Edgar Filing: NATURAL RESOURCE PARTNERS LP

e424b3

The information in this prospectus supplement is not complete and may be changed. This prospectus supplement is not an offer to sell these securities, and we are not soliciting offers to buy these securities, in any state where the offer or sale is not permitted.

Filed pursuant to Rule 424(b)(3)

Registration No. 333-111532

SUBJECT TO COMPLETION, DATED MARCH 8, 2004

PROSPECTUS SUPPLEMENT

(To Prospectus Dated February 10, 2004)

(NATURAL RESOURCE PARTNERS L.P. LOGO)

4,600,000 Common Units

Representing Limited Partner Interests

Natural Resource Partners L.P.

$ per common unit

We are selling 4,600,000 common units with this prospectus supplement and the accompanying prospectus. We have granted the underwriters a 30-day option to purchase up to 690,000 additional common units to cover over-allotments.

Our common units are listed on the New York Stock Exchange under the symbol “NRP.” The last reported sales price of our common units on the NYSE on March 3, 2004 was $42.50 per common unit.

Investing in our common units involves risks. See “Risk Factors” beginning on page S-11 of this prospectus supplement and page 3 of the accompanying prospectus.

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.


	Per Common Unit	Total

Public Offering Price	$	$
Underwriting Discount	$	$
Proceeds to Natural Resource Partners L.P., before expenses	$	$

The underwriters expect to deliver the common units on or about March , 2004.


Sole Bookrunning Manager	Joint Lead Manager


Citigroup	Lehman Brothers

A.G. Edwards & Sons, Inc.


	UBS Investment Bank


	Wachovia Securities

Friedman Billings Ramsey


	RBC Capital Markets


	Sanders Morris Harris

March , 2004

(PROPERTY LOCATIONS)

This document is in two parts. The first part is this prospectus supplement, which describes the terms of this offering of common units. The second part is the accompanying prospectus, which gives more general information, some of which may not apply to the common units. If the description of this common 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. We are not making an offer of these securities 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


Summary			S-1
Risk Factors			S-11
Use of Proceeds			S-12
Price Range of Common Units and Distributions			S-13
Capitalization			S-14
Management’s Discussion and Analysis of Financial Condition and Results of Operations			S-15
Business			S-20
Management			S-23
Tax Considerations			S-27
Underwriting			S-28
Legal			S-31
Experts			S-31
Information Regarding Forward Looking Statements			S-32
Where You Can Find More Information			S-33
Prospectus
About This Prospectus			1
About Natural Resource Partners and NRP (Operating) LLC			1
The Guarantors			1
Risk Factors			3
Use of Proceeds			20
Ratios of Earnings to Fixed Charges			20
Description of Debt Securities			21
Description of the Common Units			30
Cash Distributions			34
Material Tax Consequences			41
Investment in Us by Employee Benefit Plans			56
Selling Unitholders			57
Plan of Distribution			58
Where You Can Find More Information			59
Forward-Looking Statements			60
Legal Matters			61
Experts			61

SUMMARY

This summary highlights information contained elsewhere in this prospectus supplement and the accompanying prospectus. You should read the entire prospectus supplement, the accompanying prospectus, the documents incorporated by reference and the other documents to which we refer for a more complete understanding of this offering. You should read “Risk Factors” beginning on page S-11 of this prospectus supplement and page 3 of the accompanying prospectus for more information about important factors that you should consider before buying common units in this offering. Unless otherwise indicated, the information presented in this prospectus supplement assumes that the underwriters do not exercise their over-allotment option.

Natural Resource Partners L.P.

We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. We do not operate any mines. We lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine our coal reserves in exchange for royalty payments. We control approximately 1.8 billion tons of proven and probable coal reserves in nine states, including 1.6 billion tons we controlled as of December 31, 2003 and an additional 176 million tons we acquired in January 2004. Our reserves are subject to 125 leases with 53 lessees. 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. In 2003, our lessees produced 44.3 million tons of coal from our properties and our total revenues were $85.5 million.

Business Strategies

Our primary business strategies are:


	•	Maximize Royalty Revenues from Our Existing Properties. We 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 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 six significant acquisitions of coal-producing properties or overriding royalty interests, which have increased our proven and probable coal reserves by approximately 665 million tons (net of production), or approximately 58%. See “— Acquisitions.”

	•	Explore New Opportunities with Our Existing Lessees. Many of our lessees are subsidiaries of large coal producers that have long-term 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 Coal Mine Operator Base. 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 enables 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 coal mine operator base.

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Competitive Strengths

We believe we are well positioned to execute our business strategies successfully because of the following competitive strengths:


	•	Our Royalty Structure Generates Stable Cash Flow. Our leases generally provide for royalty rates equal to the higher of a percentage of the gross sales price or a fixed price per ton of coal mined, subject to a minimum monthly, quarterly or annual payment. This structure is designed to make our cash flow stable and predictable in periods of low coal prices, while enabling us to benefit during periods of higher coal prices.

	•	We Do Not Directly Bear Operating Costs and Risks. Because we do not operate any mines, we do not bear ordinary operating costs and have limited direct exposure to environmental compliance, permitting and labor risks. Our lessees bear all labor-related risks associated with operating the mines, such as health care legacy costs, black lung benefits and workmen’s 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 2003, we derived approximately 54% of our coal royalty revenues from subsidiaries of seven 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 reserves are produced, processed and marketed efficiently and sold 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. The coal royalty business is highly fragmented and characterized by numerous small entities 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, combined with our ability to issue debt or equity securities, provides the financial flexibility to pursue acquisitions.

	•	We Have Experienced, Knowledgeable Management. Our management team has a successful record of managing, leasing and acquiring coal-producing properties. Each member of our management team 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.

Acquisitions

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

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BLC Properties. In January 2004, we purchased all of the mineral interests of BLC Properties LLC for $73.0 million. This acquisition included coal, oil and gas and other mineral rights on approximately 270,000 acres that contain approximately 176 million tons of coal reserves. We lease these reserves to eight different lessees. The transaction also included oil and gas and other mineral rights on approximately 205,000 additional acres. The properties are located in Kentucky, Tennessee, West Virginia, Virginia, and Alabama. BLC retained a 35% non-participating royalty interest in the oil and gas and other mineral rights.

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

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

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

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

El Paso Properties. In December 2002, we purchased 108 million tons of coal reserves from El Paso Corporation for $57.0 million. We lease these reserves to Alpha Natural Resources and 13 other lessees. More than half of the reserves are in Kentucky, and the remainder are located in Virginia and West Virginia. We also acquired the mineral rights in 164,000 acres that generate minor amounts of revenues from timber, oil and gas and other leases.

Recent Developments

Distribution Increases. On February 13, 2004, we paid a quarterly cash distribution of $0.5625 per unit for the quarter ended December 31, 2003, representing an annual distribution of $2.25 per unit. We have increased our quarterly cash distribution three times since our initial public offering in October 2002, for an approximately 10% increase in the quarterly distribution over our initial quarterly distribution.

Purchase of Arch Coal Partnership Interests. In December 2003, Corbin J. Robertson, Jr., our Chairman and Chief Executive Officer, and a group of investors consisting of other owners of our general partner, purchased Arch Coal, Inc.’s 42.25% general partner interest in us and 10% of our incentive distribution rights owned separately by Arch Coal for $4.0 million. Together, Mr. Robertson and this group of investors now own 100% of our general partner. In addition, Mr. Robertson, First Reserve Corporation (a private equity firm focused on energy investments), our management and some of our original sponsors purchased all of Arch Coal’s 4,796,920 subordinated units for $111.0 million. Arch Coal continues to own 2,895,670 common units.

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We will use net proceeds from this offering in excess of $102.5 million and the net proceeds of any exercise of the underwriters’ over-allotment option to redeem common units owned by Arch Coal at a price equal to the offering price less underwriting discounts, up to the total number of common units owned by Arch Coal. Based on the closing price of our common units on March 3, 2004 and assuming a 4.25% underwriting discount, we expect to redeem 2,124,127 common units (2,814,127 common units if the over-allotment option is exercised in full). We will cancel the common units that are redeemed. After this offering, Arch Coal will own 771,543 common units (81,543 common units if the over-allotment option is exercised in full), representing a 3.00% limited partner interest (0.32% if the over-allotment option is exercised in full).

Risk Factors

You should carefully read the risk factors included under the caption “Risk Factors” beginning on page S-11 of this prospectus supplement and page 3 of the accompanying prospectus, as well as those risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2003, which is incorporated by reference in this prospectus supplement.

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Partnership Structure and Management

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

Arch Coal has the right to elect two directors, one of whom must be an independent director, to the board of directors of GP Natural Resource Partners LLC for so long as Arch continues to hold at least 10% of the common units of Natural Resource Partners. Based on the closing price of our common units on March 3, 2004 and assuming a 4.25% underwriting discount, we expect to redeem 2,124,127 common units from Arch Coal, which will result in Arch Coal owning approximately 5.6% of our outstanding common units following this offering.

In connection with the purchase of Arch Coal’s partnership interests in December 2003, the board of directors of GP Natural Resource Partners LLC was expanded to nine members, and FRC-WPP NRP Investment L.P., an affiliate of First Reserve Corporation, obtained the right to elect two directors, one of whom must be an independent director, to the board of GP Natural Resource Partners LLC.

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our subsidiaries through an operating company, NRP (Operating) LLC. Our partnership structure is as follows:


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

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

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

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

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

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

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

The chart on the following page depicts our organizational and ownership structure, after giving effect to this offering. The percentages reflected in the organizational chart represent the approximate ownership interests in us, including the anticipated redemption of 2,124,127 common units from Arch Coal.

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Ownership of Natural Resource Partners L.P.

(FLOW CHART)

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The Offering


Common units offered by us		4,600,000 common units.

		5,290,000 common units if the underwriters exercise their over-allotment option in full.

Units outstanding after this offering		13,829,531 common units and 11,353,658 subordinated units, or 13,829,531 common units and 11,353,658 subordinated units if the underwriters exercise their over-allotment option in full.

Use of proceeds		We will use the proceeds from this offering to repay debt we borrowed under our credit facility and to redeem common units owned by Arch Coal, Inc.

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 February 13, 2004, we paid a cash distribution of $0.5625 for the fourth quarter of 2003.

		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 period		During the subordination period, common units are entitled to receive a minimum quarterly distribution of $0.5125 per unit, plus arrearages from prior quarters before any distributions are made on our subordinated units. The subordination period will end once we meet the financial tests in the partnership agreement, but it generally cannot end before September 30, 2007. 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 meet the financial tests in the partnership agreement for any quarter ending on or after September 30, 2005, 25% of the subordinated units will convert into common units. If we meet these tests for any quarter 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.

Estimated ratio of taxable income to distributions		If you own the common units you purchase in this offering through the record date for the distribution for the fourth quarter of 2006, we estimate that you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 30% of the cash distributed to you with respect

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		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 less than 25% 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		NRP

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Summary Selected Financial and Operating Data

We derived the summary selected historical financial data for Natural Resource Partners L.P. as of December 31, 2002 and 2003 and for the period of operations from October 17, 2002 through December 31, 2002 and the year ended December 31, 2003 from our audited financial statements.

The following table should be read together with, and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes incorporated by reference in this prospectus supplement.


		From Commencement
		of Operations			For the Year
		(October 17, 2002)			Ended
		Through December 31,			December 31,
		2002			2003


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

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

	Total expenses		7,278			41,397

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

Net income		$	6,415		$	36,907

Balance Sheet Data (at period end):
Total assets		$	392,719		$	531,676
Deferred revenue			13,252			15,054
Long-term debt			57,500			192,650
Total liabilities			74,085			223,518
Partners’ capital			318,634			308,158
Cash Flow Data:
Net cash flow provided by (used in):
	Operating activities	$	6,738		$	64,528
	Investing activities		(57,449	)		(142,511	)
	Financing activities		58,463			94,550
Other Data:
Royalty coal tons produced by lessees			7,314			44,344
Average gross coal royalty per ton		$	1.58		$	1.66
Distributable cash flow(1)		$	6,738		$	59,828


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

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Distributable cash flow is a “non-GAAP financial measure” that is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable cash flow is a significant liquidity metric that indicates NRP’s ability to generate cash flows at a level that can sustain or support an increase in quarterly cash distributions paid to its partners. Distributable cash flow is also the quantitative standard used throughout the investment community with respect to publicly traded partnerships. Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. We believe that “net cash provided by operating activities” is the most comparable financial measure to distributable cash flow.

The following table reconciles distributable cash flow to net cash provided by operating activities.


		From
		Commencement
		of Operations
		(October 17, 2002)		For the Year
		Through		Ended
		December 31,		December 31,
		2002		2003


		(In thousands)
*Reconciliation of GAAP “Net cash provided by operating activities” to Non-GAAP “Distributable Cash Flow”:*
Cash flow from operating activities		$	6,738	$	64,528
Less actual principal payments			—		—
Less reserves for scheduled principal payments			—		(4,700	)

	Distributable cash flow	$	6,738	$	59,828

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RISK FACTORS

An investment in our common 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 common units. If any of the 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 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 3 of the accompanying prospectus.

Arch Coal may sell additional common units in the trading market in the future, which could reduce the market price of the common units.

Arch Coal will own 771,543 common units immediately after completion of this offering (81,543 if the over-allotment option is exercised in full), representing approximately 5.6% (approximately 0.6% if the over-allotment option is exercised in full) of the total number of common units outstanding. Under a registration rights agreement we entered into with Arch Coal, we will register all of these common units for sale prior to August 1, 2004. In the future, Arch Coal may dispose of some or all of its common units. Sales of a substantial number of these units in the market, whether in a single transaction or series of transactions, or the possibility that these sales may occur, could cause a decline in the market price of our outstanding common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

A large mine operated by one of our lessees will not generate coal royalty revenues until it is reopened.

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

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

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USE OF PROCEEDS

We expect that we will receive net proceeds of approximately $186.8 million from the sale of the 4,600,000 common units we are offering based on an assumed offering price of $42.50 per common unit and after deducting underwriting discounts and commissions and estimated offering expenses payable by us. If the underwriters exercise their over-allotment option in full, we will receive net proceeds of approximately $214.9 million. In connection with the offering, we will also receive a capital contribution of $2.1 million from our general partner to maintain its 2% general partner interest ($2.1 million if the underwriters exercise their over-allotment option in full).

Assuming no exercise of the over-allotment option, we will use the net proceeds of this offering and our general partner’s capital contribution to:


	•	repay the approximately $102.5 million of debt outstanding under our credit facility; and

	•	redeem approximately 2.1 million common units from Arch Coal at a price equal to the offering price less underwriting discounts.

We will use the net proceeds from any exercise of the underwriters’ over-allotment option to redeem from Arch Coal an additional number of common units equal to the number of common units issued upon exercise of that option at a price per unit equal to the net proceeds per common unit before expenses, up to the total number of common units owned by Arch Coal. We may use any additional proceeds from any exercise of the underwriters’ over-allotment option to redeem common units owned by Great Northern Properties Limited Partnership, an affiliate of our general partner.

The weighted average interest rate on the debt we will repay was 4.4% on March 3, 2004. This indebtedness was incurred under our credit facility during the past year in connection with our acquisitions of coal reserves and other mineral rights and matures in October 2005. Please read “Summary — Acquisitions.” Affiliates of some of the underwriters for this offering are lenders to us under our credit facility and will be repaid in full with the proceeds from this offering. See “Underwriting.”

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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

As of March 1, 2004, there were 11,353,658 common units outstanding, held by approximately 4,550 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 held by the WPP Group and FRC-WPP NRP Investment L.P. and are not publicly traded.

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. The last reported sale of common units on the NYSE on March 3, 2004 was $42.50 per unit.



		Price Ranges
						Cash Distributions
		High		Low		Per Unit(1)

2004
	First Quarter (through March 3, 2004)	$	42.60	$	35.67			(2)
2003
	Fourth Quarter	$	41.49	$	28.25	$	0.5625
	Third Quarter		37.00		29.60	$	0.5375
	Second Quarter		31.84		22.90	$	0.5225
	First Quarter		23.98		20.45	$	0.5225
2002
	Fourth Quarter	$	20.70	$	18.35	$	0.4234	(3)


(1)	Distributions declared associated with each respective quarter.

(2)	We expect to declare and pay a cash distribution for the first quarter of 2004 within 45 days following the end of the quarter.

(3)	The prorated cash distribution relates to the period from October 17, 2002, the closing date of our initial public offering, to December 31, 2002.

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CAPITALIZATION

The following table sets forth our historical capitalization as of December 31, 2003, and our capitalization as adjusted to give effect to (1) our acquisitions in 2004 and (2) the combined effect of our acquisitions, this offering of common units, our general partner’s proportionate capital contribution and the application of the net proceeds from this offering. The net proceeds from our common unit offering are expected to be $186.8 million, which represent 4,600,000 common units sold at $42.50 per common unit, net of the underwriting discounts and estimated offering expenses. Please read “Use of Proceeds.”



