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 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.

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

A.G. Edwards

                    , 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

Prospectus dated August 2, 2005

	•	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%.

	•	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.

	•	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.

		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	%

(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.

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.

		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.

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

		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.”

			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

(1)	Distributable cash flow represents cash flow from operations less actual principal payments and cash reserves for scheduled principal payments on our senior notes.

			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

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:

      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:

      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.

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.

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.

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.

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

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.

Results of Operations

      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.

      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:

      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.

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

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

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

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

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

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

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

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

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

Liquidity and Capital Resources

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

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.

      Our debt exists entirely at our wholly owned subsidiary, NRP Operating LLC, and at June 30, 2005 consisted of:

      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

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:

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

      The credit agreement contains covenants requiring us to maintain:

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

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

      The following table reflects our long-term non-cancelable contractual obligations as of June 30, 2005 (in millions):

      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

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.

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.

      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.

      The following table sets forth our estimate of the sulfur content, the typical quality of our coal reserves and the type of coal in each area as of December 31, 2004.

Sulfur Content, Typical Quality and Type of Coal

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

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

Major Coal Properties

      The following is a summary of our major coal producing properties based on 2004 production:

      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.

      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.

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

      Hocking-Wolford/ Cummings. The Hocking-Wolford property and the Cummings property are both located in Sullivan County, Indiana. In 2004, 1.6 million tons were produced from our property. Both properties are under common lease to Black Beauty Coal Company, an affiliate of Peabody Energy 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.

      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.

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.

      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

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

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.

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.

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:

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.

      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:

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.

      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

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:

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.

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:

      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

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.

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:

      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

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:

      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.

      You may also request a copy of these filings at no cost by making written or telephone requests for copies to:

      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.

PROSPECTUS

Natural Resource Partners L.P.

4,796,920 Subordinated Units

4,796,920 Common Units

        This prospectus relates to:

      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

      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.

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

      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:

      In addition, the actual amount of cash we will have available for distribution will depend on other factors that include:

      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.

      The prices our lessees receive for their coal depend upon factors beyond their or our control, including:

      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 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:

      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. 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.

      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.

      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:

      If our lessees do not manage their operations well, their production could be reduced, which would result in lower coal royalty revenues to us.

      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.

      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

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.

      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.

      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.

      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.

      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.

      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 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:

      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.

      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

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.

      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.

      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 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.

      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

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 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.

      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.

      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.

      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.

      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,

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.

      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.

      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

      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

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:

      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 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: