and limit the number of investors who are willing to buy the subordinated units. If the early conversions described above occur, the number of outstanding subordinated units will decline, and the liquidity of the subordinated units that remain outstanding may decline significantly. This could also result in wide bid-ask spreads, significant fluctuations in the market price of the subordinated units and limitations on the number of investors who are willing to buy subordinated units.
Subordinated units are junior in rank to the common units with respect to distributions and upon liquidation. Subordinated units also have more limited voting rights than common units.
      Our subordinated units are a separate class of limited partner interests in us and are junior to our common units. Subordinated units are not entitled to receive any distributions until the common units have received their minimum quarterly distribution, plus any arrearages from prior quarters. The subordinated units are not entitled to receive any arrearages. In addition, if we liquidate during the subordination period, in some circumstances, holders of outstanding common units will be entitled to receive more per unit in liquidating distributions than holders of outstanding subordinated units. Furthermore, unlike common units, the subordinated units are not entitled to vote on approval of the withdrawal of our general partner or the transfer by our general partner of its general partner interest or the transfer of incentive distribution rights under some circumstances. Please read “Description of Our Units — Matters Applicable Only to Subordinated Units” beginning on page 22 of the accompanying prospectus for a discussion of the differences between our subordinated units and our common units.

S-13


Table of Contents

USE OF PROCEEDS
      We will not receive any proceeds from the sale of the subordinated units by the selling unitholder in this offering.
CAPITALIZATION
      The following table sets forth our actual capitalization as of June 30, 2005 and our capitalization as of June 30, 2005, as adjusted for the closing of the first phase of the Steelhead acquisition described in “Summary — Recent Developments” and the senior notes offering on July 19, 2005.
                   
        As adjusted
    Actual as of   as of
    June 30, 2005   June 30, 2005
         
    (unaudited, in thousands)
Cash and cash equivalents
  $ 50,760     $ 47,760  
             
Current portion of long-term debt
  $ 9,350     $ 9,350  
Long-term debt:
               
 
Senior notes
    146,950       196,950  
 
Credit facility
    18,000        
             
Total debt
    174,300       206,300  
             
Partners’ capital:
               
 
Common unitholders
    248,503       248,503  
 
Subordinated unitholders
    161,280       161,280  
 
General partner
    9,439       9,439  
 
Holders of incentive distribution rights
    345       345  
 
Other accumulated comprehensive loss
    (828 )     (828 )
             
Total partners’ capital
    418,739       418,739  
             
Total capitalization
  $ 593,039     $ 625,039  
             

S-14


Table of Contents

PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS
      As of July 11, 2005, there were 13,906,986 common units outstanding, held by approximately 15,214 holders, including common units held in street name. Our common units are traded on the NYSE under the symbol “NRP.” An additional 11,353,658 subordinated units are outstanding. These subordinated units are currently held by FRC-WPP NRP Investment L.P., which is the selling unitholder in this offering, and by the WPP Group. Prior to this offering, there has been no public market for our subordinated units. We expect the initial public offering price of the subordinated units to be at a discount of approximately 2% to 4% to the closing price of our common units prior to the determination of the offering price of our subordinated units. The closing price of our common units, which trade on the NYSE under the symbol “NRP,” was $68.19 on August 3, 2005. The subordinated units have been approved for listing on the NYSE under the symbol “NSP.”
      The following table sets forth, for the periods indicated, the high and low sales price ranges for our common units, as reported on the NYSE Composite Transaction Tape, and quarterly declared cash distributions per common unit.
                           
    Price Range of    
    Common Units    
        Cash Distribution
    High   Low   per Unit(1)
             
2005
                       
 
Third Quarter (through August 3, 2005)
  $ 68.95     $ 57.60       (2)  
 
Second Quarter
    61.05       49.00     $ 0.7125 (3)
 
First Quarter
    63.14       48.00       0.6875  
2004
                       
 
Fourth Quarter
  $ 57.98     $ 40.00     $ 0.6625  
 
Third Quarter
    40.50       37.31       0.6375  
 
Second Quarter
    38.98       34.30       0.6000  
 
First Quarter
    43.53       35.50       0.5750  
2003
                       
 
Fourth Quarter
  $ 41.49     $ 28.25     $ 0.5625  
 
Third Quarter
    37.00       29.60       0.5375  
 
Second Quarter
    31.84       22.90       0.5225  
 
First Quarter
    23.98       20.45       0.5225  
 
(1)  Distributions declared per common and subordinated unit associated with each respective quarter.
 
(2)  We expect to declare and pay a cash distribution for the third quarter of 2005 within 45 days following the end of that quarter.
 
(3)  The distribution for the second quarter is payable on August 12, 2005 to holders of record as of August 1, 2005. None of the purchasers of subordinated units in this offering will receive the declared distribution for the second quarter of 2005.

S-15


Table of Contents

MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. As of December 31, 2004, we controlled approximately 1.8 billion tons of proven and probable coal reserves in nine states. Approximately 67% and 59% of the coal produced from our properties came from underground mines and approximately 33% and 41% came from surface mines for the year ended December 31, 2004 and the six months ended June 30, 2005, respectively. 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 June 30, 2005, our reserves were subject to 160 leases with 60 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. For the six months ended June 30, 2005, our lessees produced 26.9 million tons of coal generating $70.5 million in coal royalty revenues from our properties and our total revenue was $77.9 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. Our lessees located in Appalachia have 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. Similarly, our revenues in Appalachia have increased to an average of $2.83 per ton for the six months ended June 30, 2005 from an average of $2.19 per ton for the same period of 2004. Coal royalty revenues from our Appalachian properties represented 93% of our total coal royalty revenues for the full year of 2004 and 91% of our total coal royalty revenues for the six months ended June 30, 2005. In spite of the higher prices, most of our lessees have not appreciably increased production due to a number of constraints, including a shortage of labor, permitting issues and rail transportation problems.
      Approximately 35% of our 2004 coal royalty revenues and 33% of our coal royalty revenues in the first quarter of 2005 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 been substantially higher over the last two years. Metallurgical coal, because of its unique chemical characteristics, is usually priced higher than steam

S-16


Table of Contents

coal. The current pricing environment for U.S. metallurgical coal is strong in both the domestic and seaborne export markets.
      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 v. 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 Permit 21 program. The court’s 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 at the time of the July 8 order. Pending the resolution of any appeals, this decision will dramatically slow 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 2005, a lawsuit was filed in Eastern District of Kentucky on similar grounds challenging the legality of Nationwide Permit 21. In March 2005, the plaintiffs filed a motion for summary judgment requesting the court to (1) issue a declaratory judgment that Nationwide Permit 21 violates Section 404 of the Clean Water Act and (2) issue an injunction prohibiting the Corps from issuing further authorizations pursuant to Nationwide Permit 21 in Kentucky. The motion also requested the court to suspend those authorizations for valley fills on which the placement of mining spoil in streams had not commenced as of the date of filing of the motion. 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 will 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, and 3% for each of the six-month periods ended June 30, 2005 and June 30, 2004 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.

S-17


Table of Contents

Results of Operations
                                       
    For the Year Ended   For the Six Months
    December 31,   Ended June 30,
         
    2003   2004   2004   2005
                 
            (Unaudited)
    (In thousands, except price data)
Revenues:
                               
 
Coal royalties
  $ 73,770     $ 106,456     $ 49,027     $ 70,487  
 
Property taxes
    5,069       5,349       2,584       2,981  
 
Minimums recognized as revenue
    2,033       1,763       928       934  
 
Override royalties
    1,022       3,222       1,434       824  
 
Other
    3,572       4,642       1,886       2,718  
                         
 
Total revenues
    85,466       121,432       55,859       77,944  
Expenses:
                               
 
Depletion and amortization
    25,365       30,957       14,283       16,504  
 
General and administrative
    8,923       11,503       5,133       6,474  
 
Property, franchise and other taxes
    5,810       6,835       3,369       3,784  
 
Coal royalty and override payments
    1,299       2,045       786       1,298  
                         
 
Total expenses
    41,397       51,340       23,571       28,060  
                         
Income from operations
    44,069       70,092       32,288       49,884  
Other income (expense):
                               
 
Interest expense
    (6,814 )     (10,312 )     (6,098 )     (5,027 )
 
Interest income
    206       349       112       562  
 
Loss on early extinguishments of debt
          (1,135 )            
 
Loss from sale of oil and gas properties
    (55 )                  
 
Loss from interest rate hedge
    (499 )                  
                         
Net income
  $ 36,907     $ 58,994     $ 26,302     $ 45,419  
                         
Other Data:
                               
Royalties
                               
   
Appalachia
  $ 63,855     $ 98,541     $ 45,672     $ 63,997  
   
Illinois Basin
    3,566       3,852       1,498       2,400  
   
Northern Powder River Basin
    6,349       4,063       1,857       4,090  
                         
     
Total
  $ 73,770     $ 106,456     $ 49,027     $ 70,487  
                         
Production (tons)
                               
   
Appalachia
    35,998       42,089       20,868       22,611  
   
Illinois Basin
    3,034       3,138       1,298       1,574  
   
Northern Powder River Basin
    5,312       3,130       1,492       2,697  
                         
     
Total
    44,344       48,357       23,658       26,882  
                         
Average gross royalty per ton
                               
   
Appalachia
  $ 1.77     $ 2.34     $ 2.19     $ 2.83  
   
Illinois Basin
    1.18       1.23       1.15       1.52  
   
Northern Powder River Basin
    1.20       1.30       1.24       1.52  
                         
     
Total
  $ 1.66     $ 2.20     $ 2.07     $ 2.62  
                         

S-18


Table of Contents

Six months ended June 30, 2005 compared with six months ended June 30, 2004
      Revenues. For the six months ended June 30, 2005, coal royalty revenues were $70.5 million on 26.9 million tons of coal produced, compared to $49.0 million in coal royalty revenues on 23.7 million tons of coal produced for the first half of 2004, representing a 44% increase in coal royalty revenues and a 14% increase in production. Coal royalty revenues comprise 90% of our total revenue, with property taxes, minimums recognized as revenue, override royalties and other totaling $7.5 million, or 10% of total revenue.
      The following is a breakdown of our major coal producing regions:
      Appalachia. As a result of significantly higher prices, coal royalty revenues in Appalachia for the six months ended June 30, 2005 were $64.0 million compared to $45.7 million for the same period in 2004, an increase of $18.3 million or 40%. For the six months ended June 30, 2005, production in Appalachia was 22.6 million tons compared to 20.9 million tons for the same period in 2004, an increase of 1.7 million tons or 8%.
      The following properties generated significantly higher production and/or coal royalty revenues during the six months ended June 30, 2005.
  •  Pinnacle — production increased from 325,000 tons to 1.4 million tons while coal royalty revenues increased from $988,000 to $5.3 million. The increased tonnage was due to the mine resuming production after being idle during a portion of the six months ended June 30, 2004.
 
  •  Sincell — production increased from 219,000 tons to 1.5 million tons and coal royalty revenues increased from $376,000 to $2.7 million. The increased production was due to a longwall unit moving onto our property.
 
  •  Eunice — production increased from 1.0 million tons to 1.7 million tons and coal royalty revenues increased from $2.0 million to $4.3 million. The increased tonnage was due to higher production by the longwall unit on our property.
 
  •  Lynch — production increased from 2.0 million tons to 2.6 million tons and coal royalty revenues increased from $3.7 to $5.6 million. The increased production was due to new mines being opened on the property.
 
  •  BLC Properties — production increased from 1.7 million tons to 1.9 million tons and coal royalty revenues increased from $4.1 million to $6.5 million. These increases in tonnage were due to a combination of some lessees increasing production and some having a greater proportion of production on our property, which offset reductions by a lessee who experienced geologic problems.
 
  •  KY Land — production increased from 1.1 million tons to 1.3 million tons and coal royalty revenues increased from $2.9 million to $4.3 million. The increased tonnage was due to a combination of lessees increasing production and some having a greater proportion of production on our property.
 
  •  Dorothy — production increased from 715,000 tons to 1.0 million tons and coal royalty revenues increased from $1.5 million to $3.0 million. The increased tonnage was due to additional producing units being on our property.
 
  •  Eastern Kentucky Property — production increased from 37,000 tons to 353,000 tons and coal royalty revenues increased from $98,000 to $1.1 million. The increased production was due to a greater proportion of production from the mine being on our property.
 
  •  Kingston — production increased from 622,000 tons to 804,000 tons and coal royalty revenues increased from $1.1 million to $2.2 million. The increased tonnage was due to an additional producing unit being on our property and a new surface mine starting on the property.
 
  •  Plum Creek — production from our Plum Creek properties increased from zero to 253,000 tons and coal royalty revenue increased from zero to $723,000, due to the March 2005 acquisition of the property.

S-19


Table of Contents

      These increases were partially offset by lower production on our West Fork, Evans-Lavier and VICC/ Alpha properties. Production on our West Fork property decreased from 1.6 million tons to zero and coal royalty revenues decreased from $4.2 million to zero as longwall mining was completed on our property. On our Evans-Lavier property, production decreased from 1.7 million tons to 869,000 tons and coal royalty revenues decreased from $2.4 million to $1.5 million as a lower proportion of the production was on our property. On our VICC/ Alpha property, production decreased from 3.8 million tons to 3.3 million tons but coal royalty revenues increased from $7.7 million to $8.4 million. The decrease in production was due to a combination of a lower proportion of the production being on our property and mines exhausting their reserves and geologic problems. The increased sales price realized by our lessees offset this lower production resulting in higher coal royalty revenue.
      Illinois Basin. As a result of higher prices and increased production, coal royalty revenues in the Illinois Basin for the six months ended June 30, 2005 were $2.4 million compared to $1.5 million for the same period in 2004, an increase of $0.9 million or 60%. For the six months ended June 30, 2005, production in the Illinois Basin was 1.6 million tons compared to 1.3 million tons for the same period in 2004, an increase of 276,000 tons or 21%.
      On our Cummings/ Hocking Wolford property, production increased from 597,000 tons to 812,000 tons and coal royalty revenues increased from $641,000 to $1.1 million. The increased production was due to a greater proportion of production being on our property and an increase in the royalty rate under the lease terms. Our Sato property production increased from 398,000 tons to 544,000 tons and coal royalty revenues increased from $540,000 to $909,000. The increased production was due to higher production from the active mine on our property. These increases in production were partially offset by lower production on our Trico property where production decreased from 303,000 tons to 218,000 tons but coal royalty revenues increased from $318,000 to $362,000 due to higher sales prices being received by our lessee. The decrease in production was due to exhaustion of a portion of the reserves at the mine.
      Northern Powder River Basin. Production from our Western Energy property increased from 1.5 million tons to 2.7 million tons and coal royalty revenues increased from $1.9 million to $4.1 million. These increases were due to the typical variations in production resulting from the checkerboard ownership pattern and higher sales prices being received by our lessee.
      Expenses. For the six months ended June 30, 2005, total expenses were $28.1 million, compared to $23.6 million for the first half of 2004, representing an increase of $4.5 million, or 19%. Included in total expenses are:
  •  Depletion and amortization of $16.5 million for the first half of 2005, compared to $14.3 million for the same period of 2004, an increase of $2.2 million, or 15% due to the increase in production volumes;
 
  •  General and administrative expenses of $6.5 million for the first half of 2005, compared to $5.1 million for the first six months of 2004, an increase of $1.4 million, or 27%. Most of the increase in general and administrative expenses is attributable to compensation expenses for additional staff required to manage the properties we acquired as well as accruals under our long-term incentive compensation plans due to the increase in our unit price; and
 
  •  Property, franchise and other taxes of $3.8 million for the six months ended June 30, 2005, compared to $3.4 million for the first six months of 2004, an increase of $0.4 million, or 12%, due to an increase in franchise taxes for 2005.
      Interest Expense. For the six months ended June 30, 2005, interest expense was $5.0 million compared to $6.1 million for 2004, a decrease of $1.1 million. This decrease is attributed to lower outstanding balances on our credit facility and senior notes during the first half of 2005.

S-20


Table of Contents

      Year ended December 31, 2004 compared with 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.