		As of December 31, 2003

								As Adjusted
								for 2004
					As Adjusted			Acquisitions and
					for 2004			Common Unit
		Actual			Acquisitions(1)			Offering


		(in thousands)
Cash and cash equivalents		$	24,320		$	24,320		$	24,320

Current portion of long-term debt		$	9,350		$	9,350		$	9,350
Long-term debt:
	Senior notes		165,650			165,650			165,650
	Credit facility		27,000			102,500			—

Total debt			202,000			277,500			175,000

Partners’ capital:
	Common unitholders		143,956			143,956			244,309
	Subordinated unitholders		158,633			158,633			158,633
	General partner		6,474			6,474			8,621
	Other accumulated comprehensive loss		(905	)		(905	)		(905	)

Total partners’ capital			308,158			308,158			410,658

Total capitalization		$	510,158		$	585,658		$	585,658


(1)	In January 2004, we acquired coal reserves from BLC Properties LLC for $73.0 million. In February 2004, we acquired a small block of reserves adjacent to those acquired in the BLC acquisition from Appolo Fuels, Inc. for $2.5 million. Both acquisitions were funded with our revolving credit facility.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Executive Overview

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

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

Most of our coal is produced by large companies, many of which are publicly traded, with professional and sophisticated sales departments. We estimate that 80% of our coal is sold by our lessees under coal supply contracts that have terms of one year or more. However, coal supply contracts with terms of one year or more are becoming increasingly rare, and our coal royalty revenue stream is increasingly affected by changes in 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. During the last few years, steam coal prices have varied greatly. While higher than average spot prices prevailed for most of 2001, in late 2001 prices declined as demand for coal fell due to unusually warm weather during the winter of 2001-2002 and the sluggish U.S. economy. In contrast, the winter of 2002-2003 was colder than normal in many parts of the United States. As a result of the increased demand for electricity for heating resulting from this colder weather, electric utilities used substantial amounts of coal to generate electricity and reduced the size of their stockpiles. Additionally, the weaker U.S. dollar, especially against the Euro and the Australian dollar, and the increase in ocean going freight rates caused an increase in demand for export coal because the United States was better able to compete with Australia for the European market. Thus, in 2003, our lessees experienced a greater demand for coal, and spot prices increased about 30%. We expect these increased spot prices to begin to affect our results of operations in 2004 because our lessees received previously contracted prices for much of their production in 2003.

Prices of metallurgical coal have increased substantially in the past year. Metallurgical coal, because of its unique chemical characteristics, is usually priced higher than steam coal. Metallurgical coal production gradually decreased during the years prior to 2003 due to a decline in exports as a result of the strength of the U.S. dollar and increasing use of electric arc furnaces and pulverized coal, rather than metallurgical coal, for steel production. With the weakening of the dollar and the increase in ocean going freight rates, U.S. metallurgical coal has become more competitive and exports are increasing. The ventilation disruption resulting in the closure of PinnOak Resources’ Pinnacle Mine in West Virginia, together with the closure of another low volatile metallurgical mine in Alabama have caused a critical shortage of that type of coal and a substantial increase in its price. Some metallurgical coal can also be

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used as steam coal. However, some metallurgical coal mines on our properties may only operate profitably if all or a portion of their production is sold as metallurgical coal. If the operators of these mines are unable to sell metallurgical coal, these mines may not be economically viable and may be closed.

In addition to coal royalty revenues, we generated approximately 5% of our 2003 revenues from rentals, royalties on oil and gas and coalbed methane leases, overriding royalty arrangements and wheelage payments. We have not provided comparison and explanations of other items on our income statement because we do not have comparable data for all of 2002 and 2001.

Coal Royalty Revenues and Production


	*Year Ended December 31, 2003 Compared with Year Ended December 31, 2002*

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



		Year Ended
		December 31,

		2002		2003


		(In thousands, except
		per-ton data)
Coal Royalty Revenues
Appalachia		$	40,688	$	63,855
Illinois Basin			2,994		3,566
Northern Powder River Basin			5,926		6,349

	Total	$	49,608	$	73,770

Coal Production (in tons)
Appalachia			22,600		35,998
Illinois Basin			2,433		3,034
Northern Powder River Basin			5,474		5,312

	Total		30,507		44,344

Average Gross Coal Royalty Per Ton
Appalachia		$	1.80	$	1.77
Illinois Basin			1.23		1.18
Northern Powder River Basin			1.08		1.20

	Total	$	1.63	$	1.66

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

Appalachia. Coal royalty revenues in Appalachia in 2003 were $63.9 million compared to $40.7 million in 2002, an increase of $23.2 million, or 57%. In 2003, production in Appalachia was

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36.0 million tons compared to 22.6 million tons in 2002, an increase of 13.4 million tons, or 59%. As noted above, the increases in both coal royalty revenues and production primarily resulted from the acquisitions we have completed since our initial public offering.

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

These increases were partially offset by lower royalty revenue from our Evans-Laviers, Eunice and Lone Mountain properties. On our Evans-Laviers property, production decreased from 3.4 million tons to 3.0 million tons and coal royalty revenues decreased from $4.5 million to $3.8 million. This decrease resulted from a combination of a higher royalty surface mine being idle for most of the year and an underground mine having higher production during the current year. On our Eunice property, production remained constant at 2.6 million tons but coal royalty revenues decreased from $4.6 million to $4.3 million because a greater proportion of the production came from the lower royalty surface mine. On our Lone Mountain property, production remained constant at 2.5 million tons while royalty revenue decreased from $4.8 million to $4.6 million due to a slightly lower average selling price for the production of our lessee.

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

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

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	*Year Ended December 31, 2002 Compared with Year Ended December 31, 2001*

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



		Year Ended
		December 31,

		2001		2002


		(In thousands, except
		per-ton data)
Coal Royalty Revenues
Appalachia		$	31,719	$	40,688
Illinois Basin			3,155		2,994
Northern Powder River Basin			6,951		5,926

	Total	$	41,825	$	49,608

Coal Production (in tons)
Appalachia			19,648		22,600
Illinois Basin			2,659		2,433
Northern Powder River Basin			6,683		5,474

	Total		28,990		30,507

Average Gross Coal Royalty Per Ton
Appalachia		$	1.61	$	1.80
Illinois Basin			1.19		1.23
Northern Powder River Basin			1.04		1.08

	Total	$	1.44	$	1.63

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

Appalachia. Production from our West Fork property increased from 222,000 tons to 2.1 million tons, and coal royalty revenues increased from $357,000 to $4.7 million because a longwall mine moved onto the property from adjacent property. On our Eunice property, production increased from 1.8 million tons to 2.6 million tons, and coal royalty revenues increased from $2.7 million to $4.6 million because a longwall mine was on our property for a greater portion of the year and was subject to a higher royalty rate. On our Welch/ Wyoming property, production increased from 222,000 tons to 609,000 tons, and coal royalty revenues increased from $361,000 to $1.3 million because a new mine, which began production during 2001, operated on the property for the entire year. On our Dorothy property, production increased from 652,000 tons to 1.0 million tons, and coal royalty revenues increased from $1.1 million to $2.0 million. This increase was due to increased production from a surface mine and the resumption of mining at a temporarily idled mine. On our Kingston property, production increased from 740,000 tons to 1.1 million tons, and coal royalty revenues increased from $1.3 million to $1.8 million. This increase was primarily due to a new mine starting on the property during the year. In addition, the acquisition of properties from El Paso on December 4, 2002 resulted in additional production of 504,000 tons and coal royalty revenues of $601,000 in 2002.

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These increases were partially offset by lower production and coal royalty revenues from our Rockhouse and Boone-Lincoln properties. On our Evans-Laviers property, production decreased from 3.8 million tons to 3.4 million tons. Coal royalty revenues decreased from $5.1 million to $4.4 million. This decrease was due to the idling of a higher-royalty-rate surface mine for part of the year. On our Rockhouse property, production decreased from 322,000 tons to 34,000 tons, and coal royalty revenues decreased from $791,000 to $82,000 because a mine on the property ceased production. On our Boone-Lincoln property, production decreased from 670,000 tons to 195,000 tons, and coal royalty revenues decreased from $1.3 million to $389,000. This decrease was due to lower production on the property from the active surface mine and the temporary idling of the underground mine on the property. This idled mine resumed production in late 2002.

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

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


	*Liquidity and Capital Resources*

Cash Flows and Capital Expenditures. We believe that cash generated from our operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements and anticipated capital expenditures for the next several years. We expect to fund acquisitions with borrowings under our credit facility and proceeds from the issuance of common units. 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 detailed discussion of factors that will affect cash flow we generate from our operations, please read “Risk Factors” beginning on page S-11 of this prospectus supplement and page 3 of the accompanying prospectus.

Credit Facility and Senior Notes. NRP Operating LLC, our wholly owned subsidiary, has issued all of our debt. Our debt currently consists of:


	•	a $175 million revolving credit facility that matures in October 2005 and under which $102.5 million is outstanding as of the date of this prospectus supplement;

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

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

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

The revolving credit facility includes a $12.0 million distribution-loan sublimit that can be used for funding quarterly distributions. The remainder of the revolving credit facility is available for general purposes, including future acquisitions, but may not be used to fund quarterly distributions.

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BUSINESS

Coal Reserves and Production

The following table sets forth production data and reserve information for the properties in each of the following areas: Appalachia, Illinois Basin and Northern Powder River Basin.



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

Area		2001		2002		2003		Underground		Surface		Total


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

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

We classify low sulfur coal as coal with a sulfur content of less than 1.0%, medium sulfur coal as coal with a sulfur content between 1.0% and 1.5% and high sulfur coal as coal with a sulfur content of greater than 1.5%. Compliance coal is coal which meets the standards of Phase II of the Clean Air Act and is that portion of low sulfur coal that, when burned, emits less than 1.2 pounds of sulfur dioxide per million Btu. As of December 31, 2003, approximately 36% of our reserves were compliance coal. 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 2003, approximately 22% of the coal royalty revenues from our properties were from metallurgical coal.

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

Sulfur Content, Typical Quality and Type of Coal



				Sulfur Content								Typical Quality				Type of Coal

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


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

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


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

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

We prepare our reserve estimates from geologic data assembled and analyzed by our staff of geologists and engineers. The geologic data is taken from thousands of drill holes, adjacent mine workings, outcrop prospect openings and other sources, including from third parties. These estimates also take into account legal, technical and economic limitations that may keep coal from being mined. Reserve estimates will change from time to time due to mining activities, analysis of new engineering and geologic data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods, and other factors. Our reserves as of December 31, 2003 were estimated internally by our geologists and engineers.

Major Coal Properties

The following is a summary of our major coal producing properties based on 2003 production:


	*Appalachia*

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

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

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

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

Eunice. The Eunice property is located in Raleigh and Boone Counties, West Virginia. In 2003, 2.6 million tons were produced from this property. We lease the property to Boone East Development Co., a subsidiary of publicly held Massey Energy Company. Boone East Development, through affiliates, conducts two operations on the property, including a surface operation and an underground longwall mine. These operations extend onto adjacent reserves and will also eventually extend onto a portion of our nearby

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Y&O property. Production from this operation is generally transported by beltline and processed at two preparation plants located off the property. The preparation plants ship both metallurgical and steam coal on the CSX railroad to customers such as American Electric Power, Cinergy, Louisville Gas & Electric, Virginia Electric Power, AK Steel and U.S. Steel.

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

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


	*Illinois Basin*

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


	*Northern Powder River Basin*

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

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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 served as officers or directors of GP Natural Resource Partners LLC since our initial public offering.


Name	Age		Position with GP Natural Resource Partners LLC

Corbin J. Robertson, Jr.		56	Chief Executive Officer and Chairman of the Board
Nick Carter		57	President and Chief Operating Officer
Dwight L. Dunlap		50	Chief Financial Officer and Treasurer
Kevin F. Wall		47	Vice President and Chief Engineer
Kathy E. Hager		52	Vice President Investor Relations
Wyatt L. Hogan		32	Vice President, General Counsel and Secretary
Corbin J. Robertson III		33	Vice President Acquisitions
Kenneth Hudson		49	Controller
Charles H. Kerr		50	Assistant Secretary
Robert T. Blakely**		62	Director
David M. Carmichael**		65	Director
Robert B. Karn III**		62	Director
Alex T. Krueger		30	Director
S. Reed Morian		57	Director
David B. Peugh		49	Director
W. W. Scott, Jr.		58	Director
Stephen P. Smith*		43	Director


*	Independent director.


**	Independent director and member of our Audit Committee, Conflicts Committee and Compensation, Nominating and Governance Committee.

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

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

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Coal Lessors, the immediate past Chair of the West Virginia Chamber of Commerce and a board member of the Kentucky Coal Association.

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

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

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

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

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

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

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

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Robert T. Blakely joined the Board of Directors of GP Natural Resource Partners LLC in January 2003. He currently serves as Executive Vice President and Chief Financial Officer of MCI, Inc. From mid-2002 through mid-2003, he served as President of Performance Enhancement Group, which was formed to acquire manufacturers of high performance and racing components designed for automotive- and marine-engine applications. He previously served as Executive Vice President and Chief Financial Officer of Lyondell Chemical from 1999 through 2002, Executive Vice President and Chief Financial Officer of Tenneco, Inc. from 1981 until 1999 as well as a Managing Director at Morgan Stanley. He served a four-year term on the Financial Accounting Standards Advisory Council and currently serves as a trustee of Cornell University, where he serves as Chairman of Cornell’s Finance Committee and a member of the Executive Committee of the Board.

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

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

Alex T. Krueger joined the Board of Directors of GP Natural Resource Partners LLC in December 2003. Mr. Krueger joined First Reserve Corporation in 1999 and is currently a Director of First Reserve focused on investment efforts in the coal and energy infrastructure sectors. Mr. Krueger also serves on the board of Alpha Natural Resources LLC, a significant lessee of NRP, as well as the boards of Pine Mountain Oil and Gas, Inc. and Aquilex Services Corporation. Prior to joining First Reserve, Mr. Krueger worked in the Houston office of Donaldson, Lufkin & Jenrette in the Energy Group.

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

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

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

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. He is responsible for American Electric Power’s accounting, financial planning and budgeting, treasury, investor relations and

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strategy functions. Mr. Smith was President and Chief Operating Officer — Corporate Services for NiSource Inc. from November 2000 to January 2003. He managed NiSource’s Shared Services Center and oversaw the company’s information technology, telecommunications, accounting, procurement, tax, real estate, benefits administration and payroll organizations. Prior to joining NiSource, Mr. Smith was 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 1997 to 1999.

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TAX CONSIDERATIONS

The tax consequences to you of an investment in our common units 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 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 common units in this offering and own them through the record date for the distribution for the fourth quarter of 2006, we estimate that you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 30% 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 less than 25% 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 $0.5625 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 prospectus accompanying this prospectus supplement.

Ownership of 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 prospectus accompanying this prospectus supplement.

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UNDERWRITING

Citigroup Global Markets Inc. is acting as representative of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus supplement, which we will file as an exhibit to our current report on Form 8-K relating to this offering, each underwriter named below has agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name.


		Number of
Underwriter		Common Units

Citigroup Global Markets Inc.
Lehman Brothers Inc.
A.G. Edwards & Sons, Inc.
UBS Securities LLC
Wachovia Capital Markets, LLC
Friedman, Billings, Ramsey & Co., Inc.
RBC Capital Markets Corporation
Sanders Morris Harris Inc.

	Total		4,600,000

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all of the common units (other than those covered by the over-allotment option described below) if they purchase any of the common units.

The underwriters propose to offer some of the common units directly to the public at the public offering price set forth on the cover page of this prospectus supplement and some of the units to dealers at the public offering price less a concession not to exceed $ per common unit. The underwriters may allow, and dealers may reallow, a concession not to exceed $ per common unit on sales to other dealers. If all of the common units are not sold at the initial offering price, the representatives may change the public offering price and the other selling terms.

We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus supplement, to purchase up to 690,000 additional common units at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment.

We, our general partner, certain affiliates of our general partner, certain officers and directors of our general partner, the WPP Group and Arch Coal have agreed not to directly or indirectly sell, offer to sell, grant any option for the sale of or otherwise dispose of or hedge any common units or any securities convertible into or exercisable or exchangeable for common units, other than pursuant to employee benefit plans, including our general partner’s long-term incentive plan, for a period of 90 days from the date of this prospectus supplement, without the prior written consent of Citigroup Global Markets Inc. The foregoing will not apply to the redemption of common units owned by Arch Coal or Great Northern Properties Limited Partnership in connection with the offering. The foregoing will also not restrict the ability of such persons to pledge such securities in connection with a bona fide loan or transfer such securities to affiliates of our general partner provided that such affiliates agree to be bound by the foregoing restrictions. These agreements do not apply to accretive acquisitions of assets, businesses or the capital stock or other ownership interests of businesses by us in exchange for common units if the recipient of such common units agrees not to dispose of any common units received in connection with the acquisition during that period. Citigroup Global Markets Inc., in its sole discretion, may release any of the common units subject to these lock-up agreements at any time without notice.

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Citigroup Global Markets Inc. has informed us that they have no present intent or arrangement to release any of the 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 common units and whether the person seeking the release is an officer, director or affiliate of us or our general partner.

Our common units are listed on the New York Stock Exchange under the symbol “NRP.”

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.


		No Exercise	Full Exercise

Per common unit		$	$
	Total	$	$

In connection with the offering, Citigroup Global Markets Inc., on behalf of the underwriters, may purchase and sell common units in the open market. These transaction may include short sales, syndicate covering transactions and stabilizing transactions. Short sales involve syndicate sales of common units in excess of the number of common units to be purchased by the underwriters in the offering, which creates a syndicate short position. “Covered” short sales are sales of common units made in an amount up to the number of common units represented by the underwriters’ over-allotment option. In determining the source of units to close out the covered syndicate short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase units through the over-allotment option. Transactions to close out the covered syndicate short involve either purchases of the common units in the open market after the distribution has been completed or the exercise of the over-allotment option. The underwriters may also make “naked” short sales of common units in excess of the over-allotment option. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of bids for or purchases of common units in the open market while the offering is in progress.

The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when Citigroup Global Markets Inc. repurchases common units originally sold by that syndicate member in order to cover syndicate short positions or make stabilizing purchases.

Any of these activities may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the New York Stock Exchange or in the over-the-counter market, or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

We estimate that our total expenses of this offering, excluding underwriting discounts and commissions, will be $400,000.

Some of the underwriters have performed investment banking and advisory services for us and our general partner and its affiliates from time to time for which they have received customary fees and expenses. The underwriters may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business. Affiliates of Citigroup Global Markets Inc. and Wachovia Capital Markets, LLC are lenders under our revolving credit facility and will be repaid with a portion of the net proceeds from this offering.