S-21


Table of Contents

      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.
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 “Risk Factors” beginning on page 2 of the accompanying prospectus. Our capital expenditures, other than for acquisitions, have historically been minimal.
      Net cash provided by operations for the six-month periods ended June 30, 2005 and 2004 was $57.4 million and $36.5 million, respectively. Net cash provided by operations for the years ended December 31, 2004 and 2003 was $90.8 million and $64.5 million, respectively. Substantially all of our cash provided by operations since inception has been from coal royalty revenues.
      Net cash used in investing activities for the six months ended June 30, 2005 was $21.5 million compared to $77.3 million for the corresponding period in 2004. The 2005 results include the acquisition of coal reserves from Plum Creek Timber Company, Inc. Net cash used in investing activities for 2004 include the

S-22


Table of Contents

acquisitions of coal reserves from BLC and Apollo. Net cash used in investing activities for the year ended December 31, 2004 was $77.7 million. The 2004 results include the BLC, Appolo, Pardee Minerals, and Clinchfield acquisitions. We funded these acquisitions with available cash and borrowings under our revolving credit facility. Borrowings under our revolving credit facility were subsequently paid in full with the proceeds from our equity offering in March 2004. Net cash used in investing activities for the year ended December 31, 2003 was $142.5 million. This amount includes the acquisition of the Alpha Natural Resources reserves and overriding royalty interest and PinnOak Resources and Eastern Kentucky reserves. We funded these acquisitions with borrowings under our revolving credit facility. We repaid $175 million of those borrowings with the proceeds from the issuance of senior notes in June and September of 2003.
      Net cash used by financing activities for the six months ended June 30, 2005 was $27.2 million compared to net cash provided by financing activities of $38.1 million for the same period in 2004. In the six months ended June 30, 2005, we borrowed $18.0 million under our credit facility to fund the Plum Creek acquisition, paid $9.4 million in principal payments on our senior notes and we made distributions to our partners totaling $35.9 million. During the six months ended June 30, 2004, results include $200.4 million in net proceeds from our equity offering in March 2004, a $2.1 million capital contribution from our general partner to maintain its 2% general partner interest, 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. We also paid distributions to our partners totaling $28 million. 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 related $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 an increase in the borrowing amount 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 included $142.1 million under our revolving credit facility and $175.0 million from the issuance of our senior 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.
Contractual Obligations and Commercial Commitments
      Our debt exists entirely at our wholly owned subsidiary, NRP Operating LLC, and at June 30, 2005 consisted of:
  •  $18 million outstanding under our $175 million revolving credit facility that matures in October 2009;
 
  •  $53.4 million of 5.55% senior notes due 2023, with a 10-year average life;
 
  •  $68 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.
      We have agreed to sell to institutional investors an additional $100 million of our senior notes. These notes will mature in 2020, have an average life of 8.5 years and bear interest at 5.05%. We will pay interest only on the notes for the first two years and begin making principal payments in July 2007. We issued $50 million of the notes in July 2005 and used the proceeds to repay amounts borrowed under our revolving credit facility as well as amounts borrowed to finance the first phase of the Steelhead acquisition described above. We expect to sell the remaining $50 million in January 2006 to fund the second phase of the

S-23


Table of Contents

Steelhead acquisition. As a result, $175 million was available for borrowing under the credit facility as of August 3, 2005.
      Credit Facility. On October 29, 2004, NRP (Operating) LLC entered into a 5-year, $175 million revolving credit facility with Citigroup Global Markets, Inc. and Wachovia Capital Markets, LLC as joint lead arrangers. The new credit facility replaced NRP Operating’s previous 3-year facility, which would have expired in October 2005. In addition to substantially improved pricing terms, the new facility permits NRP Operating to increase the size of the facility up to $300 million without obtaining lender consents. As a result of entering into the new credit facility, we expensed $1.1 million of unamortized loan financing costs related to NRP Operating’s early extinguishment of its previous credit facility.
      Our obligations under the new credit facility are unsecured but are guaranteed by our operating subsidiaries. We may prepay all loans at any time without penalty. Indebtedness under the revolving credit facility bears interest, at our option, at either:
  •  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 June 30, 2005 (in millions):
                                                         
    Payments Due by Period(1)
     
Contractual Obligations   Total   2005   2006   2007   2008   2009   Thereafter
                             
Long-term debt (including current maturities)
  $ 238.29     $ 4.11     $ 17.33     $ 16.85     $ 16.38     $ 33.90     $ 149.72  
                                           
 
(1)  The amounts indicated in the table include principal and interest due on our senior notes.
      Shelf Registration Statements. 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

S-24


Table of Contents

form of common units representing limited partner interests in Natural Resource Partners or debt securities of NRP or any of our operating subsidiaries. We currently have approximately $290.2 million available under our registration statement. The registration statement also covers, for possible future sales, up to 373,715 common units held by Great Northern Properties Limited Partnership.
      The securities may be offered from time to time directly or through underwriters at amounts, prices, interest rates and other terms to be determined at the time of any offering. The net proceeds from the sale of securities from the shelf will be used for future acquisitions and other general corporate purposes, including the retirement of existing debt. We will not receive any proceeds from the sale of common units by Great Northern Properties.
      On June 28, 2005, we filed a shelf registration statement with the Securities and Exchange Commission in order to register the 4,796,920 subordinated units held by FRC-WPP NRP Investment L.P. After the completion of this offering, 596,920 subordinated units will remain available for sale by the selling unitholder under this registration statement. If the underwriters exercise their option to purchase additional subordinated units from the selling unitholder in connection with this offering, there will not be any more subordinated units available for sale under this registration statement. We will not receive any proceeds from the sale of subordinated units under this registration statement.

S-25


Table of Contents

BUSINESS
      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 acquired an additional 85 million tons in March 2005 in connection with the Plum Creek acquisition and an additional 47.5 million tons in July 2005 when we completed the first phase of the Steelhead acquisition. We lease our 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, subject to minimum payments. As of June 30, 2005, our reserves were subject to 160 leases with 60 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 revenues were $121.4 million. For the six months ended June 30, 2005, our lessees produced 26.9 million tons of coal generating $70.5 million in coal royalty revenues from our properties and our total revenues were $77.9 million.
Coal Reserves and Production
      The following table sets forth production data and reserve information for the properties in each of the following areas: Appalachia, Illinois Basin and Northern Powder River Basin.
                                                   
    Production   Proven and Probable Reserves at
    Year Ended December 31,   December 31, 2004
         
Area   2002   2003   2004   Underground   Surface   Total
                         
    (Tons in thousands)
Appalachia
    22,600       35,998       42,098       1,444,678       152,077       1,595,755  
Illinois Basin
    2,433       3,034       3,138             19,794       19,794  
Northern Powder River Basin
    5,474       5,312       3,130             153,023       153,023  
                                     
 
Total
    30,507       44,344       48,357       1,444,678       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 total proven and probable reserves were compliance coal. We present the quality of the coal 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 were from metallurgical coal.

S-26


Table of Contents

      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
                 
            Medium   High            
    Compliance   Low (less   (1.0% to   (greater       Heat Content   Sulfur    
Area   Coal(1)   than 1.0%)   1.5%)   than 1.5%)   Total   (Btu per 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.
Major Coal Properties
      The following is a summary of our major coal producing properties based on 2004 production:
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, L.L.C. 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, the Tennessee Valley Authority, VEPCO and U.S. Steel.

S-27


Table of Contents

      Lynch. The Lynch property is located in Harlan and Letcher Counties, Kentucky. In 2004, 4.5 million tons were produced from this property. We primarily lease the property to Resource Development, LLC., an independent coal producer. Production comes from both underground mines and surface mines. Production from the mines is transported by truck to a preparation plant on the property and is shipped primarily on the CSX railroad to utility customers such as Georgia Power and Orlando Utilities.
      BLC Properties. The BLC Properties are located in Kentucky, Tennessee, West Virginia, Virginia and Alabama. In 2004, 3.5 million tons were produced from these properties. We purchased these properties in January 2004 from BLC Properties LLC. We lease this property to a number of operators including Appolo Fuels Inc., Bell County Coal Corporation and Kopper-Glo Fuels. Production comes from both underground and surface mines and is trucked to preparation plants and loading facilities operated by our lessees. Coal is transported by truck and is shipped via both CSX and Norfolk & Southern railroads to utility and industrial customers. Major customers include Southern Company, SCE&G, and numerous medium and small industrial customers.
      West Fork. The West Fork property is located in Boone County, West Virginia. In 2004, 2.7 million tons were produced from this property. We lease the property to Eastern Associated Coal Company, a subsidiary of publicly held Peabody Energy Company. Production from the property is from an underground mine, and the coal is transported via belt to a preparation plant on an adjacent property and shipped by CSX railroad to both utility and metallurgical customers such as Cinergy, Detroit Edison and U.S. Steel. In 2004, the longwall mineable reserves were exhausted and we do not expect significant production from this property in the future.
      Evans-Laviers. The Evans-Laviers property is located in Breathitt, Floyd, Knott and Magoffin Counties, Kentucky. In 2004, 2.5 million tons were produced from this property. We lease the property to CONSOL of Kentucky Inc., a subsidiary of publicly held CONSOL Energy Inc., which operates an underground mine and contracts the operations of other mines to third-party operators. Additionally, a sublessee has a surface and a highwall mine on the property. The underground mine is on our property as well as adjacent property. The coal produced from this property is trucked to the Big Sandy River for barge transport or is transported by truck or beltline to preparation plants located on site and on adjacent property. Coal is shipped from the preparation plants on the CSX railroad to customers such as DuPont, Virginia Electric Power, Southern Company, American Electric Power and Electric Fuels.
      Lone Mountain. The Lone Mountain property is located in Harlan County, Kentucky. In 2004, 2.4 million tons were produced from this property. We lease the property to Ark Land Company, a subsidiary of publicly held Arch Coal, Inc. Production comes from underground mines and is transported primarily by beltline to a preparation plant on adjacent property and shipped on the Norfolk Southern or CSX railroads to utility customers such as Georgia Power and the Tennessee Valley Authority.
      VICC/ Kentucky Land. The VICC/ Kentucky Land property is located primarily in Perry, Leslie and Pike Counties, Kentucky. We purchased the property in December 2002 from El Paso Corporation. In 2004, 2.3 million tons were produced from this property. Coal is produced from a number of lessees and from both underground and surface mines. Coal is shipped primarily by truck and also on the CSX and Norfolk Southern railroads to customers such as Southern Company, the Tennessee Valley Authority 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.

S-28


Table of Contents

      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 Company. 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.
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.

S-29


Table of Contents

MANAGEMENT
      The following table sets forth information with respect to the executive officers and members of the board of directors of GP Natural Resource Partners LLC. Executive officers and directors are elected for one-year terms. Unless otherwise noted below, the individuals have served as officers or directors of GP Natural Resource Partners LLC since our initial public offering.
             
Name   Age   Position with the General Partner
         
Corbin J. Robertson, Jr. 
    57     Chief Executive Officer and Chairman of the Board
Nick Carter
    59     President and Chief Operating Officer
Dwight L. Dunlap
    52     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
Kevin J. Craig
    37     Vice President of Business Development
Kenneth Hudson
    51     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. 
    60     Director
Stephen P. Smith **
    44     Director
 
  *  Independent director and member of the Audit Committee, Conflicts Committee and Compensation, Nominating and Governance Committee of GP Natural Resource Partners LLC.
**  Independent director and member of the Audit Committee of GP Natural Resource Partners LLC.
      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 has served as Chairman of the Board of Quintana Maritime Limited since January 2005. 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.
      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.
      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

S-30


Table of Contents

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 LLP from September 1997 through July 2000.
      Kevin J. Craig is Vice President — Business Development of GP Natural Resource Partners LLC. Mr. Craig joined NRP in April 2005. Mr. Craig previously served as Terminal Manager, West Virginia Coalfields for CSX Transportation Inc., a subsidiary of CSX Corporation, from 2003 until he joined NRP and held various marketing and finance-related jobs at CSX from 1996 to 2003. Prior to joining CSX, Mr. Craig served as a Captain in the United States Army. Mr. Craig has also served as a Delegate to the West Virginia House of Delegates since 2000.
      Kenneth Hudson is 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 and prior to that as a Managing Director at Morgan Stanley. He served a four-year term on the Financial Accounting Standards Advisory Council and currently serves as a trustee of Cornell University, where he serves as Chairman of Cornell’s Finance Committee and a member of the Executive Committee of the Board. 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

S-31


Table of Contents

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.

S-32


Table of Contents

TAX CONSIDERATIONS
      The tax consequences to you of an investment in our subordinated units and common units issuable upon conversion will depend in part on your own tax circumstances. For a discussion of the principal federal income tax considerations associated with our operations and the purchase, ownership and disposition of our subordinated and common units, please read “Material Tax Consequences” in the accompanying prospectus. You are urged to consult with your own tax advisor about the federal, state, local and foreign tax consequences peculiar to your circumstances.
      If you purchase subordinated units in this offering and own them, or the common units issued upon conversion of the subordinated units, through the record date for the distribution for the fourth quarter of 2007, we estimate that you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 40% of the cash distributed to you with respect to that period. A substantial portion of the income that will be allocated to you is expected to be long-term capital gain, which for individuals is subject to a significantly lower maximum federal income tax rate (currently 15%) than ordinary income (currently taxable at a maximum rate of 35%). If you are an individual taxable at the maximum rate of 35% on ordinary income, the effect of this lower capital gains rate is to produce an after-tax return to you that is the same as if the amount of federal taxable income allocated to you for that period were approximately 30% of the cash distributed to you for that period. These estimates are based upon the assumption that our available cash for distribution will be sufficient to make quarterly distributions of $0.7125 per unit and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and certain tax reporting positions that we have adopted with which the Internal Revenue Service could disagree. Accordingly, we cannot assure you that the estimates will be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units. See “Material Tax Consequences” in the accompanying prospectus.
      Ownership of subordinated and common units by tax-exempt entities, regulated investment companies and foreign investors raises issues unique to such persons. Please read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors” in the accompanying prospectus.
Consequences of Conversion
      A holder of subordinated units generally will not recognize any income, gain, loss or deduction upon the conversion of subordinated units into common units. If a unitholder receives cash in lieu of a fractional common or retained subordinated unit upon conversion, such distribution of cash generally will not be taxable to the unitholder for federal income tax purposes to the extent of the unitholder’s tax basis in his units immediately before the distribution. The unitholder’s aggregate basis in the common units issued upon conversion of the subordinated units will equal the unitholder’s adjusted basis in the corresponding converted subordinated units, less any amount of cash distributed with respect to a fractional unit and any decrease in the unitholder’s share of our nonrecourse liabilities. The unitholder’s aggregate basis in the retained subordinated units will be decreased by any amount of cash distributed with respect to a fractional unit and any decrease in the unitholder’s share of our nonrecourse liabilities. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership” in the accompanying prospectus. The unitholder’s holding period for these common units will include the holding period for the corresponding converted subordinated units.

S-33


Table of Contents

SELLING UNITHOLDER
      This prospectus supplement covers the sale of up to 4,796,920 subordinated units, including the underwriters’ option to purchase an additional 596,920 subordinated units, by FRC-WPP NRP Investment L.P., the selling unitholder. FRC-WPP NRP Investment L.P., a Delaware limited partnership, has two limited partners: FRC-NRP A.V. Holdings L.P., an affiliate of First Reserve, and FRC-WPP Investment L.P., an affiliate of Corbin J. Robertson, Jr. The general partner of the selling unitholder is FRC-WPP GP LLC, a Delaware limited liability company controlled by affiliates of First Reserve. The selling unitholder currently has the right to nominate two of our directors. First Reserve holds a significant interest in Alpha Natural Resources, which is one of our largest lessees, and holds a significant interest in Foundation Coal, Inc., which controls the lessee on our Kingston Property in West Virginia.
      The selling unitholder will bear all costs, expenses and fees in connection with the registration of the units offered under this prospectus supplement and the accompanying prospectus. Brokerage commissions and similar selling expenses, if any, attributable to the sale of the units will be borne by the selling unitholder. The selling unitholder does not own any of our common units. The following table sets forth information relating to the selling unitholder’s beneficial ownership of our subordinated units:
                                 
    Subordinated Units Owned upon Completion of Offering
     
    Assuming No Exercise   Assuming Exercise
    of Underwriters’ Option   of Underwriters’ Option
         
Number of Subordinated Units       Percentage of       Percentage of
Owned by Prior to Offering   Number   Subordinated Units   Number   Subordinated Units
                 
4,796,920
    596,920       5.25 %            

S-34


Table of Contents

UNDERWRITING
      Lehman Brothers Inc. and Citigroup Global Markets Inc. are acting as representatives of the underwriters. Under the terms of the underwriting agreement, which is filed as an exhibit on Form 8-K, each of the underwriters named below has severally agreed to purchase from the selling unitholder the respective number of subordinated units set forth opposite each underwriter’s name.
           
    Number of
Underwriter   Subordinated Units
     
Lehman Brothers Inc. 
       
Citigroup Global Markets Inc. 
       
A.G. Edwards & Sons, Inc. 
       
UBS Securities LLC
       
Wachovia Capital Markets, LLC
       
Friedman, Billings, Ramsey & Co., Inc. 
       
Sanders Morris Harris Inc.
       
       
 
Total
    4,200,000  
       
      The underwriting agreement provides that the underwriters’ obligation to purchase the subordinated units depends on the satisfaction of the conditions contained in the underwriting agreement including:
  •  the obligation to purchase all of the subordinated units offered hereby, if any of the subordinated units are purchased;
 
  •  the representations and warranties made by us and the selling unitholder to the underwriters are true;
 
  •  there is no material change in the financial markets; and
 
  •  we and the selling unitholder deliver customary closing documents to the underwriters.
Commissions and Expenses
      The following table summarizes the underwriting discounts and commissions that the selling unitholder will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional subordinated units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay the selling unitholder for the subordinated units.
                   
    No Exercise   Full Exercise
         
Per subordinated unit
  $       $    
 
Total
  $       $    
      The representatives of the underwriters have advised us that the underwriters proposed to offer the subordinated units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $           per subordinated unit. The underwriters may allow, and selected dealers may reallow, a discount from the concession not in excess of $           per subordinated unit on sales to other dealers. After the offering, the representatives may change the public offering price and the other selling terms.
      The expenses of the offering that are payable by the selling unitholder are estimated to be $500,000 (exclusive of underwriting discounts and commissions). The selling unitholder will pay all expenses relating to this offering, including the underwriting discounts and commissions.
Option to Purchase Additional Subordinated Units
      The selling unitholder has granted to the underwriters an option exercisable for 30 days from the date of this prospectus to purchase, from time to time, in whole or in part, up to an aggregate 596,920 additional

S-35


Table of Contents

subordinated units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than 4,200,000 subordinated units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional subordinated units based on the underwriter’s percentage underwriting commitment in the offering as indicated in the table at the beginning of this underwriting section.
Lock-Up Agreements
      We, our general partners, the officers and directors of our general partners, our significant security holders and affiliates and the selling unitholder have agreed not to directly or indirectly offer for sale, sell, pledge or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of), or sell or grant options, rights or warrants with respect to, any subordinated units or common units, or any securities convertible into or exercisable or exchangeable for subordinated units or common units (other than pursuant to existing employee benefit plans, including our general partner’s long-term incentive plan, or pursuant to outstanding options, warrants or rights), enter into any swap or other derivatives transaction that transfers, in whole or in part, any of the economic benefits or risks of ownership of subordinated units or common units, file or cause to be filed a registration statement with respect to the registration of any subordinated units or common units, or securities convertible, exercisable or exchangeable into subordinated units or common units or any of our other securities or publicly disclose the intention to do any of the foregoing for a period commencing on the underwriting agreement and ending 90 days from the date of this prospectus supplement, without the prior written consent of Lehman Brothers Inc. and Citigroup Global Markets Inc. The foregoing restrictions will not restrict the ability of such persons to pledge such securities in connection with a bona fide loan or transfer such securities to their affiliates or affiliates of our general partners provided that such affiliates agree, among other things, to be bound by the foregoing restrictions. These restrictions also do not apply to accretive acquisitions of assets, businesses or the capital stock or other ownership interests of businesses by us in exchange for subordinated units or common units if the recipient of such subordinated units or common units agrees not to dispose of any subordinated units or common units received in connection with the acquisition during that period. Lehman Brothers Inc. and Citigroup Global Markets Inc., in their sole discretion, may release any of the subordinated units or common units subject to these lock-up agreements at any time without notice.
      The 90-day restricted period described in the preceding paragraph will be extended if:
  •  during the last 17 days of the 90-day restricted period we issue an earnings release or announce material news or a material event; or
 
  •  prior to the expiration of the 90-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 90-day period,
in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.
      Lehman Brothers Inc. and Citigroup Global Markets Inc. have informed the parties to the lock-up agreements that they have no present intent or arrangement to release any of the subordinated units or common units subject to the lock-up agreements. The release of units subject to any of the lock-up agreements is considered on a case-by-case basis. Factors in deciding whether to release these units may include the length of time before the particular lock-up expires, the number of units involved, historical trading volumes of our subordinated units and common units and whether the person seeking the release is an officer, director or affiliate of us or our general partners.

S-36


Table of Contents

Offering Price Determination
      Prior to this offering, there has been no public market for our subordinated units. The initial public offering price of our subordinated units will be negotiated between us and the underwriters. We expect the offering price of the subordinated units to be at a discount of approximately 2% to 4% to the closing price of our common units on the date we determine the offering price of our subordinated units. The closing price of our common units, which trade on the NYSE under the symbol “NRP,” was $68.19 on August 3, 2005. Other factors we expect to be considered in determining the initial public offering price of our subordinated units include prevailing market conditions, our historical performance, estimates of our business potential and earnings prospects, an assessment of our management and the consideration of the above factors in relation to market valuation of companies in related businesses.
Indemnification
      We, our general partners, our operating company and the selling unitholder have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.
Stabilization, Short Positions and Penalty Bids
      The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the subordinated units or common units, in accordance with Regulation M under the Securities Exchange Act of 1934:
  •  Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
 
  •  A short position involves a sale by the underwriters of subordinated units in excess of the number of subordinated units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of subordinated units involved in the sales made by the underwriters in excess of the number of subordinated units they are obligated to purchase is not greater than the number of subordinated units that they may purchase by exercising their option to purchase additional subordinated units. In a naked short position, the number of subordinated units involved is greater than the number of subordinated units in their option to purchase additional subordinated units. The underwriters may close out any short position by either exercising their option to purchase additional subordinated units and/or purchasing subordinated units in the open market. In determining the source of subordinated units to close out the short position, the underwriters will consider, among other things, the price of subordinated units available for purchase in the open market as compared to the price at which they may purchase subordinated units through their option to purchase additional subordinated units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the subordinated units in the open market after pricing that could adversely affect investors who purchase in the offering.
 
  •  Syndicate covering transactions involve purchases of the subordinated units in the open market after the distribution has been completed in order to cover syndicate short positions.
 
  •  Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the subordinated units originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.
      These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our subordinated units or our common units or preventing or retarding a decline in the market price of the subordinated units or the common units. As a result, the price of the subordinated units or the common units may be higher than the price that might otherwise exist in the

S-37


Table of Contents

open market. These transactions may be effected on The New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.
      Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the subordinated units or the common units. In addition, neither we nor any of the underwriters make representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.
Electronic Distribution
      A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of subordinated units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.
      Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus supplement and the accompanying prospectus form a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.
New York Stock Exchange
      The subordinated units have been approved for listing on the New York Stock Exchange under the symbol “NSP.”
Stamp Taxes
      If you purchase subordinated units offered in this prospectus supplement and the accompanying prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus supplement and the accompanying prospectus.
Relationships
      The underwriters may in the future perform investment banking and advisory services for us, our general partner and our affiliates from time to time for which they may in the future receive customary fees and expenses. The underwriters may, from time to time, engage in transactions with or perform services for us, our general partners and our affiliates in the ordinary course of their business. Affiliates of Citigroup Global Markets Inc. and Wachovia Capital Markets, LLC are lenders under our credit facility.
NASD
      Because the NASD views our subordinated units as interests in a direct participation program, any offering of subordinated units pursuant to this registration statement will be made in compliance with Rule 2810 of the NASD Conduct Rules. Investor suitability with respect to the subordinated units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

S-38


Table of Contents

LEGAL
      The validity of the subordinated units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the subordinated units offered hereby will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.
EXPERTS
      Ernst & Young LLP, independent registered public accounting firm, have audited (i) the consolidated financial statements of Natural Resource Partners L.P. and management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004, (ii) the financial statements of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, and Arch Coal Contributed Properties, and (iii) the balance sheet of NRP (GP) LP (Exhibit 99.1), included in our Annual Report on Form 10-K for the year ended December 31, 2004, as set forth in their reports, which are incorporated by reference in this prospectus and elsewhere in the registration statement. These financial statements and management’s assessment are incorporated by reference in reliance on Ernst & Young LLP’s reports, given on their authority as experts in accounting and auditing.
      On April 26, 2002, Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation dismissed Arthur Andersen LLP as their independent public accountants due to the adverse publicity being experienced by Arthur Andersen LLP and concerns regarding the acceptance of its audits. Ernst & Young LLP was engaged on May 3, 2002 by Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation to serve as their independent auditors for the three years ended December 31, 2000 and 2001.
      Arthur Andersen LLP’s reports on the financial statements of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, and New Gauley Coal Corporation for the years ended December 31, 2001 and 2000 did not contain an adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles. During the years ended December 31, 2001 and 2000 and through April 26, 2002:
  •  there were no disagreements with Arthur Andersen LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure which if not resolved to Arthur Andersen LLP’s satisfaction, would have caused them to make reference to the subject matter in connection with their reports on the financial statements of any of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, or New Gauley Coal Corporation for such years;
 
  •  there were no reportable events as listed in 304(a)(1)(v) of Regulation S-K; and
 
  •  Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, and New Gauley Coal Corporation did not consult Ernst & Young LLP with respect to the application of accounting principles to a specified transaction either completed or proposed, or the type of audit opinion that might be rendered on the financial statements of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, or New Gauley Coal Corporation or any other matters or reportable events listed in Items 304(a)(2)(i) and (ii) of Regulation S-K.
      The reports of Ernst & Young LLP are incorporated by reference in this prospectus supplement, and the financial statements listed above are incorporated by reference in reliance on Ernst & Young LLP’s reports, given on their authority as experts in accounting and auditing.
INFORMATION REGARDING FORWARD LOOKING STATEMENTS
      This prospectus supplement, the accompanying prospectus and the documents incorporated in this prospectus supplement by reference include forward-looking statements. These forward-looking statements are

S-39


Table of Contents

identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond the ability of us and our affiliates to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include but are not necessarily limited to:
  •  the cost of acquiring new coal reserves;
 
  •  the ability to acquire coal reserves on satisfactory terms;
 
  •  the prices for which coal from our properties can be sold;
 
  •  the volatility of commodity prices for coal;
 
  •  our ability to lease new and existing coal reserves;
 
  •  the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves, including as a result of extraordinary capital expenditures, development and reclamation costs and severance and excise taxes;
 
  •  the ability of our lessees to obtain favorable sales contracts for coal produced from our reserves;
 
  •  competition among producers in the coal industry generally;
 
  •  the extent to which the amount and quality of actual production differs from estimated coal reserves;
 
  •  unanticipated geologic problems;
 
  •  availability of required materials and equipment;
 
  •  the occurrence of unusual weather events, accidents, changes in governmental regulation, equipment failures, transportation delays, labor-related interruptions or adverse operating conditions, including force majeure;
 
  •  the timing of receipt by our lessees of necessary governmental permits;
 
  •  the outcome of several ongoing environmental lawsuits relating to federal and state regulation of and permitting for the mining industry;
 
  •  our lessees’ labor relations and costs;
 
  •  changes in governmental regulation or enforcement practices, especially with respect to mining, environmental and health and safety matters, such as emissions levels applicable to coal-burning power generators and steel manufacturers;
 
  •  the experience and financial condition of our lessees, including their ability to satisfy their royalty, environmental, reclamation and other obligations;
 
  •  fluctuations in transportation costs and the availability or reliability of transportation of coal from our properties;
 
  •  any future announcements of production cuts or implementation of previously announced cuts by our lessees;
 
  •  a decrease in the demand for coal by the electricity generation or steel production industries;
 
  •  any increase or decrease in coal imports or exports; and

S-40


Table of Contents

  •  risks and uncertainties relating to general domestic and international economic (including inflation and interest rates) conditions and political conditions.
      Many of such factors are beyond our ability to control or predict. We caution readers not to put undue reliance on forward-looking statements.
      When considering forward-looking statements, please review the risk factors described under “Risk Factors” in this prospectus supplement, the accompanying prospectus and the documents incorporated by reference.
WHERE YOU CAN FIND MORE INFORMATION
      The SEC allows us to “incorporate by reference” information we file with it. This procedure means that we can disclose important information to you by referring you to documents filed with the SEC. The documents listed below and any filings made with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 after the date of this prospectus and prior to the termination of this offering (excluding any information furnished pursuant to Item 7.01 or Item 2.02 on any current report on Form 8-K) are incorporated by reference in this prospectus until the termination of each offering under this prospectus.
  •  Quarterly Reports on Form 10-Q for the periods ended March 31, 2005 and June 30, 2005.
 
  •  Annual Report on Form 10-K for the fiscal year ended December 31, 2004.
 
  •  Current Reports on Form 8-K filed January 31, 2005; March 3, 2005; March 31, 2005; June 1, 2005; June 28, 2005; July 12, 2005; July 20, 2005; and August 3, 2005 (excluding Item 2.02 and Item 7.01 information).
 
  •  The description of the subordinated units contained in the Registration Statement on Form 8-A, initially filed June 28, 2005, and any subsequent amendment thereto filed for the purpose of updating such description.
      You may also request a copy of these filings at no cost by making written or telephone requests for copies to:
  Natural Resource Partners L.P.
  601 Jefferson Street
  Suite 3600
  Houston, Texas 77002
  Attention: Investor Relations Department
  Telephone: (713) 751-7555
      We make available free of charge on or through our Internet website, www.nrplp.com, 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 SEC. Information contained on our website is not part of this prospectus.
      You should rely only on the information incorporated by reference or provided in this prospectus supplement and the accompanying prospectus. We have not authorized anyone else to provide you with any information. You should not assume that the information incorporated by reference or provided in this prospectus supplement and the accompanying prospectus is accurate as of any date other than the date on the front of each document.

S-41


Table of Contents

PROSPECTUS
Natural Resource Partners L.P.
 
4,796,920 Subordinated Units
4,796,920 Common Units
 
        This prospectus relates to:
  •  4,796,920 subordinated units representing limited partner interests in Natural Resource Partners L.P.; and
 
  •  4,796,920 common units representing limited partner interests in Natural Resource Partners L.P. that may be issued upon conversion of the 4,796,920 subordinated units registered herein.
      The subordinated units and the common units, which we refer to collectively in this prospectus as units, may be offered from time to time by the selling unitholder named in this prospectus or in any supplement to this prospectus. We will not receive any proceeds from any sale of units by any such selling unitholder, unless otherwise indicated in a prospectus supplement. For a more detailed discussion of the selling unitholder, please read “Selling Unitholder.”
      This prospectus describes the general terms of the units and the general manner in which the selling unitholder will offer the units. The prospectus supplement will describe the specific manner in which the selling unitholder will offer the units.
      Our common units are traded on the New York Stock Exchange under the symbol “NRP.” On July 29, 2005, the last reported sales price of our common units was $64.75 per common unit. The rights of holders of subordinated units, including the right to receive distributions, are subordinated to the rights of holders of common units. Prior to this offering, there has not been a public market for the subordinated units. We currently expect the initial public offering price of the subordinated units to be between $57 and $63 per subordinated unit. We have applied for listing of the subordinated units on the New York Stock Exchange. The price of subordinated units offered in subsequent offerings will be based on the closing price of the subordinated units on the New York Stock Exchange at the time of such offering.
 