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This prospectus supplement and the accompanying 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 participating in this offering or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than this prospectus supplement and the accompanying prospectus in electronic format, information contained in any other web site maintained by an underwriter is not part of this prospectus supplement or the accompanying prospectus or registration statement of which this prospectus supplement and the accompanying prospectus forms a part, has not been endorsed by us and should not be relied on by investors in deciding whether to purchase any units. The underwriters are not responsible for information contained in web sites that they do not maintain.

We, GP Natural Resource Partners LLC, our general partner and our operating company have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Because the NASD views our common units as interests in a direct participation program, any offering of common 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 common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

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LEGAL

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

Ernst & Young LLP, independent auditors, have audited the following financial statements included in our annual report on Form 10-K for the year ended December 31, 2003, as set forth in their reports:


	•	the consolidated financial statements of Natural Resource Partners L.P. for the year ended December 31, 2003 and for the period from commencement of operations (October 17, 2002) to December 31, 2002;

	•	the consolidated balance sheets of NRP (GP) LP as of December 31, 2003 and 2002; and

	•	the financial statements of each of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation for the period from January 1, 2002 through October 16, 2002 and for the year ended December 31, 2001; and

	•	the statements of revenues and direct costs and expenses of the Arch Coal Contributed Properties for the period from January 1, 2002 through October 16, 2002 and the year ended December 31, 2001.

The reports of Ernst & Young LLP are incorporated by reference in this prospectus supplement. Our 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.

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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:


	•	the cost of acquiring new coal reserves;

	•	the ability to acquire coal reserves on satisfactory terms;

	•	the prices for which coal from our properties can be sold;

	•	the volatility of commodity prices for coal;

	•	our ability to lease new and existing coal reserves;

	•	the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves;

	•	the ability of our lessees to obtain favorable sales contracts for coal produced from our reserves;

	•	competition among producers in the coal industry generally;

	•	the extent to which the amount and quality of actual production differs from estimated coal reserves;

	•	unanticipated geologic problems;

	•	availability of required materials and equipment;

	•	the occurrence of unusual weather events, accidents, changes in governmental regulation, equipment failures, transportation delays, labor-related interruptions or adverse operating conditions, including force majeure;

	•	the timing of receipt by our lessees of necessary governmental permits;

	•	the outcome of several ongoing environmental lawsuits relating to federal and state regulation of and permitting for the mining industry;

	•	our lessees’ labor relations and costs;

	•	changes in governmental regulation or enforcement practices, especially with respect to mining environmental, health and safety matters, such as emissions levels applicable to coal-burning power generators and steel manufacturers;

	•	the experience and financial condition of our lessees, including their ability to satisfy their royalty, environmental, reclamation and other obligations;

	•	fluctuations in transportation costs and the availability or reliability of transportation of coal from our properties;

	•	any future announcements of production cuts or implementation of previously announced cuts by our lessees;

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	•	a decrease in the demand for coal by the electricity generation or steel production industries;

	•	any increase or decrease in coal imports or exports; and

	•	risks and uncertainties relating to general domestic and international economic (including inflation and interest rates) and political conditions.

Many of such factors are beyond our ability to control or predict. Readers are cautioned 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 information we incorporate by reference is part of this prospectus and later information that we file with the SEC (excluding any information furnished pursuant to Item 9 or Item 12 on any Current Report on Form 8-K) will automatically update and supersede this information. We incorporate by reference the documents listed below:


	•	Annual Report on Form 10-K for the year ended December 31, 2003;

	•	Current Reports on Form 8-K filed on January 5, 2004, January 8, 2004 (excluding Item 9 and 12 information), January 22, 2004, February 12, 2004 (excluding Item 9 and 12 information) and March 5, 2004; and

	•	The description of our common units contained in our Form 8-A initially filed September 27, 2002, and any subsequent amendment thereto filed for the purpose of updating such description.

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


	Natural Resource Partners L.P.
	601 Jefferson Street
	Suite 3600
	Houston, Texas 77002
	Attention: Investor Relations Department
	Telephone: (713) 751-7555


	We also make available free of charge on our internet website at http://www.nrplp.com our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments to those reports, 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.

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PROSPECTUS

$500,000,000

Natural Resource Partners L.P.

Common Units

Debt Securities

NRP (Operating) LLC

Debt Securities

We may offer the following securities under this prospectus:


•	Common units representing limited partner interests in Natural Resource Partners L.P.;

•	Debt securities of Natural Resource Partners L.P.; and

•	Debt securities of NRP (Operating) LLC.

Any debt securities issued by Natural Resource Partners L.P. may be guaranteed by its subsidiaries, including NRP (Operating) LLC, and any debt securities issued by NRP (Operating) LLC may be guaranteed both by its parent, Natural Resource Partners L.P., and the issuer’s subsidiaries.

In addition, up to 673,715 common units may be offered from time to time on behalf of other unitholders. A supplement to this prospectus will identify any selling unitholders and specify the number of common units to be offered by them. We will not receive proceeds of any sale of units by any such selling unitholders, unless otherwise indicated in a prospectus supplement. For a more detailed discussion of selling unitholders, please read “Selling Unitholders.”

This prospectus describes the general terms of these securities and the general manner in which we or the selling unitholders will offer the securities. The specific terms of any securities we or the selling unitholders offer will be included in a supplement to this prospectus. The prospectus supplement will also describe the specific manner in which we or the selling unitholders will offer the securities.

Our common units are traded on the New York Stock Exchange under the symbol “NRP.”

Limited partnerships are inherently different from corporations. You should carefully consider each of the factors described under “Risk Factors,” which begins on page 3 of this prospectus, before you make an investment in the 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 February 10, 2004.

TABLE OF CONTENTS


ABOUT THIS PROSPECTUS		1
ABOUT NATURAL RESOURCE PARTNERS AND NRP (OPERATING) LLC		1
THE GUARANTORS		1
RISK FACTORS		3
Risks Related to Our Business		3
	We may not have sufficient cash from operations to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner	3
	A substantial or extended decline in coal prices could reduce our coal royalty revenues	4
	Our lessees’ coal mining operations are subject to operating risks that could result in lower coal royalty revenues to us	4
	We depend on a limited number of primary operators for a significant portion of our coal royalty revenues, and the loss of or reduction in production from any of our major operators could reduce our coal royalty revenues	4
	We may not be able to terminate our leases, and we may experience delays and be unable to replace lessees that do not make royalty payments	5
	If our lessees do not manage their operations well, their production volumes and our coal royalty revenues could decrease	5
	Adverse developments in the coal industry could reduce our coal royalty revenues and, due to our lack of asset diversification, could substantially reduce our total revenues	5
	Any decrease in the demand for metallurgical coal could result in lower coal production by our lessees, which would reduce our coal royalty revenues	5
	We may not be able to expand and our business will be adversely affected if we are unable to replace or increase our reserves or obtain other mineral reserves through acquisitions	6
	Any change in fuel consumption patterns by electric power generators resulting in a decrease in the use of coal could result in lower coal production by our lessees, which would reduce our coal royalty revenues	6
	Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts with terms of one year or more, which could adversely affect the stability and profitability of their operations and adversely affect our coal royalty revenues	6
	Competition within the coal industry may adversely affect the ability of our lessees to sell coal, and excess production capacity in the industry could put downward pressure on coal prices	7
	Lessees could satisfy obligations to their customers with coal from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments	7
	Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from our properties	8
	Our reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of our reserves	8
	Our lessees’ work forces could become increasingly unionized in the future	8
Regulatory and Legal Risks		8
	Our lessees are subject to federal, state and local laws and regulations that may limit their ability to produce and sell coal from our properties	8
	A substantial portion of our coal has a high sulfur content. This coal may become more difficult to sell because the Clean Air Act restricts the ability of electric utilities to burn high sulfur coal	9
	The Clean Air Act affects the end-users of coal and could significantly affect the demand for our coal and reduce our coal royalty revenues	9


We may become liable under federal and state mining statutes if our lessees are unable to pay mining reclamation costs		11
The increasing cost and lack of availability of reclamation bonds that are purchased by our lessees could make it uneconomic or impossible to mine our coal		11
Restructuring of the electric utility industry could lead to reduced coal prices		11
A new lawsuit challenging the legality of an important mining permit could adversely affect our lessees’ ability to produce coal from our reserves		11
We could become liable under federal and state Superfund and waste management statutes		12
Risks Related to Our Partnership Structure		12
	The WPP Group and Arch Coal may engage in substantial competition with us	12
	The WPP Group, Arch Coal and their affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit them to favor their own interests to your detriment	13
	Even if unitholders are dissatisfied, they cannot easily remove our general partner	14
	The control of our general partner may be transferred to a third party without unitholder consent	15
	Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to unitholders	15
	We may issue additional common units without your approval, which would dilute your existing ownership interests	15
	Cost reimbursements due our general partner may be substantial and will reduce the cash available for distribution to you	16
	Our general partner has a limited call right that may require you to sell your units at an undesirable time or price	16
	Your liability may not be limited if a court finds that unitholder action constitutes control of our business	17
Risks Related to the Debt Securities		17
	Both we and NRP (Operating) have a holding company structure in which our subsidiaries conduct our operations and own our operating assets	17
	We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service the debt securities or to repay them at maturity	17
Tax Risks to Common Unitholders		18
	The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to you	18
	A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will be borne by our unitholders and our general partner	18
	You may be required to pay taxes on income from us even if you do not receive any cash distributions from us	18
	Tax gain or loss on disposition of common units could be different than expected	19
	Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them	19
	We are registered as a tax shelter. This may increase the risk of an IRS audit of us or you	19
	We will treat each purchaser of common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units	20
	You will likely be subject to state and local taxes in states where you do not live as a result of an investment in units	20
USE OF PROCEEDS		20
RATIOS OF EARNINGS TO FIXED CHARGES		20


DESCRIPTION OF DEBT SECURITIES		21
	General	21
	The Guarantees	22
	Covenants	23
	Events of Default, Remedies and Notice	24
	Amendments and Waivers	26
	Satisfaction and Discharge	27
	Defeasance	27
	No Personal Liability of General Partner	28
	No Protection in the Event of a Change of Control	28
	Book Entry, Delivery and Form	28
	The Trustee	30
	Governing Law	30
DESCRIPTION OF THE COMMON UNITS		30
	Status as Limited Partner or Assignee	30
	Transfer of Common Units	30
	Limited Liability	31
	Meetings; Voting	32
	Books and Reports	33
	Summary of Partnership Agreement	34
CASH DISTRIBUTIONS		34
	Distributions of Available Cash	34
	Operating Surplus and Capital Surplus	34
	Subordination Period	35
	Distributions of Available Cash from Operating Surplus During the Subordination Period	37
	Distributions of Available Cash from Operating Surplus After the Subordination Period	37
	Incentive Distribution Rights	37
	Percentage Allocations of Available Cash from Operating Surplus	38
	Distributions from Capital Surplus	38
	Adjustment of Minimum Quarterly Distribution and Target Distribution Levels	39
	Distributions of Cash Upon Liquidation	39
MATERIAL TAX CONSEQUENCES		41
	Partnership Status	42
	Limited Partner Status	43
	Tax Consequences of Unit Ownership	44
	Tax Treatment of Operations	48
	Disposition of Common Units	50
	Uniformity of Units	52
	Tax-Exempt Organizations and Other Investors	53
	Administrative Matters	54
	State, Local and Other Tax Considerations	56
INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS		56
SELLING UNITHOLDERS		57
PLAN OF DISTRIBUTION		58
	Distribution by Natural Resource Partners	58

iii


	Distribution by Selling Unitholders	59
WHERE YOU CAN FIND MORE INFORMATION		59
FORWARD-LOOKING STATEMENTS		60
LEGAL MATTERS		61
EXPERTS		61

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 unitholders have authorized anyone else to give you different information. Neither we nor the selling unitholders are offering these securities in any state that does not permit the offer. 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.

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we have filed with the Securities and Exchange Commission using a “shelf” registration process. Under this shelf registration process, we may sell up to $500 million in aggregate offering price of the common units or debt securities described in this prospectus in one or more offerings, and the selling unitholders may sell up to an aggregate of 673,715 common units from time to time. This prospectus generally describes Natural Resource Partners L.P. and NRP (Operating) LLC and the common units, debt securities and the guarantees of the debt securities. Each time we or the selling unitholders sell common units or debt securities with this prospectus, we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add to, update or change information in this prospectus. The information in this prospectus is accurate as of December 23, 2003. Therefore, you should carefully read this prospectus and any prospectus supplement and the additional information described under the heading “Where You Can Find More Information” before you invest in our securities.

ABOUT NATURAL RESOURCE PARTNERS AND NRP (OPERATING) LLC

Natural Resource Partners L.P. was formed in 2002 by Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership and New Gauley Coal Corporation (which we refer to in this prospectus as the “WPP Group”) and Arch Coal, Inc. to engage 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. We enter into long-term leases with third-party mine operators for the right to mine our coal reserves in exchange for royalty payments. We conduct all of our business through our wholly owned operating company, NRP (Operating) LLC, and its wholly owned subsidiaries, WPP LLC, ACIN LLC and WBRD LLC.

On December 22, 2003, Arch Coal sold the following interests:


	•	all of its interests in GP Natural Resource Partners LLC, the general partner of our general partner, to Robertson Coal Management LLC;

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

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

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

Our address is 601 Jefferson, Suite 3600, Houston, Texas 77002, and our telephone number is (713) 751-7507. Our website address is www.nrplp.com. The information contained in our website is not part of this prospectus.

As used in this prospectus, “we,” “us,” “our” and “Natural Resource Partners” mean Natural Resource Partners L.P. and, where the context requires, our operating company, NRP (Operating) LLC, and its subsidiaries.

THE GUARANTORS

NRP (Operating) LLC, WPP LLC, ACIN LLC and WBRD LLC are our only subsidiaries as of the date of this prospectus. We own 100% of the membership interests in NRP (Operating) LLC. NRP (Operating) LLC owns 100% of the membership interests in WPP LLC, ACIN LLC and WBRD LLC.

Natural Resource Partners, WPP LLC, ACIN LLC and WBRD LLC may unconditionally guarantee any series of debt securities of NRP (Operating) LLC offered by this prospectus, as set forth in a related prospectus supplement. NRP (Operating) LLC, WPP LLC, ACIN LLC and WBRD LLC may unconditionally guarantee any series of debt securities of Natural Resource Partners offered by this prospectus, as set forth in a related prospectus supplement.

As used in this prospectus, the term “Subsidiary Guarantors” means WPP LLC, ACIN LLC and WBRD LLC and also includes NRP (Operating) LLC when discussing subsidiary guarantees of the debt securities of Natural Resource Partners. The term “Guarantor” means Natural Resource Partners in its role as guarantor of the debt securities of NRP (Operating) LLC.

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 common units or our debt securities. When we offer and sell any securities pursuant to a prospectus supplement, we may include additional risk factors relevant to those securities in a 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 operation could be adversely affected, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business


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

The amount of cash we can distribute on our units principally depends upon the amount of royalties we receive from our lessees, which will fluctuate from quarter to quarter based on, among other things:


	•	the amount of coal our lessees are able to produce from our properties;

	•	the price at which our lessees are able to sell coal;

	•	the level of our operating costs;

	•	the level of our general and administrative costs; and

	•	prevailing economic conditions.

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


	•	the costs of acquisitions, if any;

	•	our debt service requirements;

	•	fluctuations in our working capital;

	•	the level of capital expenditures we make;

	•	restrictions on distributions contained in our debt instruments;

	•	our ability to borrow under our working capital facility to pay distributions; and

	•	the amount of cash reserves established by our general partner in its sole discretion in the conduct of our business.

You should also be aware that our ability to pay quarterly distributions each quarter depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not make distributions during periods when we record net income.


	*A substantial or extended decline in coal prices could reduce our coal royalty revenues.*

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


	•	the supply of and demand for domestic and foreign coal;

	•	weather conditions;

	•	the proximity to and capacity of transportation facilities;

	•	worldwide economic conditions;

	•	domestic and foreign governmental regulations and taxes;

	•	the price and availability of alternative fuels; and

	•	the effect of worldwide energy conservation measures.

A substantial or extended decline in coal prices could materially and adversely affect us in two ways. First, lower prices may reduce the quantity of coal that may be economically produced from our properties. This, in turn, could reduce our coal royalty revenues and the value of our coal reserves. Second, even if production is not reduced, the royalties we receive on each ton of coal sold may be reduced.


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

Our coal royalty revenues are largely dependent on our lessees’ level of production from our coal reserves. The level of our lessees’ production is subject to operating conditions or events beyond their or our control including:


	•	the inability to acquire necessary permits or mining or surface rights;

	•	changes or variations in geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;

	•	changes in governmental regulation of the coal industry or the electric utility industry;

	•	mining and processing equipment failures and unexpected maintenance problems;

	•	interruptions due to transportation delays;

	•	adverse weather and natural disasters, such as heavy rains and flooding;

	•	labor-related interruptions; and

	•	fires and explosions.

These conditions may increase our lessees’ cost of mining and delay or halt production at particular mines for varying lengths of time or permanently. Any interruptions to the production of coal from our reserves may reduce our coal royalty revenues.


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

We depend on a limited number of primary operators for a significant portion of our coal royalty revenues. If reductions in production by these operators are implemented on our properties and sustained, our revenues may be substantially affected. Additionally, if a lessee were to experience financial difficulty, the lessee might not be able to pay its royalty payments or continue its operations, which could materially reduce our coal royalty revenues.


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

A failure on the part of one of our lessees to make coal royalty payments could give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement lessee. We might not be able to find a replacement lessee and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced. In addition, it may be difficult for us to secure new or replacement lessees for small or isolated coal reserves, since industry trends toward consolidation favor larger-scale, higher-technology mining operations in order to increase productivity.


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

We depend on our lessees to effectively manage their operations on our properties. Our lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to:


	•	marketing of the coal mined;

	•	mine plans, including the amount to be mined and the method of mining;

	•	processing and blending coal;

	•	credit risk of their customers;

	•	permitting;

	•	insurance and surety bonding;

	•	acquisition of surface rights and other mineral estates;

	•	employee wages;

	•	coal transportation arrangements;

	•	compliance with applicable laws, including environmental laws;

	•	negotiations and relations with unions; and

	•	mine closure and reclamation.

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


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

Our coal royalty business generates substantially all of our revenues. Due to our lack of asset diversification, an adverse development in the coal industry would have a significantly greater impact on our financial condition and results of operations than if we owned more diverse assets.


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

Our lessees produce a significant amount of the metallurgical coal that is used in both the U.S. and foreign steel industries. In 2002, approximately 16.2% of the coal production from our properties was 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.


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

Because our reserves decline as our lessees mine our coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves or other mineral reserves that are economically recoverable. If we are unable to replace or increase our coal reserves or acquire other mineral reserves on acceptable terms, our royalty revenues will decline as our reserves are depleted. In addition, if we are unable to successfully integrate the companies, businesses or properties we are able to acquire, our royalty revenues may decline and we could experience a material adverse effect on our business, financial condition or results of operations. If we acquire additional reserves, there is a possibility that any acquisition could be dilutive to our earnings and reduce our ability to make distributions to unitholders. Any debt we incur to finance an acquisition may also reduce our ability to make distributions to unitholders. Our ability to make acquisitions in the future also could be limited by restrictions under our existing or future debt agreements, competition from other mineral companies for attractive properties or the lack of suitable acquisition candidates.


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

Domestic electric power generation accounts for approximately 90% of domestic coal consumption. The amount of coal consumed for domestic electric power generation is affected primarily by the overall demand for electricity, the price and availability of competing fuels for power plants such as natural gas, nuclear, fuel oil and hydroelectric power and environmental and other governmental regulations. We expect new power plants will be built to produce electricity. Many of these new power plants will likely be fired by natural gas because of lower construction costs compared to coal-fired plants and because natural gas is a cleaner burning fuel. The increasingly stringent requirements of the federal Clean Air Act may result in more electric power generators shifting from coal to natural-gas-fired power plants.


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

As electric utilities adjust to the Phase II requirements of the Clean Air Act and the possible deregulation of their industry, they are becoming increasingly less willing to enter into coal supply contracts with terms of more than one year. Instead, these utilities are purchasing higher percentages of coal on the spot market. The industry shift away from long-term supply contracts could adversely affect our lessees, and the level of our coal royalty revenues, in several ways. First, fewer electric utilities will have a contractual obligation to purchase coal from our lessees, thereby increasing the risk that our lessees will not have a market for their coal production. Second, the prices our lessees receive in the spot market may be less than a contractual price an electric utility is willing to pay for a committed supply. Finally, spot market prices tend to be more volatile than contractual prices, which could result in decreased coal royalty revenues and adversely affect our ability to pay distributions in any one quarter.

In addition, price adjustment, price reopener and other similar provisions in supply contracts with terms of one year or more may reduce the protection from short-term coal price volatility traditionally provided by these contracts. Some coal supply contracts contain provisions that allow for the price at which coal is purchased to be renegotiated at periodic intervals. These price reopener provisions may

automatically set a new price based on the prevailing market price or, in some instances, require the parties to agree on a new price. In some circumstances, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Any adjustment or renegotiation leading to a significantly lower contract price could result in decreased coal royalty revenues. Accordingly, even supply contracts with terms of one year or more may provide only limited protection if adverse market conditions occur.

Some supply contracts also contain provisions that allow the customer to suspend or terminate performance under the contract upon the occurrence or continuation of specified events. These events typically include:


	•	the inability of our lessees to deliver the volume or qualities of coal specified;

	•	changes in government regulations that render use of coal inconsistent with the customer’s pollution control strategies; and

	•	the occurrence of events beyond the reasonable control of the affected party, including labor disputes, mechanical malfunctions, transportation disruptions and changes in government regulations.


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

Our lessees compete with numerous other coal producers in various regions of the United States for domestic sales. During the mid-1970s and early 1980s, increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in additional production capacity throughout the industry, all of which led to increased competition and lower coal prices. Any increases in coal prices could also encourage the development of expanded capacity by new or existing coal producers. Any resulting overcapacity could reduce coal prices and therefore reduce our coal royalty revenues.

Competition from coal with lower production costs shipped east from western coal mines has resulted in increased competition for coal sales from the Appalachian region and the Illinois Basin. This competition could result in a decrease in market share for our lessees operating in these regions and a decrease in our coal royalty revenues.

The amount of coal exported from the United States has declined over the last few years due to adverse economic conditions in Asia and the higher relative cost of U.S. coal due to the strength of the U.S. dollar. This decline could cause competition among coal producers in the United States to intensify, potentially resulting in additional downward pressure on coal prices.

Conversely, the amount of coal imported into the United States over the last few years has increased. This increase is mostly due to the economic and environmental advantages of some imported coal. A continued increase in imported coal could result in less of our coal being mined and sold and reduce our coal royalty revenues. Additionally, lower priced imported coal could result in lower on coal prices that would reduce our coal royalty revenues.


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

Coal supply contracts do not generally require operators to satisfy their obligations to their customers with coal mined from specific reserves. Several factors may influence a lessee’s decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the lessee’s lease with us, mining conditions, mining operations costs, cost and availability of transportation, and customer coal specifications. If a lessee satisfies its obligations to its customers with coal from properties we do not own or lease, production on our properties will decrease, and we will receive lower coal royalty revenues.


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

Transportation costs represent a significant portion of the total cost of coal for the customers of our lessees. Increases in transportation costs could make coal a less competitive source of energy or could make coal produced by some or all of our lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition for our lessees from coal producers in other parts of the country.

Our lessees depend upon railroads, barges, trucks and beltlines to deliver coal to their customers. Disruption of those transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and other events could temporarily impair the ability of our lessees to supply coal to their customers. Our lessees’ transportation providers may face difficulties in the future that may impair the ability of our lessees to supply coal to their customers, resulting in decreased coal royalty revenues to us.


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

Our reserve estimates may vary substantially from the actual amounts of coal our lessees may be able to economically recover from our reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions relate to:


	•	future coal prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs;

	•	future mining technology improvements;

	•	the effects of regulation by governmental agencies; and

	•	geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experiences in areas where our lessees currently mine.

Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. As a result, you should not place undue reliance on our coal reserve data that is incorporated by reference in this prospectus.


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

Some of the mines on our properties are operated by unionized employees of our lessees or their affiliates. Our lessees’ employees could become increasingly unionized in the future. Some labor unions active in our lessees’ areas of operations are attempting to organize the employees of some of our lessees. If some or all of our lessees’ non-unionized operations were to become unionized, it could adversely affect their productivity, increase costs and increase the risk of work stoppages. In addition, our lessees’ operations may be adversely affected by work stoppages at unionized companies, particularly if union 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.

Regulatory and Legal Risks


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

Our lessees may incur substantial costs and liabilities under increasingly strict federal, state and local environmental, health and safety and endangered species laws, including regulations and governmental

enforcement policies. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our lessees’ operations. Our lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their operations. If our lessees are pursued for these sanctions, costs and liabilities, their mining operations and, as a result, our coal royalty revenues could be adversely affected.

Some species indigenous to our properties are protected under the Endangered Species Act. Federal and state legislation for the protection of endangered species may have the effect of prohibiting or delaying our lessees from obtaining mining permits and may include restrictions on road building and other mining activities in areas containing the affected species. Additional species on our properties may receive protected status, and currently protected species may be discovered within our properties. Either event could result in increased costs to us or our lessees.

New environmental legislation, new regulations and new interpretations of existing environmental laws, including regulations governing permitting requirements and the protection of endangered species, could further regulate or tax the coal industry and may also require our lessees to change their operations significantly to incur increased costs or to obtain new or different permits, any of which could decrease our coal royalty revenues.


	A substantial portion of our coal has a high sulfur content. This coal may become more difficult to sell because the Clean Air Act restricts the ability of electric utilities to burn high sulfur coal.

Sulfur is a naturally occurring component of coal. In 1995, Phase I of the Clean Air Act required power plants to reduce their emissions of sulfur dioxide to the equivalent of approximately 2.5 pounds or less per million Btus. In 2000, Phase II of these regulations further restricted emissions to the equivalent of approximately 1.2 pounds of sulfur dioxide per million Btus. These restrictions may reduce the demand 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, 2002, 75% of our coal reserves were not compliance coal, which is low-sulfur coal that, when burned, emits no more than 1.2 pounds of sulfur dioxide per million Btus. If our lessees’ customers, or their potential customers in our market areas, choose not to purchase our noncompliance coal, our lessees may be unable to find other buyers for this coal at current price and volume levels, which could materially adversely affect our coal royalty revenues and our ability to make distributions to our unitholders.


	*The Clean Air Act affects the end-users of coal and could significantly affect the demand for our coal and reduce our coal royalty revenues.*

The Clean Air Act and corresponding state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides and other compounds emitted from industrial boilers and power plants, including those that use our coal. These regulations constitute a significant burden on coal customers and stricter regulation could adversely affect the demand for and price of our coal, especially higher sulfur coal, resulting in lower coal royalty revenues.

In July 1997, the U.S. Environmental Protection Agency, or “EPA,” adopted more stringent ambient air quality standards for particulate matter and ozone. Particulate matter includes small particles that are emitted during the coal combustion process. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA’s position, although it remanded the EPA’s ozone implementation policy for further consideration. On remand, the Court of Appeals for the D.C. Circuit affirmed the EPA’s adoption of these more stringent ambient air quality standards. As a result of the finalization of these standards, states that have not attained these standards will have to revise their State Implementation Plans to include provisions

for the control of ozone precursors and particulate matter. Revised State Implementation Plans could require electric power generators to further reduce nitrogen oxide and particulate matter emissions. The potential need to achieve these emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other by-products of coal combustion could restrict the market for coal and the development of new mines by our lessees. This, in turn, may result in decreased production by our lessees and a corresponding decrease in our coal royalty revenues.

Furthermore, in October 1998, the EPA finalized a rule that will require 19 states in the Eastern United States that have ambient air quality problems to make substantial reductions in nitrogen oxide emissions by the year 2004. To achieve these reductions, many power plants will be required to install additional control measures. The installation of these measures will make it more costly to operate coal-fired power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel.

Additionally, the U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against a number of investor-owned electric utilities and brought an administrative action against one government-owned electric utility for alleged violations of the Clean Air Act. The EPA claims that the power plants operated by these utilities have failed to obtain permits required under the Clean Air Act for facility modifications. Our lessees supply coal to some of the affected utilities, and it is possible that other of our lessees’ customers will be sued. These lawsuits could require the affected utilities to pay penalties and install pollution control equipment or undertake other emission reduction measures, which could adversely affect their demand for coal. In fact, settlements between the EPA and several utilities related to these alleged violations have resulted in the retirement of some facilities and additional capital expenditures at others. Any outcome that adversely affects our lessees’ customers and their demand for coal could adversely affect our coal royalty revenues.

Other proposed initiatives may have an effect upon our lessees’ coal operations. One such proposal is the Bush Administration’s Clear Skies Initiative, which was announced in February 2002 and introduced into the U.S. House and Senate in February 2003 as the Clear Skies Act of 2003. As proposed, this initiative is designed to reduce emissions of sulfur dioxide, nitrogen oxides and mercury from power plants. Other so-called multi-pollutant bills that could regulate additional air pollutants, including carbon dioxide, have been proposed in Congress. While the details of all of these proposed initiatives vary, there appears to be a movement towards increased regulation of a number of power plant air pollutants. If these initiatives were enacted into law, power plants could choose to shift away from coal as a fuel source to meet these requirements.

The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, which is intended to limit emissions of greenhouse gases, such as carbon dioxide. In December 1997, the signatories to the convention established a set of emission reduction targets for developed nations including the United States, commonly known as the Kyoto Protocol. The United States, however, has not ratified the treaty commitments, the current administration has withdrawn support for this treaty, and no comprehensive federal regulations focusing on greenhouse emissions are in place. Nevertheless, restrictions on greenhouse gas emissions, whether through ratification of the Kyoto protocol or other efforts to stabilize or reduce gas emissions, including initiatives being considered by several states, could adversely affect the price and demand for coal.

The Clean Air Act also imposes standards on sources of hazardous air pollutants. The EPA has announced that it will regulate hazardous air pollutants from coal-fired power plants. Under the Clean Air Act, coal-fired power plants may be required to control hazardous air pollution emissions by approximately 2009. These controls are likely to require significant new investments in controls by power plant owners. Like other environmental regulations, these standards and future standards could result in a decreased demand for coal.


	*We may become liable under federal and state mining statutes if our lessees are unable to pay mining reclamation costs.*

The Surface Mining Control and Reclamation Act of 1977, or SMCRA, and state statutes adopted pursuant to SMCRA impose various permitting and operational requirements on mine operators. In addition, SMCRA assigns to operators the responsibility of restoring the land to its approximate original contour or compensating the surface owner for types of damages occurring as a result of mining operations, and requires mine operators to post performance bonds to ensure compliance with any reclamation obligations. Regulatory authorities may attempt to assign the liabilities of our lessees to us if any of our lessees are not financially capable of fulfilling those obligations.


	*The increasing cost and lack of availability of reclamation bonds that are purchased by our lessees could make it uneconomic or impossible to mine our coal.*

In order to satisfy obligations imposed by SMCRA and state statutes, each of our lessees is required to post a reclamation bond at the time its permit to mine coal is issued. The purpose of the bond is to ensure that all reclamation work will be completed on the mine site and the amount of the bond is determined by the regulatory authority issuing the permit. Due to conditions in the insurance industry following September 11, 2001, the number of companies issuing reclamation bonds has declined substantially. As a result, the cost of these bonds has increased and in some instances the bonds are not available to mining companies. If the cost of these bonds were to increase to a level that resulted in our coal becoming uneconomic to mine, our coal royalty revenues could decline substantially.


	*Restructuring of the electric utility industry could lead to reduced coal prices.*

A number of states and the District of Columbia have passed legislation to allow retail price competition in the electric utility industry. If ultimately implemented at both the state and federal levels, restructuring of the electric utility industry is expected to compel electric utilities to be more aggressive in developing and defending market share, to be more focused on their pricing and cost structures and to be more flexible in reacting to changes in the market. We believe that a fully competitive electricity market may put downward pressure on fuel prices, including coal, because electric utilities will be competing with other suppliers and will no longer necessarily be able to pass increased fuel costs on to their customers. In addition, some of these initiatives may or do mandate the increased use of alternative or renewable fuels as alternatives to burning fossil fuels. Lower coal prices or mandatory use of alternative fuels could reduce our lessees’ coal production and our coal royalty revenues.


	*A new lawsuit challenging the legality of an important mining permit could adversely affect our lessees’ ability to produce coal from our reserves.*

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

The most recent lawsuit alleges that a nationwide permit cannot lawfully be issued under Section 404 for the surface mining of coal and that the Corps of Engineers failed to comply with the requirements of the National Environmental Policy Act in the adoption of Nationwide Permit 21. If the plaintiffs were successful, the district court could enjoin further discharges pursuant to Nationwide Permit 21 at those operations that have received authorizations under that permit and could require coal miners to obtain

individual permits under Section 404 of the Clean Water Act to discharge into fills in the future. Obtaining individual permits for fills is likely to be more costly and more time consuming than filing under a nationwide permit. As a result, our lessees’ coal mining costs could increase and they could mine less coal, which would adversely affect our coal royalty revenues.


	*We could become liable under federal and state Superfund and waste management statutes.*

The Comprehensive Environmental Response, Compensation and Liability Act, known as CERCLA or “Superfund,” and similar state laws create liabilities for the investigation and remediation of releases and threatened releases of hazardous substances to the environment and damages to natural resources. As landowners, we are potentially subject to liability for these investigation and remediation obligations.

Risks Related to Our Partnership Structure


	*The WPP Group and Arch Coal may engage in substantial competition with us*

We rely on the employees of our general partner’s affiliates, including the WPP Group, to conduct our business. Although the WPP Group and Arch Coal 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 Arch Coal to engage in substantial competition with us should they choose to do so. The restrictions on Arch Coal’s ability to compete with us are materially less burdensome than the restrictions on the WPP Group. The partnership agreement provides that engaging in competitive activities by Arch Coal and the WPP Group 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 Arch Coal or the WPP Group competes 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 Arch Coal 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 Arch Coal include the following:


	•	The WPP Group or Arch Coal may lease their owned coal reserves within the United States to affiliates. For example, Arch Coal or an Arch Coal subsidiary may acquire new coal reserves and lease them directly to an operating subsidiary of Arch Coal and collect royalties on the lease without offering us the opportunity to acquire these reserves.

	•	The WPP Group or Arch Coal may compete with us as long as the fair market value of the assets of any competing business are $10 million or less; provided, that with respect to the WPP Group, the total value of all competing businesses do not exceed $75 million. In addition, with respect to the WPP Group, any coal reserves that are owned and unleased at the time of the closing of the offering that are subsequently leased to third parties will not be considered in calculating the $75 million limitation.

	•	In certain circumstances, the WPP Group and Arch Coal will be required to offer a competing business to us for purchase, but if they make a good faith decision in their sole discretion not to accept our offer, they will be able to continue to own and operate the business in competition with us. There is no provision in the omnibus agreement requiring the WPP Group or Arch Coal to sell the business to us at a fair market value determined by a third party investment banking firm or appraiser.