       Limited partnerships are inherently different from corporations. You should carefully consider each of the factors described under “Risk Factors,” which begins on page 2 of this prospectus, before you make an investment in our securities.
       Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
 
The date of this prospectus is August 2, 2005.


Table of Contents

TABLE OF CONTENTS
             
    1  
    1  
    2  
      2  
        2  
        3  
        3  
        3  
        4  
        4  
        4  
        4  
        5  
        5  
        5  
        6  
        6  
        6  
        6  
        7  
        7  
      7  
        7  
        7  
        8  


Table of Contents

             
        9  
        9  
        9  
        10  
        10  
      10  
        10  
        11  
        12  
        13  
        13  
        14  
        14  
        15  
        15  
      15  
        15  
        16  
        16  
        16  
        16  
        17  
        17  
    18  
    18  
      18  
      18  
      19  

ii


Table of Contents

           
      20  
      20  
      21  
      22  
      22  
      23  
    25  
      25  
      25  
      26  
      28  
      28  
      28  
      29  
      29  
      30  
      30  
    33  
      33  
      35  
      35  
      39  
      42  
      43  
      44  
      45  
      47  
    48  
    49  
    50  
    50  
    52  
    52  
    52  
    II-5  
      You should rely only on the information contained in this prospectus, any prospectus supplement and the documents we have incorporated by reference. Neither we nor the selling unitholder have authorized anyone else to give you different information. We will disclose any material changes in our affairs in an amendment to this prospectus, a prospectus supplement or a future filing with the SEC incorporated by reference in this prospectus. You should not assume that the information incorporated by reference or provided in this prospectus or any prospectus supplement is accurate as of any date other than the date on the front of each document.

iii


Table of Contents

ABOUT THIS PROSPECTUS
      This prospectus is part of a registration statement that we have filed with the Securities and Exchange Commission using a “shelf” registration process. Under this shelf registration process, the selling unitholder may sell up to 4,796,920 subordinated units representing limited partner interests in Natural Resource Partners L.P. and up to 4,796,920 common units representing limited partner interests in Natural Resources L.P. and into which the subordinated units are convertible. This prospectus generally describes Natural Resource Partners L.P., the subordinated units and the common units. Each time the selling unitholder sells units with this prospectus, we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add to, update or change information in this prospectus. The information in this prospectus is accurate as of its date. Therefore, you should carefully read this prospectus and any prospectus supplement and the additional information described under the heading “Where You Can Find More Information” before you invest in our securities.
ABOUT NATURAL RESOURCE PARTNERS
      We are 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 March 31, 2005, our reserves were subject to 157 leases with 57 lessees. In 2004, our lessees produced 48.4 million tons of coal from our properties and our coal royalty revenues were $106.5 million.
      We conduct all of our business through our wholly owned operating company, NRP (Operating) LLC, and its wholly owned subsidiaries, WPP LLC, ACIN LLC and WBRD LLC.
      Our address is 601 Jefferson, Suite 3600, Houston, Texas 77002, and our telephone number is (713) 751-7507. Our website address is www.nrplp.com. The information contained in our website is not part of this prospectus.
      As used in this prospectus, “we,” “us,” “our” and “Natural Resource Partners” mean Natural Resource Partners L.P. and, where the context requires, our operating company, NRP (Operating) LLC, and its subsidiaries.

1


Table of Contents

RISK FACTORS
      Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our units. When units are offered pursuant to a prospectus supplement, additional risk factors relevant to those units may be included in the prospectus supplement.
      This prospectus also contains forward-looking statements that involve risks and uncertainties. Please read “Forward-Looking Statements.” Our actual results could differ materially from those anticipated in the forward-looking statements as a result of certain factors, including the risks described below and elsewhere in this prospectus. If any of these risks occur, our business, financial condition and results of operations could be adversely affected, the trading price of our subordinated units and common units could decline and you could lose all or part of your investment.
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.
      The amount of cash we can distribute on our units principally depends upon the amount of royalties we receive from our lessees, which will fluctuate from quarter to quarter based on, among other things:
  •  the amount of coal our lessees are able to produce from our properties;
 
  •  the price at which our lessees are able to sell coal;
 
  •  the level of our operating costs;
 
  •  the level of our general and administrative costs; and
 
  •  prevailing economic conditions.
      In addition, the actual amount of cash we will have available for distribution will depend on other factors that include:
  •  the costs of acquisitions, if any;
 
  •  our debt service requirements;
 
  •  fluctuations in our working capital;
 
  •  the level of capital expenditures we make;
 
  •  restrictions on distributions contained in our debt instruments;
 
  •  our ability to borrow under our working capital facility to pay distributions; and
 
  •  the amount of cash reserves established by our general partner in its sole discretion in the conduct of our business.
      You should also be aware that our ability to pay quarterly distributions each quarter depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not make distributions during periods when we record net income.

2


Table of Contents

A substantial or extended decline in coal prices could reduce our coal royalty revenues and the value of our coal reserves.
      The prices our lessees receive for their coal depend upon factors beyond their or our control, including:
  •  the supply of and demand for domestic and foreign coal;
 
  •  weather conditions;
 
  •  the proximity to and capacity of transportation facilities;
 
  •  worldwide economic conditions;
 
  •  domestic and foreign governmental regulations and taxes;
 
  •  the price and availability of alternative fuels; and
 
  •  the effect of worldwide energy conservation measures.
      A substantial or extended decline in coal prices could materially and adversely affect us in two ways. First, lower prices may reduce the quantity of coal that may be economically produced from our properties. This, in turn, could reduce our coal royalty revenues and the value of our coal reserves. Second, even if production is not reduced, the royalties we receive on each ton of coal sold may be reduced.
Our lessees’ coal mining operations are subject to operating risks that could result in lower coal royalty revenues to us.
      Our coal royalty revenues are largely dependent on our lessees’ level of production from our coal reserves. The level of our lessees’ production is subject to operating conditions or events beyond their or our control including:
  •  the inability to acquire necessary permits or mining or surface rights;
 
  •  changes or variations in geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;
 
  •  changes in governmental regulation of the coal industry or the electric utility industry;
 
  •  mining and processing equipment failures and unexpected maintenance problems;
 
  •  interruptions due to transportation delays;
 
  •  adverse weather and natural disasters, such as heavy rains and flooding;
 
  •  labor-related interruptions; and
 
  •  fires and explosions.
      These conditions may increase our lessees’ cost of mining and delay or halt production at particular mines for varying lengths of time or permanently. Any interruptions to the production of coal from our reserves may reduce our coal royalty revenues.
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 depend on a limited number of primary operators for a significant portion of our coal royalty revenues. If reductions in production by these operators are implemented on our properties and sustained, our revenues may be substantially affected. Additionally, if a lessee were to experience financial difficulty, the lessee might not be able to pay its royalty payments or continue its operations, which could materially reduce our coal royalty revenues.

3


Table of Contents

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.
      A failure on the part of one of our lessees to make coal royalty payments could give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we were to repossess any of our properties, we would seek a replacement lessee. We might not be able to find a replacement lessee and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced. In addition, it may be difficult for us to secure new or replacement lessees for small or isolated coal reserves, since industry trends toward consolidation favor larger-scale, higher-technology mining operations in order to increase productivity.
If our lessees do not manage their operations well, their production volumes and our coal royalty revenues could decrease.
      We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to:
  •  marketing of the coal mined;
 
  •  mine plans, including the amount to be mined and the method of mining;
 
  •  processing and blending coal;
 
  •  credit risk of their customers;
 
  •  permitting;
 
  •  insurance and surety bonding;
 
  •  acquisition of surface rights and other mineral estates;
 
  •  employee wages;
 
  •  coal transportation arrangements;
 
  •  compliance with applicable laws, including environmental laws;
 
  •  negotiations and relations with unions; and
 
  •  mine closure and reclamation.
      If our lessees do not manage their operations well, their production could be reduced, which would result in lower coal royalty revenues to us.
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.
      Our coal royalty business generates substantially all of our revenues. Due to our lack of asset diversification, an adverse development in the coal industry would have a significantly greater impact on our financial condition and results of operations than if we owned more diverse assets.
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.
      Our lessees produce a significant amount of the metallurgical coal that is used in both the U.S. and foreign steel industries. In 2004, approximately 35% of the coal royalty revenues from our properties were from metallurgical coal. The steel industry has increasingly relied on electric arc furnaces or pulverized

4


Table of Contents

coal processes to make steel. These processes do not use coke. If this trend continues, the amount of metallurgical coal that our lessees mine could continue to decrease. Additionally, since the amount of steel that is produced is tied to global economic conditions, a decline in those conditions could result in the decline of steel, coke and coal production. Since metallurgical coal is priced higher than steam coal, some mines on our properties may only operate profitably if all or a portion of their production is sold as metallurgical coal. If these mines are unable to sell metallurgical coal, these mines may not be economically viable and may close.
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.
      Because our reserves decline as our lessees mine our coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves or other mineral reserves that are economically recoverable. If we are unable to replace or increase our coal reserves or acquire other mineral reserves on acceptable terms, our royalty revenues will decline as our reserves are depleted. In addition, if we are unable to successfully integrate the companies, businesses or properties we are able to acquire, our royalty revenues may decline and we could experience a material adverse effect on our business, financial condition or results of operations. If we acquire additional reserves, there is a possibility that any acquisition could be dilutive to our earnings and reduce our ability to make distributions to unitholders. Any debt we incur to finance an acquisition may also reduce our ability to make distributions to unitholders. Our ability to make acquisitions in the future also could be limited by restrictions under our existing or future debt agreements, competition from others for attractive properties or the lack of suitable acquisition candidates.
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.
      Domestic electric power generation accounts for approximately 90% of domestic coal consumption. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants, such as natural gas, nuclear, fuel oil and hydroelectric power, and environmental and other governmental regulations. We expect new power plants will be built to produce electricity. Many of these new power plants will likely be fired by natural gas because of lower construction costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. The increasingly stringent requirements of the federal Clean Air Act may result in more electric power generators shifting from coal to natural-gas-fired power plants.
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.
      Our lessees compete with numerous other coal producers in various regions of the United States for domestic sales. During the mid-1970s and early 1980s, increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in additional production capacity throughout the industry, all of which led to increased competition and lower coal prices. Any increases in coal prices could also encourage the development of expanded capacity by new or existing coal producers. Any resulting overcapacity could reduce coal prices and therefore reduce our coal royalty revenues.
      Competition from coal with lower production costs shipped east from western coal mines has resulted in increased competition for coal sales from the Appalachian region and the Illinois Basin. This competition could result in a decrease in market share for our lessees operating in these regions and a decrease in our coal royalty revenues.

5


Table of Contents

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.
      Coal supply contracts do not generally require operators to satisfy their obligations to their customers with coal mined from specific reserves. Several factors may influence a lessee’s decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the lessee’s lease with us, mining conditions, mining operations costs, cost and availability of transportation, and customer coal specifications. If a lessee satisfies its obligations to its customers with coal from properties we do not own or lease, production on our properties will decrease, and we will receive lower coal royalty revenues.
Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from our properties.
      Transportation costs represent a significant portion of the total cost of coal for the customers of our lessees. Increases in transportation costs could make coal a less competitive source of energy or could make coal produced by some or all of our lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition for our lessees from coal producers in other parts of the country.
      Our lessees depend upon railroads, barges, trucks and beltlines to deliver coal to their customers. Disruption of those transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and other events could temporarily impair the ability of our lessees to supply coal to their customers. Our lessees’ transportation providers may face difficulties in the future that may impair the ability of our lessees to supply coal to their customers, resulting in decreased coal royalty revenues to us.
Our reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of our reserves.
      Our reserve estimates may vary substantially from the actual amounts of coal our lessees may be able to economically recover from our reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate to:
  •  future coal prices, operating costs, 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 areas where our lessees currently mine.
      Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. As a result, you should not place undue reliance on our coal reserve data that is incorporated by reference in this prospectus.
Our lessees’ work forces could become increasingly unionized in the future.
      Some of the mines on our properties are operated by unionized employees of our lessees or their affiliates. Our lessees’ employees could become increasingly unionized in the future. Some labor unions active in our lessees’ areas of operations are attempting to organize the employees of some of our lessees. If some or all of our lessees’ non-unionized operations were to become unionized, it could adversely affect their productivity, increase costs and increase the risk of work stoppages. In addition, our lessees’ operations may be adversely affected by work stoppages at unionized companies, particularly if union

6


Table of Contents

workers were to orchestrate boycotts against our lessees’ operations. Any further unionization of our lessees’ employees could adversely affect the stability of production from our reserves and reduce our coal royalty revenues.
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.
      Borrowings under our revolving credit facility may be subject to variable interest rates based on LIBOR. If the LIBOR rate increases, the interest payable with respect to borrowings under our revolving credit facility that are subject to variable interest rates will increase. Increased interest payments will reduce the cash available for distribution to you and may materially adversely affect our results of operations.
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.
      We depend on our lessees to correctly report the coal royalty revenues that they owe us. Although we conduct regular audits and mine inspections of our lessees, we may not discover a reporting error in the financial period to which it relates. As a result, the coal royalty revenues that we report in our financial statements may be incorrect in any given period.
Regulatory and Legal Risks
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.
      Our lessees may incur substantial costs and liabilities under increasingly strict federal, state and local environmental, health and safety and endangered species laws, including regulations and governmental enforcement policies. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our lessees’ operations. Our lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their operations. If our lessees are pursued for these sanctions, costs and liabilities, their mining operations and, as a result, our coal royalty revenues could be adversely affected.
      Some species indigenous to our properties are protected under the Endangered Species Act. Federal and state legislation for the protection of endangered species may have the effect of prohibiting or delaying our lessees from obtaining mining permits and may include restrictions on road building and other mining activities in areas containing the affected species. Additional species on our properties may receive protected status, and currently protected species may be discovered within our properties. Either event could result in increased costs to us or our lessees.
      New environmental legislation, new regulations and new interpretations of existing environmental laws, including regulations governing permitting requirements and the protection of endangered species, could further regulate or tax the coal industry and may also require our lessees to change their operations significantly to incur increased costs or to obtain new or different permits, any of which could decrease our coal royalty revenues.
A substantial portion of our coal has a high sulfur content. This coal may become more difficult to sell because the Clean Air Act restricts the ability of electric utilities to burn high sulfur coal.
      Sulfur is a naturally occurring component of coal. In 1995, Phase I of the Clean Air Act required power plants to reduce their emissions of sulfur dioxide to the equivalent of approximately 2.5 pounds or less per million Btus. In 2000, Phase II of these regulations further restricted emissions to the equivalent of approximately 1.2 pounds of sulfur dioxide per million Btus. These restrictions may reduce the demand

7


Table of Contents

by electric utilities for high sulfur coal. Currently, electric utilities operating coal-fired plants can purchase credits that allow them to comply with the sulfur dioxide emission compliance requirements, install emission-control equipment, switch to lower sulfur fuel or reduce generating levels. Many of the power plants supplied by our lessees do not currently have emission-control equipment that reduces sulfur dioxide emissions, such as scrubbers. As of December 31, 2004, 63% of our coal reserves were not compliance coal, which is low-sulfur coal that, when burned, emits no more than 1.2 pounds of sulfur dioxide per million Btus. If our lessees’ customers, or their potential customers in our market areas, choose not to purchase our noncompliance coal, our lessees may be unable to find other buyers for this coal at current price and volume levels, which could materially adversely affect our coal royalty revenues and our ability to make distributions to our unitholders.
The Clean Air Act affects the end-users of coal and could significantly affect the demand for our coal and reduce our coal royalty revenues.
      The Clean Air Act and corresponding state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides and other compounds emitted from industrial boilers and power plants, including those that use our coal. These regulations constitute a significant burden on coal customers and stricter regulation could adversely affect the demand for and price of our coal, especially higher sulfur coal, resulting in lower coal royalty revenues.
      In July 1997, the U.S. Environmental Protection Agency, or “EPA,” adopted more stringent ambient air quality standards for particulate matter and ozone. Particulate matter includes small particles that are emitted during the coal combustion process. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA’s position, although it remanded the EPA’s ozone implementation policy for further consideration. On remand, the Court of Appeals for the D.C. Circuit affirmed the EPA’s adoption of these more stringent ambient air quality standards. As a result of the finalization of these standards, states that have not attained these standards will have to revise their State Implementation Plans to include provisions for the control of ozone precursors and particulate matter. Revised State Implementation Plans could require electric power generators to further reduce nitrogen oxide and particulate matter emissions. The potential need to achieve these emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other by-products of coal combustion could restrict the market for coal and the development of new mines by our lessees. This, in turn, may result in decreased production by our lessees and a corresponding decrease in our coal royalty revenues.
      Furthermore, in October 1998, the EPA finalized a rule that will require 19 states in the Eastern United States that have ambient air quality problems to make substantial reductions in nitrogen oxide emissions by the year 2004. To achieve these reductions, many power plants will be required to install additional control measures. The installation of these measures will make it more costly to operate coal-fired power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel.
      Additionally, the U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against a number of investor-owned electric utilities and brought an administrative action against one government-owned electric utility for alleged violations of the Clean Air Act. The EPA claims that the power plants operated by these utilities have failed to obtain permits required under the Clean Air Act for facility modifications. Our lessees supply coal to some of the affected utilities, and it is possible that other of our lessees’ customers will be sued. These lawsuits could require the affected utilities to pay penalties and install pollution control equipment or undertake other emission reduction measures, which could adversely affect their demand for coal. In fact, settlements between the EPA and several utilities related to these alleged violations have resulted in the retirement of some facilities and additional capital expenditures at others. Any outcome that adversely affects our lessees’ customers and their demand for coal could adversely affect our coal royalty revenues.