	•	Arch Coal may buy an interest in a competing business that is a general partner interest or a managing member interest in a limited liability company provided it divests itself of such interest within six months of acquisition or it offers us the opportunity to buy its interest. If, however, Arch Coal is unable to divest its interest in the competing business within six months of acquisition despite a good faith, commercially reasonable attempt to do so, and Arch has not received an extension from our conflicts committee or has not offered us the opportunity to buy its competing


		interest, then Arch Coal may opt to either (1) have its designated directors immediately resign from the board of directors of our general partner, in which case Arch Coal may continue to own and operate the competing business but will continue to relinquish its rights to designate directors of our general partner until such time as it divests the competing business, or (2) hire an independent investment banking firm to determine the fair market value of the competing business. If Arch Coal elects to obtain an independent valuation of its competing business, then:


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

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

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


	•	There is no restriction on the ability of the WPP Group and Arch Coal to compete with us in the ownership and operation of other businesses, including the leasing of other mineral properties such as oil and gas and iron ore. It is our strategy to diversify into the acquisition of mineral properties in addition to coal properties.

	•	There is no restriction on the ability of the WPP Group and Arch Coal to own a noncontrolling equity interest in a competing business, including an economic stake that is greater than their stake in us.

If the WPP Group or Arch Coal, as applicable, ceases to participate in the control of our general partner, then it will no longer be bound by the noncompetition provisions of the omnibus agreement. Arch Coal will lose the right to designate two directors, and will no longer be subject to the omnibus agreement, when it ceases to hold at least 10% of our common units.

In addition, First Reserve GP IX, Inc., First Reserve Corporation and their affiliates may compete with us without any limitations.


	The WPP Group, Arch Coal, First Reserve and their affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit them to favor their own interests to your detriment.

The WPP Group and their affiliates own approximately 67% of our common and subordinated units and together own and control our general partner. In addition, FRC-WPP NRP Investment L.P., an affiliate of First Reserve GP IX, Inc., owns approximately 42% of our subordinated units and has the right to elect two directors to the board of GP Natural Resource Partners LLC. Although Arch Coal has sold its subordinated units and its interests in our general partners, it has retained the right to elect two directors to the board of directors of GP Natural Resource Partners LLC for so long as it continues to hold at least 10% of our common units. Conflicts of interest may arise between the WPP Group, Arch Coal and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of the unitholders. These conflicts include, among others, the following situations:


	•	Some officers of the WPP Group, who will provide services to us, will also devote significant time to the businesses of the WPP Group and will be compensated by the WPP Group for the services they provide.


	•	Neither the partnership agreement nor any other agreement requires the WPP Group, Arch Coal or First Reserve to pursue a business strategy that favors us. The directors and officers of the WPP Group have a fiduciary duty to make decisions in the best interests of the WPP Group’s limited partners and shareholders. Arch Coal’s directors and officers have a fiduciary duty to make decisions in the best interests of Arch Coal’s shareholders, and the directors of First Reserve GP IX, Inc. and its affiliates have a fiduciary duty to make decisions in the best interests of their shareholders and partners.

	•	As described above, the WPP Group, Arch Coal, First Reserve and their affiliates may engage in substantial competition with us.

	•	Our general partner is allowed to take into account the interests of parties other than us, such as the WPP Group and Arch Coal, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to the unitholders.

	•	Our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. As a result of purchasing units, you are deemed to consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.

	•	Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional limited partner interests and reserves, each of which can affect the amount of cash that is distributed to unitholders.

	•	Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

	•	Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

	•	Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates.

	•	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

	•	In some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to hasten the expiration of the subordination period.


	*Even if unitholders are dissatisfied, they cannot easily remove our general partner.*

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or the board of directors of GP Natural Resource Partners LLC and will have no right to elect our general partner or the board of directors of GP Natural Resource Partners LLC on an annual or other continuing basis.

The nine-member board of directors of GP Natural Resource Partners LLC is elected by Robertson Coal Management LLC, which is wholly owned by Corbin J. Robertson, Jr., our chief executive officer and chairman and an affiliate of the WPP Group. Arch Coal has the right to designate two members, and FRC-WPP NRP Investment L.P., which is indirectly controlled by First Reserve GP IX, Inc., has the right to designate two members of the board. Arch Coal will lose its right to designate directors when it ceases to hold at least 10% of our common units. FRC-WPP NRP Investment L.P. will lose its right to designate directors when it owns less than 5% of our issued and outstanding units, including both common and subordinated units, and less than 20% of its current holdings, which consist of 4,796,920 subordinated units. Although our general partner has a fiduciary duty to manage our business in a manner beneficial to us and the unitholders, the directors of GP Natural Resource Partners LLC have a fiduciary duty to manage the general partner in a manner beneficial to its sole member, Robertson Coal Management LLC.

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. First, our general partner generally may not be removed except upon the vote of the holders of at least 66 2/3% of the outstanding units voting together as a single class. Because affiliates of the general partner control approximately 67% of all the outstanding units, the general partner currently cannot be removed without the consent of the general partner and its affiliates. Also, if our general partner is removed without cause during the subordination period and units held by the general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholders’ dissatisfaction with the general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. In addition, the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence, the manner or direction of management.

As a result of these provisions, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the takeover price.


	*The control of our general partner may be transferred to a third party without unitholder consent.*

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owners of our general partner or its general partner, GP Natural Resource Partners LLC, from transferring their ownership interest in the general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers.


	*Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to unitholders.*

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will reduce the amount of cash available for distribution to unitholders.


	*We may issue additional common units without your approval, which would dilute your existing ownership interests.*

During the subordination period our general partner may cause us to issue up to 5,676,829 additional common units without your approval. Our general partner may also cause us to issue an unlimited number

of additional common units or other equity securities of equal rank with the common units, without your approval, in a number of circumstances, such as:


	•	the issuance of common units in connection with acquisitions or capital improvements that our general partner determines would increase cash flow from operations per unit on a pro forma basis;

	•	the conversion of subordinated units into common units;

	•	the conversion of units of equal rank with the common units into common units under some circumstances;

	•	the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal of our general partner;

	•	the issuance of common units under our incentive plans; or

	•	issuances of common units to repay up to $25 million of certain indebtedness.

After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of the unitholders. Our partnership agreement does not give the unitholders the right to approve our issuance at any time of equity securities ranking junior to the common units.

The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:


	•	your proportionate ownership interest in us will decrease;

	•	the amount of cash available for distribution on each unit may decrease;

	•	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by the common unitholders will increase;

	•	the relative voting strength of each previously outstanding unit may be diminished; and

	•	the market price of the common units may decline.


	*Cost reimbursements due our general partner may be substantial and will reduce the cash available for distribution to you.*

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including GP Natural Resource Partners LLC and the officers and directors of GP Natural Resource Partners LLC, for all expenses they incur on our behalf. The reimbursement of expenses could adversely affect our ability to pay cash distributions to you. Our general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us with other services for which we will be charged fees as determined by our general partner.


	*Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.*

If, at any time, our general partner and its affiliates own more than 80% of the common units then outstanding, our general partner has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units at a price not less than the then-current market price of the units. As a result, you may be required to sell your common units at an undesirable time or price and may therefore not receive any return on your investment. You may also incur tax liability upon a sale of your units.


	*Your liability may not be limited if a court finds that unitholder action constitutes control of our business.*

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. While our partnership is organized under Delaware law, we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for our obligations as if you were a general partner if:


	•	a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

	•	a court determines that your right to act with other unitholders to remove or replace the general partner, to approve some amendment to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Risks Related to the Debt Securities


	*Both we and NRP (Operating) have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.*

Both we and NRP (Operating) have a holding company structure, and our subsidiaries conduct all of our operations and own all of our operating assets. We and NRP (Operating) have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make required payments on the debt securities depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our and NRP (Operating)’s subsidiaries to make distributions to us and NRP (Operating) may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. Pursuant to our credit facilities, we or NRP (Operating) may be required to establish cash reserves for the future payment of principal and interest on the amounts outstanding under the credit facilities. If we or NRP (Operating) is unable to obtain the funds necessary to pay the principal amount at maturity of the debt securities, or to repurchase the debt securities upon the occurrence of a change of control, we or NRP (Operating), as the case may be, may be required to adopt one or more alternatives, such as a refinancing of the debt securities. We cannot assure you that we or NRP (Operating) would be able to refinance the debt securities.


	*We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service the debt securities or to repay them at maturity.*

Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our available cash to our unitholders of record and our general partner. Available cash is generally all of our cash receipts adjusted for cash distributions and net changes to reserves. Our general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating partnerships in amounts the general partner determines in its reasonable discretion to be necessary or appropriate:


	•	to provide for the proper conduct of our business and the businesses of our operating partnerships (including reserves for future capital expenditures and for our anticipated future credit needs),

	•	to provide funds for distributions to our unitholders and the general partner for any one or more of the next four calendar quarters, or

	•	to comply with applicable law or any of our loan or other agreements.

Although our payment obligations to our unitholders are subordinate to our payment obligations to debtholders, the value of our units will decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue equity to recapitalize.

Tax Risks to Common Unitholders

You should read “Material Tax Consequences” for a full discussion of the expected material federal income tax consequences of owning and disposing of common units.


	*The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to you.*

The after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you may be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. If we were treated as a corporation, there would be a material reduction in the after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units. Moreover, treatment of us as a corporation would materially and adversely affect our ability to make payments on our debt securities.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.


	A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will be borne by our unitholders and our general partner.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner, and these costs will reduce our cash available for distribution.


	*You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.*

You will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not

receive cash distributions from us equal to your share of our taxable income or even the tax liability that results from that income.


	*Tax gain or loss on disposition of common units could be different than expected.*

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.


	*Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.*

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds) and non-U.S. persons raises issues unique to them. For example, a significant amount of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, may be unrelated business taxable income and will be taxable to such a unitholder. Very little of our income will be qualifying income to a regulated investment company. Distributions to non-U.S. persons will be reduced by withholding tax at the highest effective tax rate applicable to individuals, and non-U.S. unitholders will be required to file federal income tax returns and pay tax on their share of our taxable income.


	*We are registered as a tax shelter. This may increase the risk of an IRS audit of us or you.*

We are registered with the IRS as a “tax shelter.” Our tax shelter registration number is 02247000042. The federal income tax laws require that some types of entities, including some partnerships, register as tax shelters in response to the perception that they claim tax benefits that may be unwarranted. As a result, we may be audited by the IRS and tax adjustments may be made. Any unitholder owning less than a 1% profit interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in your tax returns and may lead to audits of your tax returns and adjustments of items unrelated to us. You would bear the cost of any expense incurred in connection with an examination of your tax return.

Recently issued Treasury Regulations require taxpayers to report certain information on Internal Revenue Service Form 8886 if they participate in a “reportable transaction.” You may be required to file this form with the IRS if we participate in a “reportable transaction.” A transaction may be a reportable transaction based upon any of several factors. We urge you to consult with your own tax advisor concerning the application of any of these factors to your investment in our common units. Congress is considering legislative proposals that, if enacted, would impose significant penalties for failure to comply with these disclosure requirements. The Treasury Regulations also impose obligations on “material advisors” that organize, manage or sell interests in registered “tax shelters.” As stated above, we have registered as a tax shelter, and, thus, one of our material advisors will be required to maintain a list with specific information, including your name and tax identification number, and to furnish this information to the IRS upon request. We urge you to consult with your own tax advisor concerning any possible disclosure obligation with respect to your investment. You should be aware that we and our material advisors intend to comply with the list and disclosure requirements.


	We will treat each purchaser of common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of applicable Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the common unitholder’s tax returns.


	*You will likely be subject to state and local taxes in states where you do not live as a result of an investment in units.*

In addition to federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if you do not live in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We own assets and do business in Alabama, Georgia, Illinois, Indiana, Kentucky, Maryland, Montana, North Carolina, North Dakota, Virginia and West Virginia. Each of these states currently imposes a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

USE OF PROCEEDS

Except as otherwise provided in an applicable prospectus supplement, we will use the net proceeds we receive from the sale of the securities to pay all or a portion of our indebtedness outstanding at the time and to acquire assets as suitable opportunities arise. A prospectus supplement will describe the actual use of net proceeds from the sale of securities. Unless otherwise provided in a prospectus supplement, we will not receive any proceeds from the sale of common units by the selling unitholders.

RATIOS OF EARNINGS TO FIXED CHARGES

The ratios of earnings to fixed charges for each of Natural Resource Partners and NRP (Operating) LLC covering the periods indicated are as follows:


											January 1		October 17
	Year Ended December 31										through		through		Nine Months
											October 16,		December 31,		Ended September
	1997		1998		1999		2000		2001		2002		2002		30, 2003

Western Pocahontas Properties Limited Partnership		3.06		3.64		3.74		4.01		4.58		2.74
Great Northern Properties Limited Partnership		1.21		1.38		1.26		1.49		1.71		2.18
New Gauley Coal Corporation		0.97		6.86		7.05		5.21		9.15		4.68
Arch Coal Contributed Properties*
Natural Resource Partners L.P.														23.04		6.44


*	Information for Arch Coal Contributed Properties is not available

Ratios set forth in the table above relating to periods commencing prior to October 17, 2002 relate to our predecessors.

For purposes of calculating the ratio of earnings to fixed charges:


	•	“fixed charges” represent interest expense (including amounts capitalized), amortization of debt costs and the portion of rental expense representing the interest factor; and

	•	“earnings” represent the aggregate of income from continuing operations (before adjustment for minority interest, extraordinary loss and equity earnings), fixed charges and distributions from equity investment, less capitalized interest.

DESCRIPTION OF DEBT SECURITIES

The debt securities may be issued by Natural Resource Partners or NRP (Operating) LLC. Natural Resource Partners will issue debt securities under an indenture, among it, as issuer, and a trustee that we will name in the related prospectus supplement. NRP (Operating) LLC will issue debt securities under a separate indenture among itself, as issuer, and a trustee that we will name in the related prospectus supplement. Any Guarantor or Subsidiary Guarantors will also be parties to the indentures. The term “Trustee” as used in this prospectus refers to the trustee under either of the above indentures. References in this prospectus to an “Indenture “refer to the particular indenture under which Natural Resource Partners or NRP (Operating) LLC issues a series of debt securities. The debt securities will be governed by the provisions of the related Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939.

This description is a summary of the material provisions of the debt securities and the Indentures. We urge you to read the forms of Indentures filed as exhibits to the registration statement of which this prospectus is a part because those Indentures, and not this description, govern your rights as a holder of debt securities.

General


	*The Debt Securities*

Any series of debt securities:


	•	will be issued only in fully registered form;

	•	will be general obligations of the related issuer;

	•	will be general obligations of Natural Resource Partners if it guarantees debt securities issued by NRP (Operating) LLC; and

	•	will be general obligations of the Subsidiary Guarantors if they guarantee debt securities issued by Natural Resource Partners or NRP (Operating) LLC.

The Indenture does not limit the total amount of debt securities that may be issued. Debt securities under the Indenture may be issued from time to time in separate series, up to the aggregate amount authorized for each such series.

We will prepare a prospectus supplement and either an indenture supplement or a resolution of the board of directors of the general partner and accompanying officers’ certificate relating to any series of debt securities that Natural Resource Partners or NRP (Operating) LLC offers, which will include specific terms relating to some or all of the following:


	•	the form and title of the debt securities;

	•	the total principal amount of the debt securities;

	•	the date or dates on which the debt securities may be issued;

	•	the portion of the principal amount which will be payable if the maturity of the debt securities is accelerated;


	•	any right the issuer may have to defer payments of interest by extending the dates payments are due and whether interest on those deferred amounts will be payable;

	•	the dates on which the principal and premium, if any, of the debt securities will be payable;

	•	the interest rate which the debt securities will bear and the interest payment dates for the debt securities;

	•	any optional redemption provisions;

	•	any sinking fund or other provisions that would obligate the issuer to repurchase or otherwise redeem the debt securities;

	•	whether the debt securities are entitled to the benefits of any guarantees by the Subsidiary Guarantors;

	•	whether the debt securities may be issued in amounts other than $1,000 each or multiples thereof;

	•	any changes to or additional Events of Default or covenants; and

	•	any other terms of the debt securities.

This description of debt securities will be deemed modified, amended or supplemented by any description of any series of debt securities set forth in a prospectus supplement related to that series.

The prospectus supplement will also describe any material United States federal income tax consequences or other special considerations regarding the applicable series of debt securities, including those relating to:


	•	debt securities with respect to which payments of principal, premium or interest are determined with reference to an index or formula, including changes in prices of particular securities, currencies or commodities;

	•	debt securities with respect to which principal, premium or interest is payable in a foreign or composite currency;

	•	debt securities that are issued at a discount below their stated principal amount, bearing no interest or interest at a rate that at the time of issuance is below market rates; and

	•	variable rate debt securities that are exchangeable for fixed rate debt securities.

Interest payments on debt securities in certificated form may be made by check mailed to the registered holders or, if so stated in the applicable prospectus supplement, at the option of a holder, by wire transfer to an account designated by the holder.

Unless otherwise provided in the applicable prospectus supplement, debt securities may be transferred or exchanged at the office of the Trustee at which its corporate trust business is principally administered in the United States, subject to the limitations provided in the Indenture, without the payment of any service charge, other than any applicable tax or governmental charge.

Any funds paid to a paying agent for the payment of amounts due on any debt securities that remain unclaimed for two years will be returned to the issuer, and the holders of the debt securities must look only to the issuer for payment after that time.

The Guarantees

Natural Resource Partners may fully, irrevocably and unconditionally guarantee on an unsecured basis all series of debt securities of NRP (Operating) LLC. If a series of debt securities is so guaranteed, Natural Resource Partners will execute a notation of guarantee as further evidence of its guarantee. As used in this prospectus, the term “Guarantor” means Natural Resource Partners in its role as guarantor of the debt securities of NRP (Operating) LLC.

The payment obligations of Natural Resource Partners or NRP (Operating) LLC under any series of debt securities may be jointly and severally, fully and unconditionally guaranteed by the Subsidiary Guarantors. If a series of debt securities is so guaranteed, the Subsidiary Guarantors will execute a notation of guarantee as further evidence of their guarantee. The applicable prospectus supplement will describe the terms of any guarantee by the Subsidiary Guarantors.

The obligations of each guarantor under its guarantee of the debt securities will be limited to the maximum amount that will not result in the obligations of the guarantor under its guarantee constituting a fraudulent conveyance or fraudulent transfer under Federal or state law, after giving effect to:


	•	all other contingent and fixed liabilities of the guarantor; and

	•	any collections from or payments made by or on behalf of any other guarantor in respect of the obligations of the guarantor under its guarantee.

The guarantee of any guarantor may be released under certain circumstances. If no default has occurred and is continuing under the Indenture, and to the extent not otherwise prohibited by the Indenture, a guarantor will be unconditionally released and discharged from the guarantee:


	•	in the case of a Subsidiary Guarantor, automatically upon any sale, exchange or transfer, to any person that is not an affiliate of the issuer, of all of the issuer’s direct or indirect limited liability company or other equity interests in the Subsidiary Guarantor;

	•	automatically if the issuer exercises either its legal defeasance option or its covenant defeasance option as described below under “Defeasance”;

	•	automatically upon the merger of the guarantor into the issuer or any other guarantor or the liquidation and dissolution of the guarantor; or

	•	in the case of a Subsidiary Guarantor, following delivery of a written notice by the issuer to the Trustee, upon the release of all guarantees by the Subsidiary Guarantor of any debt of the issuer for borrowed money (or a guarantee of such debt), except for any series of debt securities.

The guarantee described in the fourth bullet point above is subject to restoration if the Subsidiary Guarantor again guarantees any debt of the issuer for borrowed money (or a guarantee of such debt), except for any series of debt securities.

Covenants

The Indenture contains the following covenant for the benefit of the holders of all series of debt securities:

So long as any debt securities are outstanding, Natural Resource Partners will:


	•	for as long as it is required to file information with the SEC pursuant to the Securities Exchange Act of 1934 or the “Exchange Act,” file with the Trustee, within 15 days after it is required to file with the SEC, copies of the annual reports and of the information, documents and other reports which it is required to file with the SEC pursuant to the Exchange Act;

	•	if it is not required to file information with the SEC pursuant to the Exchange Act, file with the Trustee, within 15 days after it would have been required to file with the SEC, financial statements and a Management’s Discussion and Analysis of Financial Condition and Results of Operations, both comparable to what it would have been required to file with the SEC had it been subject to the reporting requirements of the Exchange Act; and

	•	if it is required to furnish annual or quarterly reports to its unitholders pursuant to the Exchange Act, file with the Trustee any annual report or other financial reports sent to unitholders generally.

A series of debt securities may contain additional financial and other covenants. The applicable prospectus supplement will contain a description of any such covenants that are added to the Indenture specifically for the benefit of holders of a particular series.

Events of Default, Remedies and Notice

Events of Default

Each of the following events will be an “Event of Default” under the Indenture with respect to a series of debt securities:


	•	default in any payment of interest on any debt securities of that series when due that continues for 30 days;

	•	default in the payment of principal of or premium, if any, on any debt securities of that series when due at its stated maturity, upon redemption, upon required repurchase or otherwise;

	•	default in the payment of any sinking fund payment on any debt securities of that series when due;

	•	failure by the issuer or, if the series of debt securities is guaranteed by a guarantor, the guarantor, to comply for 60 days after notice with the other agreements contained in the Indenture, any supplement to the Indenture with respect to that series or any board resolution authorizing the issuance of that series;

	•	certain events of bankruptcy, insolvency or reorganization of the issuer or, if the series of debt securities is guaranteed, any of the guarantors;

	•	if the series of debt securities is guaranteed by the Guarantor or the Subsidiary Guarantors:


	•	any of the guarantees ceases to be in full force and effect, except as otherwise provided in the Indenture;

	•	any of the guarantees is declared null and void in a judicial proceeding; or

	•	the Guarantor or any Subsidiary Guarantor denies or disaffirms its obligations under the Indenture or its guarantee.


	*Exercise of Remedies*

If an Event of Default, other than an Event of Default described in the fifth bullet point above, occurs and is continuing, the Trustee or the holders of at least 25% in principal amount of the outstanding debt securities of that series may declare the entire principal of, premium, if any, and accrued and unpaid interest, if any, on all the debt securities of that series to be due and payable immediately.

A default under the fourth bullet point above will not constitute an Event of Default until the Trustee or the holders of 25% in principal amount of the outstanding debt securities of that series notify the issuer and, if the series of debt securities is guaranteed by the Guarantor and/or the Subsidiary Guarantors, the Guarantor and/or the Subsidiary Guarantors, of the default and such default is not cured within 60 days after receipt of notice.

If an Event of Default described in the fifth bullet point above occurs, the principal of, premium, if any, and accrued and unpaid interest on all outstanding debt securities of all series will become immediately due and payable without any declaration of acceleration or other act on the part of the Trustee or any holders.

The holders of a majority in principal amount of the outstanding debt securities of a series may:


	•	waive all past defaults, except with respect to nonpayment of principal, premium or interest; and

	•	rescind any declaration of acceleration by the Trustee or the holders with respect to the debt securities of that series, but only if:


	•	rescinding the declaration of acceleration would not conflict with any judgment or decree of a court of competent jurisdiction; and


	•	all existing Events of Default have been cured or waived, other than the nonpayment of principal, premium or interest on the debt securities of that series that has become due solely by the declaration of acceleration.

If an Event of Default occurs and is continuing, the Trustee will be under no obligation, except as otherwise provided in the Indenture, to exercise any of the rights or powers under the Indenture at the request or direction of any of the holders unless such holders have offered to the Trustee reasonable indemnity or security against any costs, liability or expense. No holder may pursue any remedy with respect to the Indenture or the debt securities of any series, except to enforce the right to receive payment of principal, premium or interest when due, unless:


	•	such holder has previously given the Trustee notice that an Event of Default with respect to that series is continuing;

	•	holders of at least 25% in principal amount of the outstanding debt securities of that series have requested that the Trustee pursue the remedy;

	•	such holders have offered the Trustee reasonable indemnity or security against any cost, liability or expense;

	•	the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of indemnity or security; and

	•	the holders of a majority in principal amount of the outstanding debt securities of that series have not given the Trustee a direction that is inconsistent with such request within such 60-day period.

The holders of a majority in principal amount of the outstanding debt securities of a series have the right, subject to certain restrictions, to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any right or power conferred on the Trustee with respect to that series of debt securities. The Trustee, however, may refuse to follow any direction that:


	•	conflicts with law;

	•	is inconsistent with any provision of the Indenture;

	•	the Trustee determines is unduly prejudicial to the rights of any other holder;

	•	would involve the Trustee in personal liability.


	*Notice of Event of Default*

Within 30 days after the occurrence of an Event of Default, the issuer is required to give written notice to the Trustee and indicate the status of the default and what action it is taking or propose to take to cure the default. In addition, the issuer is required to deliver to the Trustee, within 120 days after the end of each fiscal year, a compliance certificate indicating that it has complied with all covenants contained in the Indenture or whether any default or Event of Default has occurred during the previous year.

If an Event of Default occurs and is continuing and is known to the Trustee, the Trustee must mail to each holder a notice of the Event of Default by the later of 90 days after the Event of Default occurs or 30 days after the Trustee knows of the Event of Default. Except in the case of a default in the payment of principal, premium or interest with respect to any debt securities, the Trustee may withhold such notice, but only if and so long as the board of directors, the executive committee or a committee of directors or responsible officers of the Trustee in good faith determines that withholding such notice is in the interests of the holders.

Amendments and Waivers

The issuer may amend the Indenture without the consent of any holder of debt securities to:


	•	cure any ambiguity, omission, defect or inconsistency;

	•	provide for the assumption by a successor of its obligations under the Indenture;

	•	add Subsidiary Guarantors with respect to the debt securities;

	•	secure the debt securities;

	•	add covenants for the benefit of the holders or surrender any right or power conferred upon the issuer, the Guarantor or any Subsidiary Guarantor;

	•	make any change that does not adversely affect the rights of any holder;

	•	add or appoint a successor or separate Trustee;

	•	comply with any requirement of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act; or

	•	establish the form or terms of the debt securities of any new series.

In addition, the issuer may amend the Indenture if the holders of a majority in principal amount of all debt securities of each series that would be affected then outstanding under the Indenture consent to it. The issuer may not, however, without the consent of each holder of outstanding debt securities of each series that would be affected, amend the Indenture to:


	•	reduce the percentage in principal amount of debt securities of any series whose holders must consent to an amendment;

	•	reduce the rate of or extend the time for payment of interest on any debt securities;

	•	reduce the principal of or extend the stated maturity of any debt securities;

	•	reduce the premium payable upon the redemption of any debt securities or change the time at which any debt securities may or shall be redeemed;

	•	make any debt securities payable in other than U.S. dollars;

	•	impair the right of any holder to receive payment of premium, principal or interest with respect to such holder’s debt securities on or after the applicable due date;

	•	impair the right of any holder to institute suit for the enforcement of any payment with respect to such holder’s debt securities;

	•	release any security that has been granted in respect of the debt securities;

	•	make any change in the amendment provisions which require each holder’s consent;

	•	make any change in the waiver provisions; or

	•	release the Guarantor or a Subsidiary Guarantor or modify the Guarantor’s or such Subsidiary Guarantor’s guarantee in any manner adverse to the holders.

The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. After an amendment under the Indenture becomes effective, the issuer is required to mail to all holders a notice briefly describing the amendment. The failure to give, or any defect in, such notice, however, will not impair or affect the validity of the amendment.

The holders of a majority in aggregate principal amount of the outstanding debt securities of each affected series, on behalf of all such holders, and subject to certain rights of the Trustee, may waive:


	•	compliance by the issuer, the Guarantor or a Subsidiary Guarantor with certain restrictive provisions of the Indenture; and

	•	any past default under the Indenture;

except that such majority of holders may not waive a default:


	•	in the payment of principal, premium or interest; or

	•	in respect of a provision that under the Indenture cannot be amended without the consent of all holders of the series of debt securities that is affected.

Satisfaction and Discharge

The Indenture will be discharged and will cease to be of further effect as to all outstanding debt securities of any series issued thereunder, when:

(a) either:


	(1) all outstanding debt securities of that series that have been authenticated (except lost, stolen or destroyed debt securities that have been replaced or paid and debt securities for whose payment money has theretofore been deposited in trust and thereafter repaid to the issuer) have been delivered to the Trustee for cancellation; or

	(2) all outstanding debt securities of that series that have not been delivered to the Trustee for cancellation have become due and payable or will become due and payable at their stated maturity within one year or are to be called for redemption within one year under arrangements satisfactory to the Trustee and in any case the issuer has irrevocably deposited with the Trustee as trust funds cash, non-callable U.S. government obligations or a combination thereof, in such amounts as will be sufficient, without consideration of any reinvestment of interest, to pay the entire indebtedness of such debt securities not delivered to the Trustee for cancellation, for principal, premium, if any, and accrued interest to the stated maturity or redemption date;

(b) the issuer has paid or caused to be paid all other sums payable by us under the Indenture with respect to the debt securities of that series; and

(c) the issuer has delivered an officers’ certificate and an opinion of counsel to the Trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Defeasance

At any time, the issuer may terminate, with respect to debt securities of a particular series, all its obligations under such series of debt securities and the Indenture, which we call a “legal defeasance.” If the issuer decides to make a legal defeasance, however, the issuer may not terminate its obligations:


	•	relating to the defeasance trust;

	•	to register the transfer or exchange of the debt securities;

	•	to replace mutilated, destroyed, lost or stolen debt securities; or

	•	to maintain a registrar and paying agent in respect of the debt securities.

At any time the issuer may also effect a “covenant defeasance,” which means it has elected to terminate its obligations under:


	•	covenants applicable to a series of debt securities and described in the prospectus supplement applicable to such series, other than as described in such prospectus supplement, and any Event of Default resulting from a failure to observe such covenants;


	•	the bankruptcy provisions with respect to the Guarantor or the Subsidiary Guarantors, if any; and

	•	the guarantee provisions described under “— Events of Default” above with respect to a series of debt securities.

The legal defeasance option may be exercised notwithstanding a prior exercise of the covenant defeasance option. If the legal defeasance option is exercised, payment of the affected series of debt securities may not be accelerated because of an Event of Default with respect to that series. If the covenant defeasance option is exercised, payment of the affected series of debt securities may not be accelerated because of an Event of Default specified in the fourth, fifth (with respect only to the Guarantor or a Subsidiary Guarantor (if any)) or sixth bullet points under “— Events of Default” above or an Event of Default that is added specifically for such series and described in a prospectus supplement. If the issuer exercises either its legal defeasance option or its covenant defeasance option, any guarantee will terminate with respect to that series of debt securities.

In order to exercise either defeasance option, the issuer must:


	•	irrevocably deposit in trust with the Trustee money or certain U.S. government obligations for the payment of principal, premium, if any, and interest on the series of debt securities to redemption or maturity, as the case may be;

	•	comply with certain other conditions, including that no default has occurred and is continuing 91 days after the deposit in trust; and

	•	deliver to the Trustee of an opinion of counsel to the effect that holders of the series of debt securities will not recognize income, gain or loss for Federal income tax purposes as a result of such defeasance and will be subject to Federal income tax on the same amounts and in the same manner and at the same times as would have been the case if such defeasance had not occurred. In the case of legal defeasance only, such opinion of counsel must be based on a ruling of the Internal Revenue Service or other change in applicable Federal income tax law.

No Personal Liability of General Partner

GP Natural Resource Partners LLC and its directors, officers, employees, incorporators and members, as such, will not be liable for:


	•	any of the obligations of Natural Resource Partners or NRP (Operating) LLC or the obligations of the Guarantor or the Subsidiary Guarantors under the debt securities, the Indenture or the guarantees; or

	•	any claim based on, in respect of, or by reason of, such obligations or their creation.

By accepting a debt security, each holder will be deemed to have waived and released all such liability. This waiver and release are part of the consideration for the issuance of the debt securities. This waiver may not be effective, however, to waive liabilities under the Federal securities laws and it is the view of the SEC that such a waiver is against public policy.

No Protection in the Event of a Change of Control

Unless otherwise set forth in the prospectus supplement, the debt securities will not contain any provisions that protect the holders of the debt securities in the event of a change of control of the issuer or in the event of a highly leveraged transaction, whether or not such transaction results in a change of control of the issuer.

Book Entry, Delivery and Form

A series of debt securities may be issued in the form of one or more global certificates deposited with a depositary. We expect that The Depository Trust Company, New York, New York, or “DTC,” will act as depositary. If a series of debt securities is issued in book-entry form, one or more global certificates will

be issued and deposited with or on behalf of DTC and physical certificates will not be issued to each holder. A global security may not be transferred unless it is exchanged in whole or in part for a certificated security, except that DTC, its nominees and their successors may transfer a global security as a whole to one another.

DTC will keep a computerized record of its participants, such as a broker, whose clients have purchased the debt securities. The participants will then keep records of their clients who purchased the debt securities. Beneficial interests in global securities will be shown on, and transfers of beneficial interests in global securities will be made only through, records maintained by DTC and its participants.

DTC advises us that it is:


	•	a limited-purpose trust company organized under the New York Banking Law;

	•	a “banking organization” within the meaning of the New York Banking Law;

	•	a member of the United States Federal Reserve System;

	•	a “clearing corporation” within the meaning of the New York Uniform Commercial Code; and

	•	a “clearing agency” registered under the provisions of Section 17A of the Exchange Act.

DTC is owned by a number of its participants and by the New York Stock Exchange, Inc., The American Stock Exchange, Inc. and the National Association of Securities Dealers, Inc. The rules that apply to DTC and its participants are on file with the Securities and Exchange Commission.

DTC holds securities that its participants deposit with DTC. DTC also records the settlement among participants of securities transactions, such as transfers and pledges, in deposited securities through computerized records for participants’ accounts. This eliminates the need to exchange certificates. Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations.

Principal, premium, if any, and interest payments due on the global securities will be wired to DTC’s nominee. The issuer, the Trustee and any paying agent will treat DTC’s nominee as the owner of the global securities for all purposes. Accordingly, the issuer, the Trustee and any paying agent will have no direct responsibility or liability to pay amounts due on the global securities to owners of beneficial interests in the global securities.

It is DTC’s current practice, upon receipt of any payment of principal, premium, if any, or interest, to credit participants’ accounts on the payment date according to their respective holdings of beneficial interests in the global securities as shown on DTC’s records. In addition, it is DTC’s current practice to assign any consenting or voting rights to participants, whose accounts are credited with debt securities on a record date, by using an omnibus proxy.

Payments by participants to owners of beneficial interests in the global securities, as well as voting by participants, will be governed by the customary practices between the participants and the owners of beneficial interests, as is the case with debt securities held for the account of customers registered in “street name”. Payments to holders of beneficial interests are the responsibility of the participants and not of DTC, the Trustee or the issuer.

Beneficial interests in global securities will be exchangeable for certificated securities with the same terms in authorized denominations only if:


	•	DTC notifies the issuer that it is unwilling or unable to continue as depositary or if DTC ceases to be a clearing agency registered under applicable law and a successor depositary is not appointed by the issuer within 90 days; or

	•	the issuer determines not to require all of the debt securities of a series to be represented by a global security and notifies the Trustee of the decision.

The Trustee

A separate trustee may be appointed for any series of debt securities. We may maintain banking and other commercial relationships with the Trustee and its affiliates in the ordinary course of business, and the Trustee may own debt securities.


	*Limitations on Trustee if it is a Creditor*

The Indenture will limit the right of the Trustee, if it becomes a creditor of an issuer or guarantor, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise.