8


Table of Contents

      Other proposed initiatives may have an effect upon our lessees’ coal operations. One such proposal is the Bush Administration’s Clear Skies Initiative, which was announced in February 2002 and introduced into the U.S. House and Senate in February 2003 as the Clear Skies Act of 2003. As proposed, this initiative is designed to reduce emissions of sulfur dioxide, nitrogen oxides and mercury from power plants. Other so-called multi-pollutant bills that could regulate additional air pollutants, including carbon dioxide, have been proposed in Congress. While the details of all of these proposed initiatives vary, there appears to be a movement towards increased regulation of a number of power plant air pollutants. If these initiatives were enacted into law, power plants could choose to shift away from coal as a fuel source to meet these requirements.
      The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, which is intended to limit emissions of greenhouse gases, such as carbon dioxide. In December 1997, the signatories to the convention established a set of emission reduction targets for developed nations including the United States, commonly known as the Kyoto Protocol. The United States, however, has not ratified the treaty commitments, the current administration has withdrawn support for this treaty, and no comprehensive federal regulations focusing on greenhouse emissions are in place. Nevertheless, restrictions on greenhouse gas emissions, whether through ratification of the Kyoto protocol or other efforts to stabilize or reduce gas emissions, including initiatives being considered by several states, could adversely affect the price and demand for coal.
      The Clean Air Act also imposes standards on sources of hazardous air pollutants. The EPA has announced that it will regulate hazardous air pollutants from coal-fired power plants. Under the Clean Air Act, coal-fired power plants may be required to control hazardous air pollution emissions by approximately 2009. These controls are likely to require significant new investments in controls by power plant owners. Like other environmental regulations, these standards and future standards could result in a decreased demand for coal.
We may become liable under federal and state mining statutes if our lessees are unable to pay mining reclamation costs.
      The Surface Mining Control and Reclamation Act of 1977, or SMCRA, and state statutes adopted pursuant to SMCRA impose various permitting and operational requirements on mine operators. In addition, SMCRA assigns to operators the responsibility of restoring the land to its approximate original contour or compensating the surface owner for types of damages occurring as a result of mining operations, and requires mine operators to post performance bonds to ensure compliance with any reclamation obligations. Regulatory authorities may attempt either to assign the liabilities of our lessees to us if any of our lessees are not financially capable of fulfilling those obligations or to render us and our lessees ineligible for future mining permits until those obligations are fulfilled.
The increasing cost and lack of availability of reclamation bonds that are purchased by our lessees could make it uneconomic or impossible to mine our coal.
      In order to satisfy obligations imposed by SMCRA and state statutes, each of our lessees is required to post a reclamation bond at the time its permit to mine coal is issued. The purpose of the bond is to ensure that all reclamation work will be completed on the mine site and the amount of the bond is determined by the regulatory authority issuing the permit. Due to conditions in the insurance industry following September 11, 2001, the number of companies issuing reclamation bonds has declined substantially. As a result, the cost of these bonds has increased and in some instances the bonds are not available to mining companies. If the cost of these bonds were to increase to a level that resulted in our coal becoming uneconomic to mine, our coal royalty revenues could decline substantially.
Restructuring of the electric utility industry could lead to reduced coal prices.
      A number of states and the District of Columbia have passed legislation to allow retail price competition in the electric utility industry. If ultimately implemented at both the state and federal levels,

9


Table of Contents

restructuring of the electric utility industry is expected to compel electric utilities to be more aggressive in developing and defending market share, to be more focused on their pricing and cost structures and to be more flexible in reacting to changes in the market. We believe that a fully competitive electricity market may put downward pressure on fuel prices, including coal, because electric utilities will be competing with other suppliers and will no longer necessarily be able to pass increased fuel costs on to their customers. In addition, some of these initiatives may or do mandate the increased use of alternative or renewable fuels as alternatives to burning fossil fuels. Lower coal prices or mandatory use of alternative fuels could reduce our lessees’ coal production and our coal royalty revenues.
A new lawsuit challenging the legality of an important mining permit could adversely affect our lessees’ ability to produce coal from our reserves.
      The surface mining of coal requires a permit under Section 404 of the Clean Water Act for the disposal into fills of the overburden created by the mining process. In March 2002, the Army Corps of Engineers issued Nationwide Permit 21 under Section 404 to allow mining companies to discharge into fills without obtaining individual permits under the Clean Water Act. The legality of that permitting scheme has been challenged in a lawsuit filed in October 2003 by the Ohio Valley Environmental Coalition and several other citizens groups. This lawsuit is the latest in a series of lawsuits filed in the United States District Court in 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. Although the first two lawsuits were successful at the district court level, the Fourth Circuit Court of Appeals overturned both decisions.
      The most recent lawsuit alleges that a nationwide permit cannot lawfully be issued under Section 404 for the surface mining of coal and that the Corps of Engineers failed to comply with the requirements of the National Environmental Policy Act in the adoption of Nationwide Permit 21. On July 8, 2004, the district court invalidated the future use of Nationwide Permit 21 in the southern judicial district of West Virginia and enjoined the use of the permit at sites already authorized to use it where certain levels of activities had not already started by that date. As a result, our lessees’ coal mining costs could increase and they could mine less coal, which would adversely affect our coal royalty revenues.
      A similar lawsuit has been filed in the United States District Court for the Eastern District of Kentucky, but the court has not rendered a decision.
We could become liable under federal and state Superfund and waste management statutes.
      The Comprehensive Environmental Response, Compensation and Liability Act, known as CERCLA or “Superfund,” and similar state laws create liabilities for the investigation and remediation of releases and threatened releases of hazardous substances to the environment and damages to natural resources. As landowners, we are potentially subject to liability for these investigation and remediation obligations.
Risks Related to Our Partnership Structure
Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and their affiliates may engage in substantial competition with us.
      We rely on the employees of our general partner’s affiliates, including the Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation, which we refer to collectively as the WPP Group, to conduct our business. Although the WPP Group and its affiliates have agreed in the omnibus agreement to some restrictions on their ability to compete with us in the leasing of coal reserves, these restrictions are subject to numerous exceptions that will enable the WPP Group and its affiliates to engage in substantial competition with us should they choose to do so. The partnership agreement provides that engaging in competitive activities by the WPP Group and its affiliates that are not prohibited by the omnibus agreement will not constitute a breach of their fiduciary duties to us or the unitholders. To the extent that the WPP Group or its affiliates compete with us, our growth prospects may be reduced and our results of operations and financial condition may be

10


Table of Contents

materially adversely affected. Furthermore, the WPP Group and its affiliates may have information regarding our operations and business strategies that may give them an advantage in competing with us that a third-party competitor would not have.
      The exceptions to the noncompete obligations of the WPP Group and its affiliates include the following:
  •  The WPP Group and its affiliates may lease their owned coal reserves within the United States to affiliates. For example, a member of the WPP Group or one of its subsidiaries may acquire new coal reserves and lease them directly to an operating subsidiary and collect royalties on the lease without offering us the opportunity to acquire these reserves.
 
  •  The WPP Group and its affiliates may compete with us as long as the fair market value of the assets of any competing business are $10 million or less; provided, that the total value of all competing businesses do not exceed $75 million. In addition, any coal reserves that are owned and unleased at the time of the closing of the offering that are subsequently leased to third parties will not be considered in calculating the $75 million limitation.
 
  •  In certain circumstances, the WPP Group and its affiliates will be required to offer a competing business to us for purchase, but if they make a good faith decision in their sole discretion not to accept our offer, they will be able to continue to own and operate the business in competition with us. There is no provision in the omnibus agreement requiring the WPP Group or its affiliates to sell the business to us at a fair market value determined by a third party investment banking firm or appraiser.
 
  •  There is no restriction on the ability of the WPP Group and its affiliates to compete with us in the ownership and operation of other businesses, including the leasing of other mineral properties such as oil and gas and iron ore. It is our strategy to diversify into the acquisition of mineral properties in addition to coal properties.
 
  •  There is no restriction on the ability of the WPP Group and its affiliates to own a noncontrolling equity interest in a competing business, including an economic stake that is greater than their stake in us.
      If the WPP Group or its affiliates ceases to participate in the control of our general partner, then the relevant entity it will no longer be bound by the noncompetition provisions of the omnibus agreement.
      In addition, First Reserve Fund IX, L.P., First Reserve GP IX, Inc., First Reserve Corporation and their affiliates, which are affiliates of the selling unitholder, which owns approximately 42% of our subordinated units and which we refer to collectively as First Reserve, may compete with us without any limitations.
The WPP Group, NRP Investment L.P., First Reserve and their affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit them to favor their own interests to your detriment.
      The WPP Group and its affiliates own approximately 40% of our common and subordinated units and together own and control our general partner. In addition, the selling unitholder, which is an affiliate of First Reserve, owns approximately 42% of our subordinated units and has the right to elect two directors to the board of our general partner. Conflicts of interest may arise between the WPP Group, First Reserve and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of the unitholders. These conflicts include, among others, the following situations:
  •  Some officers of the WPP Group, who will provide services to us, will also devote significant time to the businesses of the WPP Group and will be compensated by the WPP Group for the services they provide.

11


Table of Contents

  •  Neither the partnership agreement nor any other agreement requires the WPP Group and its affiliates or First Reserve to pursue a business strategy that favors us. The directors and officers of the WPP Group and its affiliates have a fiduciary duty to make decisions in the best interests of their limited partners and shareholders, and the directors of First Reserve and its affiliates have a fiduciary duty to make decisions in the best interests of their shareholders and partners.
 
  •  As described above, the WPP Group, First Reserve and their affiliates may engage in substantial competition with us.
 
  •  Our general partner is allowed to take into account the interests of parties other than us, such as the WPP Group, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to the unitholders.
 
  •  Our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. As a result of purchasing units, you are deemed to consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.
 
  •  Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional limited partner interests and reserves, each of which can affect the amount of cash that is distributed to unitholders.
 
  •  Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.
 
  •  Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.
 
  •  Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates.
 
  •  Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
  •  In some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to hasten the expiration of the subordination period.
Even if unitholders are dissatisfied, they cannot easily remove our general partner.
      Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Neither our general partner nor the board of directors of GP Natural Resource Partners LLC were elected by the unitholders, and neither the common unitholders nor the subordinated unitholders will have the right to elect our general partner or the board of directors of GP Natural Resource Partners LLC on an annual or other continuing basis.
      The eight-member board of directors of our general partner is elected by Robertson Coal Management LLC, which is wholly owned by Corbin J. Robertson, Jr., our chief executive officer and chairman and an affiliate of the WPP Group and NRP Investment L.P. The selling unitholder, which is indirectly controlled by First Reserve, has the right to designate two members of the board. The selling unitholder will lose its right to designate directors when it owns less than 5% of our issued and outstanding units, including both common and subordinated units, and less than 20% of its current holdings, which consist of 4,796,920 subordinated units. Although our general partner has a fiduciary duty to manage our business in a manner beneficial to us and the unitholders, the directors of our general partner have a

12


Table of Contents

fiduciary duty to manage the general partner in a manner beneficial to its sole member, Robertson Coal Management LLC.
      Furthermore, if subordinated unitholders or common unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. First, our general partner generally may not be removed except upon the vote of the holders of at least 662/3% of the outstanding units voting together as a single class. Because affiliates of the general partner control approximately 40% of all the outstanding units, the general partner currently cannot be removed without the consent of the general partner and its affiliates. Also, if our general partner is removed without cause during the subordination period and units held by the general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.
      Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholders’ dissatisfaction with the general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.
      Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. In addition, the partnership agreement contains provisions limiting the ability of subordinated unitholders and common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence, the manner or direction of management.
      As a result of these provisions, the price at which our common units and our subordinated units will trade may be lower because of the absence or reduction of a takeover premium in the takeover price.
The control of our general partner may be transferred to a third party without the consent of our subordinated unitholders or common unitholders.
      Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owners of our general partner or its general partner, GP Natural Resource Partners LLC, from transferring their ownership interest in the general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers.
Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to subordinated unitholders and common unitholders.
      Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will reduce the amount of cash available for distribution to subordinated unitholders and common unitholders.

13


Table of Contents

We may issue additional subordinated units and common units without your approval, which would dilute your existing ownership interests.
      During the subordination period our general partner may cause us to issue an unlimited number of subordinated units and up to 5,676,829 additional common units without your approval. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without your approval, in a number of circumstances, such as:
  •  the issuance of common units in connection with acquisitions or capital improvements that our general partner determines would increase cash flow from operations per unit on a pro forma basis;
 
  •  the conversion of subordinated units into common units;
 
  •  the conversion of units of equal rank with the common units into common units under some circumstances;
 
  •  the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal of our general partner;
 
  •  the issuance of common units under our incentive plans; or
 
  •  issuances of common units to repay up to $25 million of certain indebtedness.
      After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of the unitholders. Our partnership agreement does not give the subordinated unitholders or the common unitholders the right to approve our issuance at any time of additional subordinated units or any other equity securities ranking junior to the common units.
      The issuance of additional subordinated units, additional common units or other equity securities of equal or senior rank will have the following effects upon the subordinated unitholders:
  •  your proportionate ownership interest in us will decrease;
 
  •  the amount of cash available for distribution on each unit may decrease;
 
  •  the risk that subordinated unitholders will bear a shortfall in the payment of the minimum quarterly distribution will increase;
 
  •  the relative voting strength of each previously outstanding unit may be diminished; and
 
  •  the market price of the subordinated units may decline.
      The issuance of additional common units or other equity securities of equal or senior rank will have the following effects upon the common unitholders:
  •  your proportionate ownership interest in us will decrease;
 
  •  the amount of cash available for distribution on each unit may decrease;
 
  •  because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by the common unitholders will increase;
 
  •  the relative voting strength of each previously outstanding unit may be diminished; and
 
  •  the market price of the common units may decline.
Cost reimbursements due our general partner may be substantial and will reduce the cash available for distribution to you.
      Prior to making any distribution on the subordinated units or the common units, we will reimburse our general partner and its affiliates, including its officers and directors, for all expenses they incur on our

14


Table of Contents

behalf. The reimbursement of expenses could adversely affect our ability to pay cash distributions to you. Our general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us with other services for which we will be charged fees as determined by our general partner.
Our general partner has a limited call right that may require you to sell your subordinated units or common units at an undesirable time or price.
      If, at any time, our general partner and its affiliates own more than 80% of either the subordinated units or the common units then outstanding, our general partner has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining subordinated units or the common units, as the case may be, at a price not less than the then-current market price of such units. As a result, you may be required to sell your subordinated units or common units at an undesirable time or price and may therefore not receive any return on your investment. You may also incur tax liability upon a sale of your subordinated units or common units.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
      A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. While our partnership is organized under Delaware law, we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for our obligations as if you were a general partner if:
  •  a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
  •  a court determines that your right to act with other subordinated unitholders or common unitholders to remove or replace the general partner, to approve some amendment to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
      In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
Tax Risks to Unitholders
      You should read “Material Tax Consequences” for a full discussion of the expected material federal income tax consequences of owning and disposing of units.
The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to you.
      The after-tax economic benefit of an investment in the units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
      If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you may be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. If we were treated as a corporation, there would be a material reduction in the after-tax return to the unitholders, likely causing a substantial reduction in the value of our units.