	*Certificates and Opinions to be Furnished to Trustee*

The Indenture will provide that, in addition to other certificates or opinions that may be specifically required by other provisions of the Indenture, every application by the issuer for action by the Trustee must be accompanied by a certificate of certain of the officers of GP Natural Resource Partners LLC or NRP (Operating) LLC and an opinion of counsel (who may be the issuer’s counsel) stating that, in the opinion of the signers, all conditions precedent to such action have been complied with by the issuer.

Governing Law

The Indenture and the debt securities will be governed by, and construed in accordance with, the laws of the State of New York.

DESCRIPTION OF THE COMMON UNITS

The common units represent limited partner interests in Natural Resource Partners that entitle the holders to participate in our cash distributions and to exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units, holders of subordinated units, and our general partner in and to partnership distributions, together with a description of the circumstances under which subordinated units convert into common units, see “Cash Distributions” in this prospectus.

Our outstanding common units are listed on the New York Stock Exchange under the symbol “NRP.”

The transfer agent and registrar for our common units is American Stock Transfer & Trust Company.

Status as Limited Partner or Assignee

Except as described under “— Limited Liability,” the common units will be fully paid, and the unitholders will not be required to make additional capital contributions to us.

Transfer of Common Units

Each purchaser of common units offered by this prospectus must execute a transfer application. By executing and delivering a transfer application, the purchaser of common units:


	•	becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;

	•	automatically requests admission as a substituted limited partner in our partnership;

	•	agrees to be bound by the terms and conditions of, and executes, our partnership agreement;

	•	represents that he has the capacity, power and authority to enter into the partnership agreement;


	•	grants powers of attorney to officers of the general partner and any liquidator of our partnership as specified in the partnership agreement; and

	•	makes the consents and waivers contained in the partnership agreement.

An assignee will become a substituted limited partner of our partnership for the transferred common units upon the consent of our general partner and the recording of the name of the assignee on our books and records. The general partner may withhold its consent in its sole discretion.

Transfer applications may be completed, executed and delivered by a purchaser’s broker, agent or nominee. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders’ rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired, the purchaser has the right to request admission as a substituted limited partner in our partnership for the purchased common units. A purchaser of common units who does not execute and deliver a transfer application obtains only:


	•	the right to assign the common unit to a purchaser or transferee; and

	•	the right to transfer the right to seek admission as a substituted limited partner in our partnership for the purchased common units.

Thus, a purchaser of common units who does not execute and deliver a transfer application:


	•	will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application; and

	•	may not receive some federal income tax information or reports furnished to record holders of common units.

Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by the limited partners as a group:


	•	to remove or replace the general partner;

	•	to approve some amendments to our partnership agreement; or

	•	to take other action under our partnership agreement

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under Delaware law, to the same extent as the general partner. This liability would extend to persons who transact business with us and who reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we have found no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if after the distribution all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of our partnership, exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to our partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and which could not be ascertained from our partnership agreement.

Our subsidiaries currently conduct business in twelve states: Alabama, Georgia, Illinois, Indiana, Kentucky, Maryland, Montana, North Carolina, North Dakota, Tennessee, Virginia and West Virginia. Maintenance of limited liability for Natural Resource Partners as the sole member of the operating company, may require compliance with legal requirements in the jurisdictions in which the operating company conducts business, including qualifying our subsidiaries to do business there. Limitations on the liability of members for the obligations of a limited liability company have not been clearly established in many jurisdictions. If it were determined that we were, by virtue of our member interest in the operating company or otherwise, conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner as our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, shall be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner shall distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy shall constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum shall be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in our partnership, although additional limited partner interests having special voting rights could be issued. However, if at

any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates or a person or group who acquires the units with the prior approval of the board of directors, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, the person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as otherwise provided in the partnership agreement, subordinated units will vote together with common units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:


	•	a current list of the name and last known address of each partner;

	•	a copy of our tax returns;

	•	information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

	•	copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments and powers of attorney under which they have been executed;

	•	information regarding the status of our business and financial condition; and

	•	any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or which we are required by law or by agreements with third parties to keep confidential.

Summary of Partnership Agreement

A summary of the important provisions of our partnership agreement, many of which apply to holders of common units, is included in reports filed with the SEC and incorporated by reference in this prospectus.

CASH DISTRIBUTIONS

Distributions of Available Cash

General. Within approximately 45 days after the end of each quarter, Natural Resource Partners will distribute all available cash to unitholders of record on the applicable record date.

Definition of Available Cash. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:


	•	less the amount of cash reserves that the general partner determines in its reasonable discretion is necessary or appropriate to:


	•	provide for the proper conduct of our business;

	•	comply with applicable law, any of our debt instruments, or other agreements; or

	•	provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;


	•	plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

Intent to Distribute the Minimum Quarterly Distribution. We intend to distribute to holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.5125 per quarter, or $2.05 per year, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of fees and expenses, including reimbursements to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our credit facility.

Operating Surplus and Capital Surplus

General. All cash distributed to unitholders will be characterized either as operating surplus or capital surplus. We distribute available cash from operating surplus differently than available cash from capital surplus.

Maintenance capital expenditures are capital expenditures made to maintain, over the long term, the operating capacity of our assets as they existed at the time of the expenditure. Expansion capital expenditures are capital expenditures made to increase over the long term the operating capacity of our assets as they existed at the time of the expenditure. The general partner has the discretion to determine how to allocate a capital expenditure for the acquisition or expansion of coal reserves between maintenance capital expenditures and expansion capital expenditures, and its good faith allocation will be conclusive. Maintenance capital expenditures reduce operating surplus, from which we pay the minimum quarterly distribution, but expansion capital expenditures do not.

Definition of Operating Surplus. For any period, operating surplus generally means:


	•	our cash balance on the closing date of our initial public offering; plus

	•	$15.0 million (as described below); plus


	•	all of our cash receipts since the closing of our initial public offering, excluding cash from borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus

	•	working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for that quarter; less

	•	all of our operating expenses since the closing of our initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less

	•	the amount of cash reserves that the general partner deems necessary or advisable to provide funds for future operating expenditures.

Definition of Capital Surplus. Capital surplus will generally be generated only by:


	•	borrowings other than working capital borrowings;

	•	sales of debt and equity securities; or

	•	sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

Characterization of Cash Distributions. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus. As reflected above, operating surplus includes $15.0 million in addition to our cash balance on the closing date of our initial public offering, cash receipts from our operations and cash from working capital borrowings. This amount does not reflect actual cash on hand at closing that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to $15 million of cash we receive in the future from non-operating sources, such as assets sales, issuances of securities and long-term borrowings, which would otherwise be considered distributions of capital surplus. Any distributions of capital surplus would trigger certain adjustment provisions in our partnership agreement as described below. See “— Distributions From Capital Surplus” and “— Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.”

Subordination Period

General. During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.5125 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Definition of Subordination Period. The subordination period will generally extend until the first day of any quarter beginning after September 30, 2007 that each of the following tests are met:


	•	distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the adjusted operating surplus generated during each of the three immediately preceding non-overlapping four-quarter periods equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on


		a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Conversion of Subordinated Units. Before the end of the subordination period, 50% of the subordinated units, or up to 5,676,829 subordinated units, may convert into common units on a one-for-one basis immediately after the distribution of available cash to partners in respect of any quarter ending on or after:


	•	September 30, 2005 with respect to 25% of the subordinated units; and

	•	September 30, 2006 with respect to 25% of the subordinated units.

The early conversions will occur if at the end of the applicable quarter each of the following three tests are met:


	•	distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the adjusted operating surplus generated during each of the three immediately preceding, non-overlapping four-quarter periods equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

However, the early conversion of the second 25% of the subordinated units may not occur until at least one year following the early conversion of the first 25% of the subordinated units.

Definition of Adjusted Operating Surplus. Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.

Adjusted operating surplus for any period generally means:


	•	operating surplus generated with respect to that period; less

	•	any net increase in working capital borrowings with respect to that period; less

	•	any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

	•	any net decrease in working capital borrowings with respect to that period; plus

	•	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Effect of Expiration of the Subordination Period. Upon expiration of the subordination period, all remaining subordinated units will convert into common units on a one-for-one basis and will then participate, pro rata, with the other common units in distributions of available cash. In addition, if the unitholders remove the general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of this removal:


	•	the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and


	•	the general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Distributions of Available Cash from Operating Surplus During the Subordination Period

Natural Resource Partners will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:


	•	First, 98% to the common unitholders, pro rata, and 2% to the general partner until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

	•	Second, 98% to the common unitholders, pro rata, and 2% to the general partner until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

	•	Third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	Thereafter, in the manner described in “—Incentive Distribution Rights” below.

Distributions of Available Cash from Operating Surplus After the Subordination Period

Natural Resource Partners will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:


	•	First, 98% to all unitholders, pro rata, and 2% to the general partner until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	Thereafter, in the manner described in “— Incentive Distribution Rights” below

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner and members and affiliates of the WPP Group currently hold 65% and 35%, respectively, of the incentive distribution rights. The WPP Group and its affiliates may transfer these rights, but our general partner may only transfer these rights separately from its general partner interest in accordance with restrictions in the partnership agreement.

If for any quarter:


	•	we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

	•	we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:


	•	First, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.5625 per unit for that quarter (the “first target distribution”);

	•	Second, 85% to all unitholders, pro rata, 13% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.6625 per unit for that quarter (the “second target distribution”);


	•	Third, 75% to all unitholders, pro rata, 23% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.7625 per unit for that quarter (the “third target distribution”); and

	•	Thereafter, 50% to all unitholders, pro rata, 48% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.



			Marginal Percentage Interest in
			Distributions

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

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

Distributions from Capital Surplus

Natural Resource Partners will make distributions of available cash from capital surplus, if any, in the following manner:


	•	First, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in the initial public offering, an amount of available cash from capital surplus equal to the initial public offering price;

	•	Second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

	•	Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a Distribution from Capital Surplus. The partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from the initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the unrecovered initial unit price. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into

common units. Any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero and we will make all future distributions from operating surplus, with 50% being paid to the holders of units, and 50% to the general partner.

Adjustment of Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:


	•	the minimum quarterly distribution;

	•	the target distribution levels;

	•	the unrecovered initial unit price;

	•	the number of additional common units issuable during the subordination period without a unitholder vote; and

	•	the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates. For example, if we became subject to a maximum marginal federal, and effective state and local income tax rate of 38%, then the minimum quarterly distribution and the target distributions levels would each be reduced to 62% of their previous levels.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon the liquidation of Natural Resource Partners to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon liquidation of Natural Resource Partners to enable the holder of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

Manner of Adjustment for Gain. The manner of the adjustment is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:


	•	First, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

	•	Second, 98% to the common unitholders, pro rata, and 2% to the general partner, until the capital account for each common unit is equal to the sum of:

(1) the unrecovered initial unit price; plus


	(2)	the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; plus

(3) any unpaid arrearages in payment of the minimum quarterly distribution;


	•	Third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until the capital account for each subordinated unit is equal to the sum of:


	(1)	the unrecovered initial unit price on that subordinated unit; and

	(2)	the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;


	•	Fourth, 98% to all unitholders, pro rata, and 2% to the general partner, pro rata, until we allocate under this paragraph an amount per unit equal to:


	(1)	the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

	(2)	the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that was distributed 98% to the units, pro rata, and 2% to the general partner, pro rata, for each quarter of our existence;


	•	Fifth, 85% to all unitholders, pro rata, 13% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to:


	(1)	the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less

	(2)	the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that was distributed 85% to the unitholders, pro rata, 13% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner for each quarter of our existence;


	•	Sixth, 75% to all unitholders, pro rata, and 23% to the holders of the incentive distribution rights, pro rata , and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to:


	(1)	the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less

	(2)	the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that was distributed 75% to the unitholders, pro rata, 23% to the holders of the incentive distribution rights, pro rata and 2% to the general partner for each quarter of our existence;


	•	Thereafter, 50% to all unitholders, pro rata, 48% to the holders of the incentive distribution rights, pro rata and 2% to the general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustment for Losses. Upon our liquidation, we will generally allocate any loss to the general partner and the unitholders in the following manner:


	•	First, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to the general partner until the capital accounts of the holders of the subordinated units have been reduced to zero;

	•	Second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the general partner until the capital accounts of the common unitholders have been reduced to zero; and

	•	Thereafter, 100% to the general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts Upon the Issuance of Additional Units. We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive interim adjustments to the capital accounts, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or distributions of property or upon liquidation in a manner which results, to the extent possible, in the capital account balance of the general partner equaling the amount which would have been in its capital account if no earlier positive adjustments to the capital accounts had been made.

MATERIAL TAX CONSEQUENCES

This section is a summary of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to the general partner and us, insofar as it relates to United States federal income tax matters. If we offer and sell any debt securities, a description of the material federal income tax consequences of the acquisition, ownership and disposition of debt securities will be set forth in the prospectus supplement relating to the offering. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Natural Resource Partners and its direct subsidiary, NRP (Operating) LLC.

This section does not comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we recommend that each prospective unitholder consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us and our general partner.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions and advice of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by the unitholders and the general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues:


	•	the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”);

	•	whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and

	•	whether our method for depreciating Section 743 adjustments is sustainable (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the marketing of coal. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 1% of our current income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and the general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of the operating company for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, Natural Resource Partners will be classified as a partnership and the operating company will be disregarded as an entity separate from Natural Resource Partners for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and the general partner. The representations made by us and our general partner upon which counsel has relied are:


	•	Neither Natural Resource Partners nor the operating company has elected or will elect to be treated as a corporation; and

	•	For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure which is determined by the IRS to be inadvertent and which is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The remainder of this section is based on Vinson & Elkins L.L.P.’s opinion that Natural Resource Partners will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Natural Resource Partners will be treated as partners of Natural Resource Partners for federal income tax purposes. Also:


	•	assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and

	•	unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units

will be treated as partners of Natural Resource Partners for federal income tax purposes.

As there is no direct authority addressing assignees of common units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Vinson & Elkins L.L.P. does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in Natural Resource Partners for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange

Basis of Common Units. A unitholder’s initial tax basis for his common units is the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt which is recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of its stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be

“at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly-traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly-traded partnerships.

Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly-traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all

current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to the general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of an offering, referred to in this discussion as “Contributed Property.” The effect of these allocations to a unitholder purchasing common units in an offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales. A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those units would be fully taxable; and

	•	all of these distributions would appear to be ordinary income.

Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable

income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates. In general, the highest effective United States federal income tax rate for individuals currently is 35% and the maximum United States federal income tax rate for net capital gains of an individual currently is 15% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election. We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we have adopted), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury regulation Section 1.167(c)-l(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, the general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury regulations. Please read “— Tax Treatment of Operations — Uniformity of Units.”

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 but is arguably inconsistent with Treasury regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Tax Treatment of Operations — Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the

Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by the general partner, its affiliates and our other unitholders as of that time. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We are not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Coal Income. Section 631 of the Internal Revenue Code provides special rules by which gains or losses on the sale of coal may be treated, in whole or in part, as gains or losses from the sale of property used in a trade or business under Section 1231 of the Internal Revenue Code. Specifically, Section 631(c) provides that if the owner of coal held for more than one year disposes of that coal under a contract by virtue of which the owner retains an economic interest in the coal, the gain or loss realized will be treated under Section 1231 of the Internal Revenue Code as gain or loss from property used in a trade or business. Section 1231 gains and losses may be treated as capital gains and losses. Please read “— Sales of

Coal Reserves.” In computing gain or loss, the amount realized is reduced by the adjusted depletion basis in the coal, determined as described in “— Coal Depletion.” For purposes of Section 631(c), the coal generally is deemed to be disposed of on the day on which the coal is mined. Further, Treasury regulations promulgated under Section 631 provide that advance royalty payments may also be treated as proceeds from sales of coal to which Section 631 applies and, therefore, such payment may be treated as capital gain under Section 1231. However, if the right to mine the related coal expires or terminates under the contract that provides for the payment of advance royalty payments or such right is abandoned before the coal has been mined, we may, pursuant to the Treasury regulations, file an amended return that reflects the payments attributable to unmined coal as ordinary income and not as received from the sale of coal under Section 631.

Our royalties from coal leases generally will be treated as proceeds from sales of coal to which Section 631 applies. Accordingly, the difference between the royalties paid to us by the lessees and the adjusted depletion basis in the extracted coal generally will be treated as gain from the sale of property used in a trade or business, which may be treated as capital gain under Section 1231. Please read “— Sales of Coal Reserves.” Our royalties that do not qualify under Section 631(c) generally will be taxable as ordinary income in the year of sale.

Coal Depletion. In general, we are entitled to depletion deductions with respect to coal mined from the underlying mineral property. We generally are entitled to the greater of cost depletion limited to the basis of the property or percentage depletion. The percentage depletion rate for coal is 10%. If Section 631(c) applies to the disposition of the coal, however, we are not eligible for percentage depletion. Please read “— Coal Income.”

Depletion deductions we claim generally will reduce the tax basis of the underlying mineral property. Depletion deductions can, however, exceed the total tax basis of the mineral property. The excess of our percentage depletion deductions over the adjusted tax basis of the property at the end of the taxable year is subject to tax preference treatment in computing the alternative minimum tax. Please read “— Tax Consequences of Unit Ownership — Alternative Minimum Tax.” In addition, a corporate unitholder’s allocable share of the amount allowable as a percentage depletion deduction for any property will be reduced by 20% of the excess, if any, of that partner’s allocable share of the amount of the percentage depletion deductions for the taxable year over the adjusted tax basis of the mineral property as of the close of the taxable year.

Sales of Coal Reserves. If any coal reserves are sold or otherwise disposed of in a taxable transaction, we will recognize gain or loss measured by the difference between the amount realized (including the amount of any indebtedness assumed by the purchaser upon such disposition or to which such property is subject) and the adjusted tax basis of the property sold. Generally, the character of any gain or loss recognized upon that disposition will depend upon whether our coal reserves or the particular tract of timberland sold are held by us:


	•	for sale to customers in the ordinary course of business (i.e., we are a “dealer” with respect to that property),

	•	for use in a trade or business within the meaning of Section 1231 of the Internal Revenue Code or

	•	as a capital asset within the meaning of Section 1221 of the Internal Revenue Code.