15


Table of Contents

      Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our units, and the cost of any IRS contest will be borne by our unitholders and our general partner.
      We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner, and these costs will reduce our cash available for distribution.
You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.
      You will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even the tax liability that results from that income.
Tax gain or loss on disposition of units could be different than expected.
      If you sell your units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those units. Prior distributions to you in excess of the total net taxable income you were allocated for a unit, which decreased your tax basis in that unit, will, in effect, become taxable income to you if the unit is sold at a price greater than your tax basis in that unit, even if the price is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.
      Investment in units by tax-exempt entities, such as individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds) and non-U.S. persons raises issues unique to them. For example, a significant amount of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, may be unrelated business taxable income and will be taxable to such a unitholder. Recent legislation treats net income derived from the ownership of certain publicly traded partnerships (including us) as qualifying income to a regulated investment company. However, this legislation is only effective for taxable years beginning after October 22, 2004, the date of enactment. For taxable years beginning on or before the date of enactment, very little of our income will be qualifying income to a regulated investment company. Distributions to non-U.S. persons will be reduced by withholding tax at the highest effective tax rate applicable to

16


Table of Contents

individuals, and non-U.S. unitholders will be required to file federal income tax returns and pay tax on their share of our taxable income.
We will treat each purchaser of units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.
      Because we cannot match transferors and transferees of units, we adopt depreciation and amortization positions that may not conform with all aspects of applicable Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of units and could have a negative impact on the value of the units or result in audit adjustments to the unitholder’s tax returns.
You will likely be subject to state and local taxes in states where you do not live as a result of an investment in units.
      In addition to federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if you do not live in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We own assets and do business in Alabama, Georgia, Illinois, Indiana, Kentucky, Maryland, Montana, North Carolina, North Dakota, Tennessee, Virginia and West Virginia. Each of these states currently imposes a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the units.

17


Table of Contents

USE OF PROCEEDS
      Unless otherwise provided in a prospectus supplement, we will not receive any proceeds from the sale of units by the selling unitholder.
DESCRIPTION OF OUR UNITS
Status as Limited Partner or Assignee
      Except as described under “— Limited Liability,” the subordinated units and the common units will be fully paid, and the unitholders will not be required to make additional capital contributions to us.
Transfer of Subordinated Units and Common Units
      Each purchaser of subordinated units and common units offered by this prospectus must execute a transfer application. By executing and delivering a transfer application, the purchaser of subordinated units or common units:
  •  becomes the record holder of the subordinated units or the common units and is an assignee until admitted into our partnership as a substituted limited partner;
 
  •  automatically requests admission as a substituted limited partner in our partnership;
 
  •  agrees to be bound by the terms and conditions of, and executes, our partnership agreement;
 
  •  represents that he has the capacity, power and authority to enter into the partnership agreement;
 
  •  grants powers of attorney to officers of the general partner and any liquidator of our partnership as specified in the partnership agreement; and
 
  •  makes the consents and waivers contained in the partnership agreement.
      An assignee will become a substituted limited partner of our partnership for the transferred units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.
      Transfer applications may be completed, executed and delivered by a purchaser’s broker, agent or nominee. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders’ rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
      Subordinated units and common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired, the purchaser has the right to request admission as a substituted limited partner in our partnership for the purchased subordinated units or common units. A purchaser of subordinated units or common units who does not execute and deliver a transfer application obtains only:
  •  the right to assign the subordinated unit or common unit to a purchaser or transferee; and
 
  •  the right to transfer the right to seek admission as a substituted limited partner in our partnership for the purchased subordinated units or common units.
      Thus, a purchaser of subordinated units or common units who does not execute and deliver a transfer application:
  •  will not receive cash distributions or federal income tax allocations, unless the subordinated units or common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application; and

18


Table of Contents

  •  may not receive some federal income tax information or reports furnished to record holders of subordinated units and common units.
      Until a subordinated unit or common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.
Limited Liability
      Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his subordinated units or common units plus his share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by the limited partners as a group:
  •  to remove or replace the general partner;
 
  •  to approve some amendments to our partnership agreement; or
 
  •  to take other action under our partnership agreement
constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under Delaware law, to the same extent as the general partner. This liability would extend to persons who transact business with us and who reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we have found no precedent for this type of a claim in Delaware case law.
      Under the Delaware Act, a limited partnership may not make a distribution to a partner if after the distribution all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of our partnership, exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to our partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and which could not be ascertained from our partnership agreement.
      Our subsidiaries currently conduct business in twelve states: Alabama, Georgia, Illinois, Indiana, Kentucky, Maryland, Montana, North Carolina, North Dakota, Tennessee, Virginia and West Virginia. Maintenance of limited liability for Natural Resource Partners as the sole member of the operating company, may require compliance with legal requirements in the jurisdictions in which the operating company conducts business, including qualifying our subsidiaries to do business there. Limitations on the liability of members for the obligations of a limited liability company have not been clearly established in many jurisdictions. If it were determined that we were, by virtue of our member interest in the operating company or otherwise, conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited

19


Table of Contents

partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner as our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.
Meetings; Voting
      Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Subordinated units and common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, shall be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the subordinated units and common units will not be voted, except that, in the case of subordinated units or common units held by our general partner on behalf of non-citizen assignees, our general partner shall distribute the votes on those subordinated units and common units in the same ratios as the votes of limited partners on other units are cast.
      Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy shall constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum shall be the greater percentage.
      Each record holder of a unit has a vote according to his percentage interest in our partnership, although additional limited partner interests having special voting rights could be issued. However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates or a person or group who acquires the units with the prior approval of the board of directors, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, the person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Subordinated units and common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as otherwise provided in the partnership agreement, subordinated units will vote together with common units as a single class.
      Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of subordinated units or common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.
Matters Requiring Approval of Subordinated and Common Units
      During the subordination period, our partnership agreement requires us to secure the approval of a majority of the outstanding subordinated units, voting as a class, and the majority of the outstanding common units, excluding common units held by our general partner and its affiliates, voting as a class, in order to approve certain actions. These actions include:
  •  the issuance of more than 5,676,829 additional common units during the subordination period other than in certain situations, including in connection with accretive acquisitions and construction projects, unit splits, and the conversion of the subordinated units;

20


Table of Contents

  •  the issuance of any additional securities that are (a) entitled to receive cash distributions before the common units have received the minimum quarterly distribution and any arrearages or (b) allocated net termination gain before the common units;
 
  •  the merger of the partnership or the sale by the general partner of all or substantially all of our assets or our subsidiaries’ assets;
 
  •  any amendment to the operating agreement of our operating company, NRP (Operating) LLC, or any action taken by NRP (Operating) LLC, if such amendment or action would materially adversely affect the limited partners or any class thereof;
 
  •  the election of a successor general partner if our partner withdraws from the partnership;
 
  •  in certain circumstances, dissolving or reconstituting the partnership; and
 
  •  certain amendments to the partnership agreement;
After the subordination period is over, the taking of any of these actions requires approval of the majority of the outstanding common units.
      In addition, the approval of at least 662/3% of the outstanding subordinated units and common units, including units held by our general partner and its affiliates, voting as a single class, is required to remove the general partner at any time.
Books and Reports
      Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.
      We will furnish or make available to record holders of subordinated units common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.
      We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.
      Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:
  •  a current list of the name and last known address of each partner;
 
  •  a copy of our tax returns;
 
  •  information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;
 
  •  copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments and powers of attorney under which they have been executed;
 
  •  information regarding the status of our business and financial condition; and
 
  •  any other information regarding our affairs as is just and reasonable.

21


Table of Contents

      Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or which we are required by law or by agreements with third parties to keep confidential.
Summary of Partnership Agreement
      A summary of the important provisions of our partnership agreement, many of which apply to holders of subordinated units and common units, is included in reports filed with the SEC and incorporated by reference in this prospectus.
Matters Applicable Only to Subordinated Units
      The subordinated units are a separate class of limited partner interests in our partnership, and the rights of holders of subordinated units to participate in distributions to partners differ from, and are subordinated to, the rights of the holders of common units. For any given quarter, any available cash will first be distributed to our general partner and to the holders of common units, until the holders of common units have received the minimum quarterly distribution plus any arrearages, and then, to the extent there is available cash remaining, will be distributed to the holders of subordinated units. Please read “Cash Distribution Policy.”
      We have applied for listing of the subordinated units on the New York Stock Exchange.
      The transfer agent and registrar for our subordinated units is American Stock Transfer and Trust Company.
Conversion of Subordinated Units
      The subordination period generally extends until the first day of any quarter beginning after September 30, 2007 in which each of the following events occur:
  •  distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
 
  •  the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
 
  •  there are no arrearages in payment of the minimum quarterly distribution on the common units.
      Before the end of the subordination period, 25% of the subordinated units will convert early into common units on a one-for-one basis immediately after the distribution of available cash to the partners in respect of any quarter ending on or after September 30, 2005 and 25% of the subordinated units will convert early into common units on a one-for-one basis immediately after the distribution of available cash to the partners in respect of any quarter ending on or after September 30, 2006 if at the end of the applicable quarter each of the following three events occurs:
  •  distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
 
  •  the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
 
  •  there are no arrearages in payment of the minimum quarterly distribution on the common units.
provided, however, that the early conversion of the second 25% of the subordinated units may not occur until at least one year following the early conversion of the first 25% of the subordinated units.

22


Table of Contents

      Upon expiration of the subordination period, all remaining subordinated units will convert into common units on a one-for-one basis and will then participate, pro rata, with the other common units in distributions of available cash. In addition, if NRP (GP) LP is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:
  •  the subordination period will end and each outstanding subordinated unit will immediately convert into one common unit;
 
  •  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
  •  our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.
Limited Voting Rights
      Holders of subordinated units will sometimes vote as a single class together with the holders of common units and sometimes vote as a class separate from the holders of common units and, as in the case of holders of common units, will have very limited voting rights. During the subordination period, common units and subordinated units each vote separately as a class on the following matters:
  •  a sale or exchange of all or substantially all of our assets;
 
  •  the election of a successor general partner in connection with the removal of our general partner;
 
  •  a dissolution or reconstitution of our partnership;
 
  •  a merger of our partnership;
 
  •  issuance of limited partner interests in some circumstances; and
 
  •  some amendments to the partnership agreement, including any amendment that would cause us to be treated as an association taxable as a corporation.
      The subordinated units are not entitled to vote on approval of the withdrawal of our general partner or the transfer by our general partner of its general partner interest or incentive distribution rights under some circumstances. Removal of our general partner requires:
  •  the affirmative vote of 662/3% of all outstanding units voting as a single class; and
 
  •  the election of a successor general partner by the holders of a majority of the outstanding common units and subordinated units, voting as separate classes.
      Under the partnership agreement, our general partner generally will be permitted to effect amendments to the partnership agreement that do not materially and adversely affect unitholders without the approval of any unitholders.
Distributions upon Liquidation
      If we liquidate during the subordination period, in some circumstances holders of outstanding common units will be entitled to receive more per unit in liquidating distributions than holders of outstanding subordinated units. The per-unit difference will be dependent upon the amount of gain or loss recognized by us in liquidating our assets. Following conversion of the subordinated units into common units, all units will be treated the same upon liquidation of our partnership.
Matters Applicable Only to Common Units
      The common units represent limited partner interests in Natural Resource Partners that entitle the holders to participate in our cash distributions and to exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of

23


Table of Contents

holders of common units, holders of subordinated units, and our general partner in and to partnership distributions, together with a description of the circumstances under which subordinated units convert into common units, read “Cash Distributions” in this prospectus.
      Our outstanding common units are listed on the New York Stock Exchange under the symbol “NRP.”
      The transfer agent and registrar for our common units is American Stock Transfer & Trust Company.
Matters Requiring Approval of Common Units
      Certain actions to be taken by our general partner must be approved by the holders of the common units, excluding the common units held by our general partner and its affiliates. These actions include:
  •  the withdrawal of the general partner prior to September 30, 2012;
 
  •  the general partner’s transfer of its general partner interest in us to a third party prior to September 30, 2012, except in specific circumstances relating to the general partner’s merger, consolidation, or the sale of substantially all its assets; and
 
  •  the transfer of the incentive distribution rights to a third party prior to September 30, 2012.

24


Table of Contents

CASH DISTRIBUTIONS
Distributions of Available Cash
      General. Within approximately 45 days after the end of each quarter, we will distribute all available cash to unitholders of record on the applicable record date.
      Definition of Available Cash. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:
  •  less the amount of cash reserves that the general partner determines in its reasonable discretion is necessary or appropriate to:
  •  provide for the proper conduct of our business;
 
  •  comply with applicable law, any of our debt instruments, or other agreements; or
 
  •  provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;
 
  •  plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
      Intent to Distribute the Minimum Quarterly Distribution. We intend to distribute to holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.5125 per quarter, or $2.05 per year, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of fees and expenses, including reimbursements to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our credit facility.
Operating Surplus and Capital Surplus
      General. All cash distributed to unitholders will be characterized either as operating surplus or capital surplus. We distribute available cash from operating surplus differently than available cash from capital surplus.
      Maintenance capital expenditures are capital expenditures made to maintain, over the long term, the operating capacity of our assets as they existed at the time of the expenditure. Expansion capital expenditures are capital expenditures made to increase over the long term the operating capacity of our assets as they existed at the time of the expenditure. The general partner has the discretion to determine how to allocate a capital expenditure for the acquisition or expansion of coal reserves between maintenance capital expenditures and expansion capital expenditures, and its good faith allocation will be conclusive. Maintenance capital expenditures reduce operating surplus, from which we pay the minimum quarterly distribution, but expansion capital expenditures do not.
      Definition of Operating Surplus. For any period, operating surplus generally means:
  •  our cash balance on the closing date of our initial public offering; plus
 
  •  $15.0 million (as described below); plus
 
  •  all of our cash receipts since the closing of our initial public offering, excluding cash from borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus
 
  •  working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for that quarter; less

25


Table of Contents

  •  all of our operating expenses since the closing of our initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less
 
  •  the amount of cash reserves that the general partner deems necessary or advisable to provide funds for future operating expenditures.
      Definition of Capital Surplus. Capital surplus will generally be generated only by:
  •  borrowings other than working capital borrowings;
 
  •  sales of debt and equity securities; or
 
  •  sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.
      Characterization of Cash Distributions. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus. As reflected above, operating surplus includes $15.0 million in addition to our cash balance on the closing date of our initial public offering, cash receipts from our operations and cash from working capital borrowings. This amount does not reflect actual cash on hand at closing that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to $15 million of cash we receive in the future from non-operating sources, such as assets sales, issuances of securities and long-term borrowings, which would otherwise be considered distributions of capital surplus. Any distributions of capital surplus would trigger certain adjustment provisions in our partnership agreement as described below. Please read “— Distributions From Capital Surplus” and “— Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.”
Subordination Period
      General. During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.5125 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.
      Definition of Subordination Period. The subordination period will generally extend until the first day of any quarter beginning after September 30, 2007 that each of the following tests are met:
  •  distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
 
  •  the adjusted operating surplus generated during each of the three immediately preceding non-overlapping four-quarter periods equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
 
  •  there are no arrearages in payment of the minimum quarterly distribution on the common units.
      Early Conversion of Subordinated Units. Before the end of the subordination period, 50% of the subordinated units, or up to 5,676,829 subordinated units, may convert into common units on a one-for-one

26


Table of Contents

basis immediately after the distribution of available cash to partners in respect of any quarter ending on or after:
  •  September 30, 2005 with respect to 25% of the subordinated units; and
 
  •  September 30, 2006 with respect to 25% of the subordinated units.
      The early conversions will occur if at the end of the applicable quarter each of the following three tests are met:
  •  distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
 
  •  the adjusted operating surplus generated during each of the three immediately preceding, non-overlapping four-quarter periods equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
 
  •  there are no arrearages in payment of the minimum quarterly distribution on the common units.
      However, the early conversion of the second 25% of the subordinated units may not occur until at least one year following the early conversion of the first 25% of the subordinated units.
      Definition of Adjusted Operating Surplus. Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.
      Adjusted operating surplus for any period generally means:
  •  operating surplus generated with respect to that period; less
 
  •  any net increase in working capital borrowings with respect to that period; less
 
  •  any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus
 
  •  any net decrease in working capital borrowings with respect to that period; plus
 
  •  any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.
      Effect of Expiration of the Subordination Period. Upon expiration of the subordination period, all remaining subordinated units will convert into common units on a one-for-one basis and will then participate, pro rata, with the other common units in distributions of available cash. In addition, if the unitholders remove the general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of this removal:
  •  the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
 
  •  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
  •  the general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

27


Table of Contents

Distributions of Available Cash from Operating Surplus During the Subordination Period
      Natural Resource Partners will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:
  •  First, 98% to the common unitholders, pro rata, and 2% to the general partner until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
 
  •  Second, 98% to the common unitholders, pro rata, and 2% to the general partner until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
 
  •  Third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
 
  •  Thereafter, in the manner described in “— Incentive Distribution Rights” below.
Distributions of Available Cash from Operating Surplus After the Subordination Period
      Natural Resource Partners will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:
  •  First, 98% to all unitholders, pro rata, and 2% to the general partner until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
 
  •  Thereafter, in the manner described in “— Incentive Distribution Rights” below.
Incentive Distribution Rights
      Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner and members and affiliates of the WPP Group currently hold 65% and 35%, respectively, of the incentive distribution rights. The WPP Group and its affiliates may transfer these rights, but our general partner may only transfer these rights separately from its general partner interest in accordance with restrictions in the partnership agreement.
      If for any quarter:
  •  we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
 
  •  we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;
then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:
  •  First, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.5625 per unit for that quarter (the “first target distribution”);
 
  •  Second, 85% to all unitholders, pro rata, 13% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.6625 per unit for that quarter (the “second target distribution”);
 
  •  Third, 75% to all unitholders, pro rata, 23% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.7625 per unit for that quarter (the “third target distribution”); and

28


Table of Contents

  •  Thereafter, 50% to all unitholders, pro rata, 48% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner.
      In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.
Percentage Allocations of Available Cash from Operating Surplus
      The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
                                 
        Marginal Percentage Interest in Distributions
         
    Total Quarterly Distribution       General   Holders of Incentive
    Target Amount   Unitholders   Partner   Distribution Rights
                 
Minimum Quarterly Distribution
    up to $0.5125       98 %     2 %      
First Target Distribution
   
above $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 %
Distributions from Capital Surplus
      Natural Resource Partners will make distributions of available cash from capital surplus, if any, in the following manner:
  •  First, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in the initial public offering, an amount of available cash from capital surplus equal to the initial public offering price;
 
  •  Second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and
 
  •  Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.
      Effect of a Distribution from Capital Surplus. The partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from the initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the unrecovered initial unit price. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into

29


Table of Contents

common units. Any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.
      Once we distribute capital surplus on a unit in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero and we will make all future distributions from operating surplus, with 50% being paid to the holders of units, and 50% to the general partner.
Adjustment of Minimum Quarterly Distribution and Target Distribution Levels
      In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:
  •  the minimum quarterly distribution;
 
  •  the target distribution levels;
 
  •  the unrecovered initial unit price;
 
  •  the number of additional common units issuable during the subordination period without a unitholder vote; and
 
  •  the number of common units into which a subordinated unit is convertible.
      For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.
      In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates. For example, if we became subject to a maximum marginal federal, and effective state and local income tax rate of 38%, then the minimum quarterly distribution and the target distributions levels would each be reduced to 62% of their previous levels.
Distributions of Cash Upon Liquidation
      If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
      The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon the liquidation of Natural Resource Partners to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon liquidation of Natural Resource Partners to enable the holder of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

30


Table of Contents

      Manner of Adjustment for Gain. The manner of the adjustment is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:
  •  First, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;
 
  •  Second, 98% to the common unitholders, pro rata, and 2% to the general partner, until the capital account for each common unit is equal to the sum of:
        (1) the unrecovered initial unit price; plus
 
        (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; plus
 
        (3) any unpaid arrearages in payment of the minimum quarterly distribution;
  •  Third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until the capital account for each subordinated unit is equal to the sum of:
        (1) the unrecovered initial unit price on that subordinated unit; and
 
        (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;
  •  Fourth, 98% to all unitholders, pro rata, and 2% to the general partner, pro rata, until we allocate under this paragraph an amount per unit equal to:
        (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less
 
        (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that was distributed 98% to the units, pro rata, and 2% to the general partner, pro rata, for each quarter of our existence;
  •  Fifth, 85% to all unitholders, pro rata, 13% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to:
        (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less
 
        (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that was distributed 85% to the unitholders, pro rata, 13% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner for each quarter of our existence;
  •  Sixth, 75% to all unitholders, pro rata, and 23% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to:
        (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less
 
        (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that was distributed 75% to the unitholders, pro rata, 23% to the holders of the incentive distribution rights, pro rata and 2% to the general partner for each quarter of our existence;
  •  Thereafter, 50% to all unitholders, pro rata, 48% to the holders of the incentive distribution rights, pro rata and 2% to the general partner.

31


Table of Contents

      If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.
      Manner of Adjustment for Losses. Upon our liquidation, we will generally allocate any loss to the general partner and the unitholders in the following manner:
  •  First, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to the general partner until the capital accounts of the holders of the subordinated units have been reduced to zero;
 
  •  Second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the general partner until the capital accounts of the common unitholders have been reduced to zero; and
 
  •  Thereafter, 100% to the general partner.
      If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.
      Adjustments to Capital Accounts Upon the Issuance of Additional Units. We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive interim adjustments to the capital accounts, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or distributions of property or upon liquidation in a manner which results, to the extent possible, in the capital account balance of the general partner equaling the amount which would have been in its capital account if no earlier positive adjustments to the capital accounts had been made.

32


Table of Contents

MATERIAL TAX CONSEQUENCES
      This section is a summary of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to the general partner and us, insofar as it relates to United States federal income tax matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Natural Resource Partners and its direct subsidiary, NRP (Operating) LLC.
      This section does not comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we recommend that each prospective unitholder consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of the units.
      All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us and our general partner.
      No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions and advice of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the units and the prices at which units trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by the unitholders and the general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
      For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues:
  •  the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”);
 
  •  whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury regulations (please read “— Disposition of Units — Allocations Between Transferors and Transferees”); and
 
  •  whether our method for depreciating Section 743 adjustments is sustainable (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).
Partnership Status
      A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.
      Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income

33


Table of Contents

Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the marketing of coal. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 1% of our current income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and the general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.
      No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of the operating company for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, Natural Resource Partners will be classified as a partnership and the operating company will be disregarded as an entity separate from Natural Resource Partners for federal income tax purposes.
      In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and the general partner. The representations made by us and our general partner upon which counsel has relied are:
  •  Neither Natural Resource Partners nor the operating company has elected or will elect to be treated as a corporation; and
 
  •  For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.
      If we fail to meet the Qualifying Income Exception, other than a failure which is determined by the IRS to be inadvertent and which is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
      If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his units, or taxable capital gain, after the unitholder’s tax basis in his units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.
      The remainder of this section is based on Vinson & Elkins L.L.P.’s opinion that Natural Resource Partners will be classified as a partnership for federal income tax purposes.

34


Table of Contents

Limited Partner Status
      Unitholders who have become limited partners of Natural Resource Partners will be treated as partners of Natural Resource Partners for federal income tax purposes. Also:
  •  assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and
 
  •  unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their units will be treated as partners of Natural Resource Partners for federal income tax purposes.
      As there is no direct authority addressing assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Vinson & Elkins L.L.P. does not extend to these persons. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units.
      A beneficial owner of units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”
      Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in Natural Resource Partners for federal income tax purposes.
Tax Consequences of Unit Ownership
      Flow-through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.
      Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the units, taxable in accordance with the rules described under “— Disposition of Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”
      A decrease in a unitholder’s percentage interest in us because of our issuance of additional units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This

35


Table of Contents

latter deemed exchange will generally result in the unitholder’s realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange
      Basis of Units. A unitholder’s initial tax basis for his units is the amount he paid for the units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt which is recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Units — Recognition of Gain or Loss.”
      Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of its stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.
      In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.
      The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly-traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.
      A unitholder’s share of our net income may be offset by any suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly-traded partnerships.
      Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:
  •  interest on indebtedness properly allocable to property held for investment;
 
  •  our interest expense attributed to portfolio income; and

36


Table of Contents

  •  the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
      The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly-traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.
      Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.
      Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to the general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.
      Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of an offering, referred to in this discussion as “Contributed Property.” The effect of these allocations to a unitholder purchasing units in an offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.
      Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Disposition of Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.
      Treatment of Short Sales. A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
  •  any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

37


Table of Contents

  •  any cash distributions received by the unitholder as to those units would be fully taxable; and
 
  •  all of these distributions would appear to be ordinary income.
      Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where units are loaned to a short seller to cover a short sale of units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Units — Recognition of Gain or Loss.”
      Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.
      Tax Rates. In general, the highest effective United States federal income tax rate for individuals currently is 35% and the maximum United States federal income tax rate for net capital gains of an individual currently is 15% if the asset disposed of was held for more than 12 months at the time of disposition.
      Section 754 Election. We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“unit basis”) and (2) his Section 743(b) adjustment to that basis.
      Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we have adopted), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-l(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, the general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury regulations. Please read “— Tax Treatment of Operations — Uniformity of Units.”
      Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the unit basis of the property, or treat that portion as non-amortizable to the extent attributable to property the unit basis of which is not amortizable. This method is consistent with the regulations under Section 743 but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to unit basis or a Section 743(b) adjustment,

38


Table of Contents

based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Tax Treatment of Operations — Uniformity of Units.”
      A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election.
      The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.
Tax Treatment of Operations
      Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Units — Allocations Between Transferors and Transferees.”
      Initial Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by the general partner, its affiliates and our other unitholders as of that time. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”
      To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We are not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.
      If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his

39


Table of Contents

interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Units — Recognition of Gain or Loss.”
      The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.
      Coal Income. Section 631 of the Internal Revenue Code provides special rules by which gains or losses on the sale of coal may be treated, in whole or in part, as gains or losses from the sale of property used in a trade or business under Section 1231 of the Internal Revenue Code. Specifically, Section 631(c) provides that if the owner of coal held for more than one year disposes of that coal under a contract by virtue of which the owner retains an economic interest in the coal, the gain or loss realized will be treated under Section 1231 of the Internal Revenue Code as gain or loss from property used in a trade or business. Section 1231 gains and losses may be treated as capital gains and losses. Please read “— Sales of Coal Reserves.” In computing gain or loss, the amount realized is reduced by the adjusted depletion basis in the coal, determined as described in “— Coal Depletion.” For purposes of Section 631(c), the coal generally is deemed to be disposed of on the day on which the coal is mined. Further, Treasury regulations promulgated under Section 631 provide that advance royalty payments may also be treated as proceeds from sales of coal to which Section 631 applies and, therefore, such payment may be treated as capital gain under Section 1231. However, if the right to mine the related coal expires or terminates under the contract that provides for the payment of advance royalty payments or such right is abandoned before the coal has been mined, we may, pursuant to the Treasury regulations, file an amended return that reflects the payments attributable to unmined coal as ordinary income and not as received from the sale of coal under Section 631.
      Our royalties from coal leases generally will be treated as proceeds from sales of coal to which Section 631 applies. Accordingly, the difference between the royalties paid to us by the lessees and the adjusted depletion basis in the extracted coal generally will be treated as gain from the sale of property used in a trade or business, which may be treated as capital gain under Section 1231. Please read “— Sales of Coal Reserves.” Our royalties that do not qualify under Section 631(c) generally will be taxable as ordinary income in the year of sale.
      Coal Depletion. In general, we are entitled to depletion deductions with respect to coal mined from the underlying mineral property. We generally are entitled to the greater of cost depletion limited to the basis of the property or percentage depletion. The percentage depletion rate for coal is 10%. If Section 631(c) applies to the disposition of the coal, however, we are not eligible for percentage depletion. Please read “— Coal Income.”
      Depletion deductions we claim generally will reduce the tax basis of the underlying mineral property. Depletion deductions can, however, exceed the total tax basis of the mineral property. The excess of our percentage depletion deductions over the adjusted tax basis of the property at the end of the taxable year is subject to tax preference treatment in computing the alternative minimum tax. Please read “— Tax Consequences of Unit Ownership — Alternative Minimum Tax.” In addition, a corporate unitholder’s allocable share of the amount allowable as a percentage depletion deduction for any property will be reduced by 20% of the excess, if any, of that partner’s allocable share of the amount of the percentage depletion deductions for the taxable year over the adjusted tax basis of the mineral property as of the close of the taxable year.
      Sales of Coal Reserves. If any coal reserves are sold or otherwise disposed of in a taxable transaction, we will recognize gain or loss measured by the difference between the amount realized (including the amount of any indebtedness assumed by the purchaser upon such disposition or to which such property is subject) and the adjusted tax basis of the property sold. Generally, the character of any

40


Table of Contents

gain or loss recognized upon that disposition will depend upon whether our coal reserves sold are held by us:
  •  for sale to customers in the ordinary course of business (i.e., we are a “dealer” with respect to that property),
 
  •  for use in a trade or business within the meaning of Section 1231 of the Internal Revenue Code or
 
  •  as a capital asset within the meaning of Section 1221 of the Internal Revenue Code.
      In determining dealer status with respect to coal reserves and other types of real estate, the courts have identified a number of factors for distinguishing between a particular property held for sale in the ordinary course of business and one held for investment. Any determination must be based on all the facts and circumstances surrounding the particular property and sale in question.
      We intend to hold our coal reserves for the purposes of generating cash flow from coal royalties and achieving long-term capital appreciation. Although our general partner may consider strategic sales of coal reserves consistent with achieving long-term capital appreciation, our general partner does not anticipate frequent sales, nor significant marketing, improvement or subdivision activity in connection with any strategic sales. In light of the factual nature of this question, however, there is no assurance that our purposes for holding our properties will not change and that our future activities will not cause us to be a “dealer” in coal reserves.
      If we are not a dealer with respect to our coal reserves and we have held the disposed property for more than a one-year period primarily for use in our trade or business, the character of any gain or loss realized from a disposition of the property will be determined under Section 1231 of the Internal Revenue Code. If we have not held the property for more than one year at the time of the sale, gain or loss from the sale will be taxable as ordinary income.
      A unitholder’s distributive share of any Section 1231 gain or loss generated by us will be aggregated with any other gains and losses realized by that unitholder from the disposition of property used in the trade or business, as defined in Section 1231(b) of the Internal Revenue Code, and from the involuntary conversion of such properties and of capital assets held in connection with a trade or business or a transaction entered into for profit for the requisite holding period. If a net gain results, all such gains and losses will be long-term capital gains and losses; if a net loss results, all such gains and losses will be ordinary income and losses. Net Section 1231 gains will be treated as ordinary income to the extent of prior net Section 1231 losses of the taxpayer or predecessor taxpayer for the five most recent prior taxable years to the extent such losses have not previously been offset against Section 1231 gains. Losses are deemed recaptured in the chronological order in which they arose.
      If we are not a dealer with respect to our coal reserves and that property is not used in a trade or business, the property will be a “capital asset” within the meaning of Section 1221 of the Internal Revenue Code. Gain or loss recognized from the disposition of that property will be taxable as capital gain or loss, and the character of such capital gain or loss as long-term or short-term will be based upon our holding period in such property at the time of its sale. The requisite holding period for long-term capital gain is more than one year.
      Upon a disposition of coal reserves, a portion of the gain, if any, equal to the lesser of (i) the depletion deductions that reduced the tax basis of the disposed mineral property plus deductible development and mining exploration expenses, or (ii) the amount of gain recognized on the disposition, will be treated as ordinary income to us.
      Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and

41


Table of Contents

amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
Disposition of Units
      Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.
      Prior distributions from us in excess of cumulative net taxable income for a unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price received is less than his original cost.
      Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. A portion of this gain or loss, which may be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.
      The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury regulations.
      Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
  •  a short sale;
 
  •  an offsetting notional principal contract; or
 
  •  a futures or forward contract with respect to the partnership interest or substantially identical property.