In determining dealer status with respect to coal reserves and other types of real estate, the courts have identified a number of factors for distinguishing between a particular property held for sale in the ordinary course of business and one held for investment. Any determination must be based on all the facts and circumstances surrounding the particular property and sale in question.

We intend to hold our coal reserves for the purposes of generating cash flow from coal royalties and achieving long-term capital appreciation. Although our general partner may consider strategic sales of coal reserves consistent with achieving long-term capital appreciation, our general partner does not anticipate frequent sales, nor significant marketing, improvement or subdivision activity in connection with any

strategic sales. In light of the factual nature of this question, however, there is no assurance that our purposes for holding our properties will not change and that our future activities will not cause us to be a “dealer” in coal reserves.

If we are not a dealer with respect to our coal reserves and we have held the disposed property for more than a one-year period primarily for use in our trade or business, the character of any gain or loss realized from a disposition of the property will be determined under Section 1231 of the Internal Revenue Code. If we have not held the property for more than one year at the time of the sale, gain or loss from the sale will be taxable as ordinary income.

A unitholder’s distributive share of any Section 1231 gain or loss generated by us will be aggregated with any other gains and losses realized by that unitholder from the disposition of property used in the trade or business, as defined in Section 1231(b) of the Internal Revenue Code, and from the involuntary conversion of such properties and of capital assets held in connection with a trade or business or a transaction entered into for profit for the requisite holding period. If a net gain results, all such gains and losses will be long-term capital gains and losses; if a net loss results, all such gains and losses will be ordinary income and losses. Net Section 1231 gains will be treated as ordinary income to the extent of prior net Section 1231 losses of the taxpayer or predecessor taxpayer for the five most recent prior taxable years to the extent such losses have not previously been offset against Section 1231 gains. Losses are deemed recaptured in the chronological order in which they arose.

If we are not a dealer with respect to our coal reserves and that property is not used in a trade or business, the property will be a “capital asset” within the meaning of Section 1221 of the Internal Revenue Code. Gain or loss recognized from the disposition of that property will be taxable as capital gain or loss, and the character of such capital gain or loss as long-term or short-term will be based upon our holding period in such property at the time of its sale. The requisite holding period for long-term capital gain is more than one year.

Upon a disposition of coal reserves, a portion of the gain, if any, equal to the lesser of (i) the depletion deductions that reduced the tax basis of the disposed mineral property plus deductible development and mining exploration expenses, or (ii) the amount of gain recognized on the disposition, will be treated as ordinary income to us.

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. A portion of this gain or loss, which may be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be real located among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements. A purchaser of units from another unitholder is required to notify us in writing of that purchase within 30 days after the purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker. Failure to notify us of a purchase may lead to the imposition of substantial penalties.

Constructive Termination. We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury regulation Section 1.167(c)-1(a)(6) which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and

amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, other foreign persons and regulated investment companies raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. A significant portion of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company or “mutual fund” is required to derive 90% or more of its gross income from interest, dividends and gains from the sale of stocks or securities or foreign currency or specified related sources. It is not anticipated that any significant amount of our gross income will include that type of income.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly traded partnerships, we will withhold tax, at the highest applicable rate, from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury regulations or administrative interpretations of the IRS. Neither we nor counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement appoints the general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:


	(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

	(b) whether the beneficial owner is


	(1)	a person that is not a United States person,

	(2)	a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

	(3)	a tax-exempt entity;


	(c) the amount and description of units held, acquired or transferred for the beneficial owner; and

	(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Registration as a Tax Shelter. The Internal Revenue Code requires that “tax shelters” be registered with the Secretary of the Treasury. It is arguable that we are not subject to the registration requirement on the basis that we will not constitute a tax shelter. However, we have registered as a tax shelter with the Secretary of Treasury in the absence of assurance that we will not be subject to tax shelter registration and in light of the substantial penalties that might be imposed if registration is required and not undertaken. Our tax shelter registration number is 02247000042.

Issuance of this registration number does not indicate that investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS.

A unitholder who sells or otherwise transfers a unit in a later transaction must furnish the registration number to the transferee. The penalty for failure of the transferor of a unit to furnish the registration number to the transferee is $100 for each failure. The unitholders must disclose our tax shelter registration number on Form 8271 to be attached to the tax return on which any deduction, loss or other benefit we generate is claimed or on which any of our income is included. A unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for that failure, will be subject to a $250 penalty for each failure. Any penalties discussed are not deductible for federal income tax purposes.

Recently issued Treasury Regulations require taxpayers to report certain information on Internal Revenue Service Form 8886 if they participate in a “reportable transaction.” You may be required to file this form with the IRS if we participate in a “reportable transaction.” A transaction may be a reportable transaction based on any of several factors. You are urged to consult with your own tax advisor concerning the application of any of these factors to your investment in our common units. Congress is considering legislative proposals that, if enacted, would impose significant penalties for failure to comply with these disclosure requirements. The Treasury Regulations also impose obligations on “material advisors” that organize, manage or sell interests in registered “tax shelters.” As stated above, we have registered as a tax shelter, and, thus, one of our material advisors will be required to maintain a list with specific information, including your name and tax identification number, and to furnish this information to the IRS upon request. You are urged to consult with your own tax advisor concerning any possible disclosure obligation with respect to your investment and should be aware that we and our material advisors intend to comply with the list and disclosure requirements.

Accuracy-related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial evaluation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:


	•	for which there is, or was, “substantial authority,” or

	•	as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

More stringent rules apply to “tax shelters,” a term that in this context does not appear to include us. If any item of income, gain, loss or deduction included in the distributive shares of unitholders might

result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

State, Local and Other Tax Considerations

In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently own assets and do business in Alabama, Georgia, Illinois, Indiana, Kentucky, Maryland, Montana, North Carolina, North Dakota, Tennessee, Virginia and West Virginia, all of which impose income taxes. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, the general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Accordingly, we strongly recommend that each prospective unitholder consult, and depend upon, his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state and local, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state or local tax consequences of an investment in us.

INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to certain additional considerations because the investments of such plans are subject to the fiduciary responsibility and prohibited transaction provisions of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), and restrictions imposed by Section 4975 of the Internal Revenue Code. As used herein, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to (a) whether such investment is prudent under Section 404(a)(1)(B) of ERISA; (b) whether in making such investment, such plan will satisfy the diversification requirement of Section 404(a)(1)(C) of ERISA; and (c) whether such investment will result in recognition of unrelated business taxable income by such plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors.” The person with investment discretion with respect to the

assets of an employee benefit plan (a “fiduciary”) should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for such plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code (which also applies to IRAs that are not considered part of an employee benefit plan) prohibit an employee benefit plan from engaging in certain transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of limited partnership units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether such plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under certain circumstances. Pursuant to these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things, (a) the equity interest acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered pursuant to certain provisions of the federal securities laws, (b) the entity is an “Operating Partnership”—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries, or (c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest (disregarding certain interests held by our general partner, its affiliates and certain other persons) is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA (such as governmental plans). Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above and may also satisfy the requirements in (c).

Plan fiduciaries contemplating a purchase of limited partnership units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

SELLING UNITHOLDERS

In addition to covering our offering of securities, this prospectus covers the offering for resale of up to 673,715 common units by selling unitholders. As used in this prospectus, “selling unitholders” includes donees, pledgees, transferees or other successors-in-interest selling units received after the date of this prospectus from a named selling unitholder as a gift, pledge, partnership distribution or other non-sale related transfer. We will bear all costs, expenses and fees in connection with the registration of the units offered by this prospectus. Brokerage commissions and similar selling expenses, if any, attributable to the sale of the units will be borne by the selling unitholders. The following table sets forth information relating to the selling unitholders’ beneficial ownership of our common units:


Selling Unitholders	Number of Common Units Owned

Great Northern Properties Limited Partnership		673,715

The applicable prospectus supplement will set forth, with respect to the selling unitholders:


	•	the name of the selling unitholders;

	•	the nature of the position, office or other material relationship which the selling unitholders will have had within the prior three years with us or any of our affiliates;

	•	the number of common units owned by the selling unitholders prior to the offering;


	•	the amount of common units to be offered for the selling unitholders’ account; and

	•	the amount and (if one percent or more) the percentage of common units to be owned by the selling unitholders after the completion of the offering.

All expenses incurred with the registration of the common units owned by the selling unitholders will be borne by us.

PLAN OF DISTRIBUTION

Distribution by Natural Resource Partners

We may sell the common units or debt securities directly, through agents, or to or through underwriters or dealers. The prospectus supplement will contain the terms of the common unit or debt securities offering, including:


	•	the names of any underwriters, dealers or agents;

	•	the offering price;

	•	underwriting discounts;

	•	sales agents’ commissions;

	•	other forms of underwriter or agent compensation;

	•	discounts, concessions or commissions that underwriters may pass on to other dealers; and

	•	any exchange on which the common units or debt securities are listed.

We may change the offering price, underwriting discounts or concessions, or the price to dealers when necessary. Discounts or commissions received by underwriters or agents and any profits on the resale of common units or debt securities by them may constitute underwriting discounts and commissions under the Securities Act of 1933, as amended.

The aggregate maximum compensation that underwriters will receive in connection with the sale of any securities under this prospectus and the registration statement of which it forms a part will not exceed 8% of the gross proceeds from the sale.

Unless we state otherwise in a prospectus supplement, underwriters will need to meet certain requirements before purchasing common units or debt securities. Agents will act on a “best efforts” basis during their appointment. We will also state the net proceeds from the sale in a prospectus supplement.

Any brokers or dealers that participate in the distribution of the common units or debt securities may be “underwriters” within the meaning of the Securities Act for such sales. Profits, commissions, discounts or concessions received by such broker or dealer may be underwriting discounts and commissions under the Securities Act.

When necessary, we may fix common unit or debt securities distribution using changeable, fixed prices, market prices at the time of sale, prices related to market prices, or negotiated prices.

We and the selling unitholders may, through agreements, indemnify underwriters, dealers or agents that participate in the distribution of the common units or debt securities against certain liabilities including liabilities under the Securities Act. We and the selling unitholders may also provide funds for payments that the underwriters, dealers or agents may be required to make. Underwriters, dealers and agents, and their affiliates may transact with us and our affiliates in the ordinary course of their business.

Distribution by Selling Unitholders

We are also registering common units on behalf of selling unitholders. Distribution of any common units to be offered by one or more of the selling unitholders may be effected from time to time in one or more transactions (which may involve block transactions):


	•	on the New York Stock Exchange;

	•	in the over-the-counter market;

	•	in underwritten transactions;

	•	in transactions otherwise than on the New York Stock Exchange or in the over-the-counter market; or

	•	in a combination of any of these transactions.

The transactions may be effected by the selling unitholders at market prices prevailing at the time of sale, at prices related to the prevailing market prices, at negotiated prices or at fixed prices. The selling unitholders may offer their shares through underwriters, brokers, dealers or agents, who may receive compensation in the form of underwriting discounts, commissions or concessions from the selling unitholders or the purchasers of the shares for whom they act as agent. The selling unitholders may engage in short sales, short sales against the box, puts and calls and other transactions in our securities, or derivatives thereof, and may sell and deliver their common units in connection with those transactions. In addition, the selling unitholders may from time to time sell their common units in transactions permitted by Rule 144 under the Securities Act.

As of the date of this prospectus, we have not engaged any underwriter, broker, dealer or agent in connection with the distribution of common units pursuant to this prospectus by the selling unitholders. To the extent required, the number of common units to be sold, the purchase price, the name of any applicable agent, broker, dealer or underwriter and any applicable commissions with respect to a particular offer will be set forth in the applicable prospectus supplement. The aggregate net proceeds to the selling unitholders from the sale of their common units offered by this prospectus will be the sale price of those shares, less any commissions, if any, and other expenses of issuance and distribution not borne by us.

The selling unitholders and any brokers, dealers, agents or underwriters that participate with the selling unitholders in the distribution of shares may be deemed to be “underwriters” within the meaning of the Securities Act, in which event any discounts, concessions and commissions received by such brokers, dealers, agents or underwriters and any profit on the resale of the shares purchased by them may be deemed to be underwriting discounts and commissions under the Securities Act.

The applicable prospectus supplement will set forth the extent to which we will have agreed to bear fees and expenses of the selling unitholders in connection with the registration of the common units being offered hereby by them. We may, if so indicated in the applicable prospectus supplement, agree to indemnify selling unitholders against certain civil liabilities, including liabilities under the Securities Act.

WHERE YOU CAN FIND MORE INFORMATION

Natural Resource Partners files annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. and at the SEC’s regional offices in New York, New York and Chicago, Illinois. Please call the SEC at 1-800-732-0330 for further information on their public reference rooms. Our SEC filings are also available at the SEC’s web site at http://www.sec.gov. You can also obtain information about us at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

The SEC allows Natural Resource Partners to incorporate by reference the information we have previously filed with the SEC. This means that Natural Resource Partners can disclose important

information to you without actually including the specific information in this prospectus by referring you to those documents. The information incorporated by reference is an important part of this prospectus. Information that Natural Resource Partners files later with the SEC will automatically update and may replace information in this prospectus and information previously filed with the SEC. The documents listed below and any filings made with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 after the date of this prospectus and prior to the termination of this offering are incorporated by reference in this prospectus until the termination of each offering under this prospectus.


	•	Quarterly Reports on Form 10-Q for the periods ended March 31, 2003, June 30, 2003 and September 30, 2003.

	•	Annual Report on Form 10-K for the fiscal year ended December 31, 2002.

	•	Current Reports on Form 8-K filed January 9, January 23, February 27, April 7, April 10, May 8 (excluding Item 9 information), June 23, July 1, July 14, August 7 (excluding Item 9 and Item 12 information), September 12 (excluding Item 9 information) and September 22, 2003 (excluding Item 9 information), November 5 (excluding Item 9 and Item 12 information), November 25, December 1 (excluding Item 9 information), December 22, 2003, January 5, 2004, January 8, 2004 (excluding Item 9 and Item 12 information) and January 22, 2004.

	•	The description of the limited partnership units contained in the Registration Statement on Form 8-A, initially filed September 27, 2002, and any subsequent amendment thereto filed for the purpose of updating such description.

We make available free of charge on or through our Internet website, www.nrplp.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

You may request a copy of any document incorporated by reference in this prospectus, at no cost, by writing or calling us at the following address:


	Investor Relations Department
	Natural Resource Partners L.P.
	601 Jefferson, Suite 3600
	Houston, Texas 77002
	(713) 751-7507

We intend to furnish or make available to our unitholders within 90 days (or such shorter period as the SEC may prescribe) following the close of our fiscal year end annual reports containing audited financial statements prepared in accordance with generally accepted accounting principles and furnish or make available within 45 days (or such shorter period as the Commission may prescribe) following the close of each fiscal quarter quarterly reports containing unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each of our fiscal years. Our annual report will include a description of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, including the amount paid or accrued to each recipient and the services performed.

FORWARD-LOOKING STATEMENTS

Some of the information included in this prospectus, any prospectus supplement and the documents we incorporate by reference contain forward-looking statements. These statements use forward-looking words such as “may,” “will,” “anticipate,” “believe,” “expect,” “project” or other similar words. These statements discuss goals, intentions and expectations as to future trends, plans, events, results of operations or financial condition or state other “forward-looking” information.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that assumed facts or bases almost always vary from actual results, and the differences between assumed facts or bases and actual results can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus, any prospectus supplement and the documents we have incorporated by reference. These statements reflect Natural Resource Partners’ current views with respect to future events and are subject to various risks, uncertainties and assumptions.

Many of such factors are beyond our ability to control or predict. Please read “Risk Factors” for a better understanding of the various risks and uncertainties that could affect our business and impact the forward-looking statements made in this prospectus. Readers are cautioned not to put undue reliance on forward-looking statements.

LEGAL MATTERS

Certain legal matters in connection with the securities will be passed upon by Vinson & Elkins L.L.P., Houston, Texas, as our counsel. The selling unitholders’ counsel and the underwriters’ own legal counsel will advise them about other issues relating to any offering in which they participate.

EXPERTS

Ernst & Young LLP, independent auditors, have audited (i) the consolidated financial statements of Natural Resource Partners L.P., (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, 2002, as set forth in their reports, which are incorporated by reference in this prospectus and in the registration statement. These financial statements 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, 1999, 2000, and 2001.

Arthur Andersen LLP’s reports on the financial statements of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, and New Gauley Coal Corporation for the years ended December 31, 2001 and 2000 did not contain an adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles. During the years ended December 31, 2001 and 2000 and through April 26, 2002:


	•	there were no disagreements with Arthur Andersen LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure which if not resolved to Arthur Andersen LLP’s satisfaction, would have caused them to make reference to the subject matter in connection with their reports on the financial statements of any of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, or New Gauley Coal Corporation for such years;

	•	there were no reportable events as listed in 304(a)(1)(v) of Regulation S-K; and


	•	Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, and New Gauley Coal Corporation did not consult Ernst & Young LLP with respect to the application of accounting principles to a specified transaction either completed or proposed, or the type of audit opinion that might be rendered on the financial statements of Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, or New Gauley Coal Corporation or any other matters or reportable events listed in Items 304(a)(2)(i) and (ii) of Regulation S-K.

4,600,000 Common Units

Natural Resource Partners L.P.

Representing Limited Partner Interests

(NATURAL RESOURCE PARTNERS L.P. LOGO)

PROSPECTUS SUPPLEMENT

March , 2004

Citigroup

Lehman Brothers

A.G. Edwards & Sons, Inc.

UBS Investment Bank

Wachovia Securities

Friedman Billings Ramsey

RBC Capital Markets

Sanders Morris Harris