42


Table of Contents

      Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
      Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.
      The use of this method may not be permitted under existing Treasury regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be real located among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury regulations.
      A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.
      Notification Requirements. A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units is required to notify us in writing of that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfer of units and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties.
      Constructive Termination. We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.
Uniformity of Units
      Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

43


Table of Contents

      We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the unit basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the unit basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6) which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a unit basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Units — Recognition of Gain or Loss.”
Tax-Exempt Organizations and Other Investors
      Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, other foreign persons and regulated investment companies raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.
      Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. A significant portion of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.
      A regulated investment company or “mutual fund” is required to derive 90% or more of its gross income from interest, dividends and gains from the sale of stocks or securities or foreign currency or specified related sources. It is not anticipated that any significant amount of our gross income will include that type of income. Recent legislation also includes net income derived from the ownership of an interest in a “qualified publicly traded partnership” as qualified income to a regulated investment company. We expect that we will meet the definition of a qualified publicly traded partnership. However, this legislation is only effective for taxable years beginning after October 22, 2004.
      Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly traded partnerships, we will withhold tax, at the highest applicable rate, from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

44


Table of Contents

      In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.
      Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.
Administrative Matters
      Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury regulations or administrative interpretations of the IRS. Neither we nor counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.
      The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.
      Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement appoints the general partner as our Tax Matters Partner.
      The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.
      A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

45


Table of Contents

      Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:
        (a) the name, address and taxpayer identification number of the beneficial owner and the nominee;
 
        (b) whether the beneficial owner is
        (1) a person that is not a United States person,
 
        (2) a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or
 
        (3) a tax-exempt entity;
        (c) the amount and description of units held, acquired or transferred for the beneficial owner; and
 
        (d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.
      Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.
      Accuracy-related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial evaluation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.
      A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:
  •  for which there is, or was, “substantial authority,” or
 
  •  as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.
      If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty. More stringent rules apply to “tax shelters,” a term that in this context does not appear to include us.
      A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.
      Reportable Transactions. If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of

46


Table of Contents

losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) is audited by the IRS. Please read “— Information Returns and Audit Procedures” above.
      Moreover, if we were to participate in a listed transaction or a reportable transaction (other than a listed transaction) with a significant purpose to avoid or evade tax, you could be subject to the following provisions of the American Jobs Creation Act of 2004:
  •  accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially grater amounts than described above at “— Accuracy-related Penalties,”
 
  •  for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and
 
  •  in the case of a listed transaction, an extended statute of limitations.
      We do not expect to engage in any reportable transactions.
State, Local and Other Tax Considerations
      In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently own assets and do business in Alabama, Georgia, Illinois, Indiana, Kentucky, Maryland, Montana, North Carolina, North Dakota, Tennessee, Virginia and West Virginia, all of which impose income taxes. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, the general partner anticipates that any amounts required to be withheld will not be material.
      It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Accordingly, we strongly recommend that each prospective unitholder consult, and depend upon, his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state and local, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state or local tax consequences of an investment in us.

47


Table of Contents

INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS
      An investment in us by an employee benefit plan is subject to certain additional considerations because the investments of such plans are subject to the fiduciary responsibility and prohibited transaction provisions of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), and restrictions imposed by Section 4975 of the Internal Revenue Code. As used herein, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to (a) whether such investment is prudent under Section 404(a)(1)(B) of ERISA; (b) whether in making such investment, such plan will satisfy the diversification requirement of Section 404(a)(1)(c) of ERISA; and (c) whether such investment will result in recognition of unrelated business taxable income by such plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors.” The person with investment discretion with respect to the assets of an employee benefit plan (a “fiduciary”) should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for such plan.
      Section 406 of ERISA and Section 4975 of the Internal Revenue Code (which also applies to IRAs that are not considered part of an employee benefit plan) prohibit an employee benefit plan from engaging in certain transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.
      In addition to considering whether the purchase of limited partnership units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether such plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.
      The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under certain circumstances. Pursuant to these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things, (a) the equity interest acquired by employee benefit plans are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered pursuant to certain provisions of the federal securities laws, (b) the entity is an “Operating Partnership” — i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries, or (c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest (disregarding certain interests held by our general partner, its affiliates and certain other persons) is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA (such as governmental plans). Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above and may also satisfy the requirements in (c).
      Plan fiduciaries contemplating a purchase of limited partnership units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

48


Table of Contents

SELLING UNITHOLDER
      This prospectus covers the offering for resale of up to 4,796,920 subordinated units, including the 4,796,920 common units into which the common units are convertible, by FRC-WPP NRP Investment L.P., the selling unitholder. The selling unitholder, a Delaware limited partnership, has two limited partners: FRC-NRP A.V. Holdings L.P., an affiliate of First Reserve Fund IX, L.P., and FRC-WPP Investment L.P., an affiliate of Corbin J. Robertson, Jr. The general partner of the selling unitholder is FRC-WPP GP LLC, a Delaware limited liability company controlled by affiliates of First Reserve.
      The selling unitholder currently has the right to nominate two of our directors. In addition, First Reserve holds a significant interest in Alpha Natural Resources, which is one of our largest lessees, and holds a significant interest in Foundation Coal, Inc., which controls the lessee on our Kingston Property in West Virginia. The selling unitholder acquired the subordinated units from Arch Coal, Inc. in December 2003 in a transaction exempt from the Securities Act of 1933, as amended. The selling unitholder is neither a broker-dealer nor an affiliate of a broker-dealer. As used in this prospectus, “selling unitholder” includes donees, pledgees, transferees, distributees or other successors-in-interest that sell units received after the date of this prospectus from the named selling unitholder as a gift, pledge, partnership distribution or other non-sale related transfer. The selling unitholder will bear all costs, expenses and fees in connection with the registration of the units offered by this prospectus. Brokerage commissions and similar selling expenses, if any, attributable to the sale of the units will be borne by the selling unitholder. This prospectus may also be used to offer any common units into which the subordinated units may convert. The following table sets forth information relating to the selling unitholder’s beneficial ownership of our subordinated units and common units:
                 
    Number of   Number of
    Subordinated Units   Common Units
Selling Unitholder   Owned   Owned
         
FRC-WPP NRP Investment L.P. 
    4,796,920       None  
      The applicable prospectus supplement will set forth, with respect to the selling unitholder:
  •  the nature of the position, office or other material relationship that the selling unitholder will have had within the prior three years with us or any of our affiliates, if not already described above;
 
  •  the number of subordinated units and common units, if any, owned by the selling unitholder prior to the offering;
 
  •  the number of subordinated units and common units, if any, to be offered for the selling unitholder’s account; and
 
  •  the number and (if one percent or more) the percentage of the outstanding subordinated units and common units to be owned by the selling unitholder after the completion of the offering.

49


Table of Contents

PLAN OF DISTRIBUTION
      We are registering subordinated units and common units that may be issued upon conversion of the subordinated units on behalf of selling unitholder or any of its donees, pledgees, distributees or other successors-in-interest. Distribution of any subordinated units or common units to be offered by the selling unitholder may be effected from time to time in one or more transactions (which may involve block transactions):
  •  on the New York Stock Exchange;
 
  •  in the over-the-counter market;
 
  •  in underwritten transactions;
 
  •  in transactions otherwise than on the New York Stock Exchange or in the over-the-counter market; or
 
  •  in a combination of any of these transactions.
      The transactions may be effected by the selling unitholder at market prices prevailing at the time of sale, at prices related to the prevailing market prices, at negotiated prices or at fixed prices. The selling unitholder may offer their shares through underwriters, brokers, dealers or agents, who may receive compensation in the form of underwriting discounts, commissions or concessions from the selling unitholder or the purchasers of the shares for whom they act as agent. The selling unitholder may engage in short sales, short sales against the box, puts and calls and other transactions in our securities, or derivatives thereof, and may sell and deliver their subordinated units or common units in connection with those transactions. In addition, the selling unitholder may from time to time sell their subordinated units or common units in transactions permitted by Rule 144 under the Securities Act.
      As of the date of this prospectus, we have not engaged any underwriter, broker, dealer or agent in connection with the distribution of subordinated units or common units pursuant to this prospectus by the selling unitholder. In the event an underwriter is engaged in connection with the offering of subordinated units or common units pursuant to this prospectus, discounts and commissions to such underwriter will not exceed 8% of the gross proceeds of any such offering. To the extent required, the number of subordinated units or common units to be sold, the purchase price, the name of any applicable agent, broker, dealer or underwriter and any applicable commissions with respect to a particular offer will be set forth in the applicable prospectus supplement. The aggregate net proceeds to the selling unitholder from the sale of its subordinated units or common units offered by this prospectus will be the sale price of those units, less any commissions, if any, and other expenses of issuance and distribution not borne by us.
      The selling unitholder and any brokers, dealers, agents or underwriters that participate with the selling unitholder in the distribution of subordinated units or common units may be deemed to be “underwriters” within the meaning of the Securities Act, in which event any discounts, concessions and commissions received by such brokers, dealers, agents or underwriters and any profit on the resale of the subordinated units or common units purchased by them may be deemed to be underwriting discounts and commissions under the Securities Act.
      We may, if so indicated in the applicable prospectus supplement, agree to indemnify the selling unitholder against certain civil liabilities, including liabilities under the Securities Act.
WHERE YOU CAN FIND MORE INFORMATION
      Natural Resource Partners files annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file at the SEC’s public reference room at 100 F Street, N.E., Washington, DC 20549. Please call the SEC at 1-800-732-0330 for further information on their public reference room. Our SEC filings are also available at the SEC’s web site at http://www.sec.gov. You can also obtain information about us at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

50


Table of Contents

      The SEC allows Natural Resource Partners to incorporate by reference the information we have previously filed with the SEC. This means that Natural Resource Partners can disclose important information to you without actually including the specific information in this prospectus by referring you to those documents. The information incorporated by reference is an important part of this prospectus. Information that Natural Resource Partners files later with the SEC will automatically update and may replace information in this prospectus and information previously filed with the SEC. The documents listed below and any filings made with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 after the date of this prospectus and prior to the termination of this offering (excluding any information furnished pursuant to Item 7.01 or Item 2.02 on any current report on Form 8-K) are incorporated by reference in this prospectus until the termination of each offering under this prospectus.
  •  Quarterly Report on Form 10-Q for the period ended March 31, 2005.
 
  •  Annual Report on Form 10-K for the fiscal year ended December 31, 2004.
 
  •  Current Reports on Form 8-K filed January 31, 2005, March 3, 2005, March 31, 2005, June 1, 2005, June 28, 2005, July 12, 2005 and July 20, 2005.
 
  •  The description of the common units contained in the Registration Statement on Form 8-A, initially filed September 27, 2002, and any subsequent amendment thereto filed for the purpose of updating such description.
 
  •  The description of the subordinated units contained in the Registration Statement on Form 8-A, initially filed June 28, 2005, and any subsequent amendment thereto filed for the purpose of updating such description.
      We make available free of charge on or through our Internet website, www.nrplp.com, 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 SEC.
      You may request a copy of any document incorporated by reference in this prospectus, at no cost, by writing or calling us at the following address:
  Investor Relations Department
  Natural Resource Partners L.P.
  601 Jefferson, Suite 3600
  Houston, Texas 77002
  (713) 751-7507
      We intend to furnish or make available to our unitholders within 90 days (or such shorter period as the SEC may prescribe) following the close of our fiscal year end annual reports containing audited financial statements prepared in accordance with generally accepted accounting principles and furnish or make available within 45 days (or such shorter period as the SEC may prescribe) following the close of each fiscal quarter quarterly reports containing unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each of our fiscal years. Our annual report will include a description of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, including the amount paid or accrued to each recipient and the services performed.

51


Table of Contents

FORWARD-LOOKING STATEMENTS
      Some of the information included in this prospectus, any prospectus supplement and the documents we incorporate by reference contain forward-looking statements. These statements use forward-looking words such as “may,” “will,” “anticipate,” “believe,” “expect,” “project” or other similar words. These statements discuss goals, intentions and expectations as to future trends, plans, events, results of operations or financial condition or state other “forward-looking” information.
      A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that assumed facts or bases almost always vary from actual results, and the differences between assumed facts or bases and actual results can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus, any prospectus supplement and the documents we have incorporated by reference. These statements reflect Natural Resource Partners’ current views with respect to future events and are subject to various risks, uncertainties and assumptions.
      Many of such factors are beyond our ability to control or predict. Please read “Risk Factors” for a better understanding of the various risks and uncertainties that could affect our business and impact the forward-looking statements made in this prospectus. Readers are cautioned not to put undue reliance on forward-looking statements.
LEGAL MATTERS
      Certain legal matters in connection with the securities will be passed upon by Vinson & Elkins L.L.P., Houston, Texas, as our counsel. The selling unitholder’s counsel and the underwriters’ own legal counsel will advise them about other issues relating to any offering in which they participate.
EXPERTS
      Ernst & Young LLP, independent registered public accounting firm, have audited (i) the consolidated financial statements of Natural Resource Partners L.P. and management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004, (ii) the financial statements of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, and Arch Coal Contributed Properties, and (iii) the balance sheet of NRP (GP) LP (Exhibit 99.1), included in our Annual Report on Form 10-K for the year ended December 31, 2004, as set forth in their reports, which are incorporated by reference in this prospectus and elsewhere in the registration statement. These financial statements and management’s assessment are incorporated by reference in reliance on Ernst & Young LLP’s reports, given on their authority as experts in accounting and auditing.
      On April 26, 2002, Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation dismissed Arthur Andersen LLP as their independent public accountants due to the adverse publicity being experienced by Arthur Andersen LLP and concerns regarding the acceptance of its audits. Ernst & Young LLP was engaged on May 3, 2002 by Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation to serve as their independent auditors for the three years ended December 31, 2000 and 2001.
      Arthur Andersen LLP’s reports on the financial statements of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, and New Gauley Coal Corporation for the years ended December 31, 2001 and 2000 did not contain an adverse opinion or disclaimer of opinion, nor

52


Table of Contents

were they qualified or modified as to uncertainty, audit scope or accounting principles. During the years ended December 31, 2001 and 2000 and through April 26, 2002:
  •  there were no disagreements with Arthur Andersen LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure which if not resolved to Arthur Andersen LLP’s satisfaction, would have caused them to make reference to the subject matter in connection with their reports on the financial statements of any of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, or New Gauley Coal Corporation for such years;
 
  •  there were no reportable events as listed in 304(a)(1)(v) of Regulation S-K; and
 
  •  Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, and New Gauley Coal Corporation did not consult Ernst & Young LLP with respect to the application of accounting principles to a specified transaction either completed or proposed, or the type of audit opinion that might be rendered on the financial statements of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, or New Gauley Coal Corporation or any other matters or reportable events listed in Items 304(a)(2)(i) and (ii) of Regulation S-K.

53


Table of Contents


(GLOBE WATERMARK)

 

(NATURAL RESOURCE PARTNERS LOGO)
Natural Resource Partners L.P.
4,200,000 Subordinated Units
Representing Limited Partner Interests
 
Prospectus Supplement
August       , 2005
 
Joint Book-Running Managers
Lehman Brothers
Citigroup
 
A.G. Edwards
UBS Investment Bank
Wachovia Securities
Friedman Billings Ramsey
Sanders Morris Harris