UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2004

OR

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-31465

NATURAL RESOURCE PARTNERS L.P.

601 Jefferson Street, Suite 3600
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)

(713) 751-7507
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ü] No [   ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [ü] No [   ]

At November 1, 2004 there were outstanding 13,986,906 Common Units and 11,353,658 Subordinated Units.

TABLE OF CONTENTS

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Part I. Financial Information

Item 1. Financial Statements

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these financial statements.

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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF INCOME

(1)	Other holders of the incentive distribution rights (IDRs) include the WPP Group (25%) and NRP Investment LP (10%). The net income allocated to the general partner includes the general partner’s portion of the IDRs (65%).

The accompanying notes are an integral part of these financial statements.

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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

The accompanying notes are an integral part of these financial statements.

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NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.

Basis of Presentation and Organization

     The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2004 are not necessarily indicative of the results that may be expected for future periods.

     For further information, refer to the consolidated financial statements and footnotes for the period from commencement of operations (October 17, 2002) through December 31, 2003 included in the Natural Resource Partners L.P. Form 10-K, as filed on March 4, 2004.

     Natural Resource Partners L.P. (the “Partnership”), a Delaware limited partnership, was formed in April 2002 to own and manage certain coal royalty producing properties contributed to the Partnership by Western Pocahontas Properties Limited Partnership, (“WPP”), Great Northern Properties Limited Partnership, (“GNP”), New Gauley Coal Corporation, (“NGCC”) and Arch Coal, Inc. (collectively “predecessors” or “predecessor companies”). The predecessor companies contributed assets to the Partnership on October 17, 2002. There were no operations in the Partnership prior to the contribution of the assets from the predecessor companies.

     The Partnership engages principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. The Partnership does not operate any mines. The Partnership leases coal reserves through its wholly owned subsidiary, NRP (Operating) LLC, (“NRP Operating”), to experienced mine operators under long-term leases that grant the operators the right to mine the Partnership’s coal reserves in exchange for royalty payments. The Partnership’s lessees are generally required to make payments to the Partnership based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, in addition to a minimum payment.

     The general partner of the Partnership is NRP (GP) LP, a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company.

2.

Summary of Significant Accounting Policies

New Accounting Standards

     Historical practice in the extractive industry has been to classify leased mineral interests on a basis consistent with owned minerals due to similar rights of the lessor. SFAS No. 141, Business Combinations, provides mineral rights as an example of a contract-based intangible asset that should be considered for separate classification as the result of a business combination. Due to the potential for inconsistencies in applying the provisions of SFAS No. 141 (and SFAS No. 142, Goodwill and Other Intangible Assets) in the extractive industries as they relate to mineral interests controlled by other than fee ownership, the Emerging Issues Task Force (the “EITF”) established a Mining Industry Working Group that addressed this issue. At a March 17-18, 2004 meeting of the EITF, the Task Force reached consensus that an inconsistency existed as to the characterization of mineral rights as tangible assets as determined by the EITF and SFAS No. 141 and 142. As a result of the EITF’s consensus, the FASB issued FASB Staff Position (“FSP”) Nos. FAS 141-1 and FAS 142-1, “Interaction of FASB Statements No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-02, Whether Mineral Rights Are Tangible or Intangible Assets,” which amend SFAS No. 141 and 142 and result in the classification of mineral rights as tangible assets. Prior to this consensus, the Partnership provided separate line items for owned and leased coal interests within the consolidated balance sheet as of December 31, 2003. At September 30, 2004, leased coal interests are included within coal and mineral rights in the unaudited consolidated balance sheet. Prior year amounts have been reclassified to conform with the current year presentation.

3.

Acquisitions

     Clinchfield. In September 2004, the Partnership purchased a tract of coal reserves from Clinchfield Coal Company in Dickenson County, Virginia for $0.4 million. This property adjoins other property the Partnership owns and represents approximately 0.8 million

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tons. The Partnership subsequently combined this property with other properties under an existing lease to a subsidiary of Alpha Natural Resources.

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

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

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

     The factors used in determining the fair market value of the assets acquired included, but were not limited to, discounted future net cash flows, the quality of the reserves, the probability of continued coal mining on the property, and marketability of the coal.

4.

Coal and Other Mineral Rights

The Partnership’s coal and other mineral rights consist of the following:

5.

Long-Term Debt

     Long-term debt consists of the following:

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     The Partnership has a $175 million unsecured revolving credit facility, which matures in October 2005, when all principal payments are due in full. The revolving credit facility provides for the election of the interest rate at (i) LIBOR plus an applicable margin ranging from 1.25% to 2.25% based on certain financial data or (ii) the higher of the federal funds rate plus an applicable margin ranging from 0.25% to 0.75% or the prime rate as announced by the agent bank. The facility includes a $12 million distribution loan sublimit that can be used for quarterly distributions. The remainder of the revolving credit facility is available for general limited partnership and affiliated company purposes, including future acquisitions, but may not be used to fund quarterly distributions. Financial covenants require the maintenance of a ratio of consolidated total indebtedness to consolidated EBITDA (as defined in the credit agreement) not to exceed 3.5 to 1.0 and a ratio of consolidated EBITDA to consolidated fixed charges of at least 4.0 to 1.0. A portion of the proceeds from the Partnership’s March 16, 2004 public offering was used to repay the $102.5 million outstanding under the credit facility at that time. The weighted average interest rate on the debt the Partnership repaid was 4.4 %. This indebtedness was incurred under our credit facility during the past year in connection with our acquisitions of coal reserves and other mineral rights. At September 30, 2004, there was no outstanding balance under the revolving credit facility. The Partnership incurs a commitment fee on the unused portion of the revolving credit facility at a rate of 0.50% per annum. For the nine months ended September 30, 2004, we paid $0.8 million in credit facility commitment fees.

     The Partnership also has outstanding $165.6 million in senior notes. Proceeds from the issuance of the senior notes were used to repay borrowings under the Partnership’s existing revolving credit facility and for related expenses. The terms under the senior notes require that the Partnership maintain a fixed charge coverage ratio of not less than 3.50 to 1.0 and a limit on consolidated debt to consolidated EBITDA of not more than 4.00 to 1.00.

     The Partnership was in compliance with all terms under its long-term debt as of September 30, 2004.

6.

Equity Offering

     On March 16, 2004 the Partnership closed a public offering of 5,250,000 common units. The Partnership received net proceeds of $200.4 million from the sale of the 5,250,000 common units. These proceeds were based on an offering price of $39.96 per common unit less underwriting discounts, commissions and offering expenses. In connection with the offering, the Partnership also received a capital contribution of $2.1 million from its general partner to maintain its 2% general partner interest.

     The Partnership used the net proceeds of this offering and its general partner’s capital contribution to:

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

7.

Net Income Per Unit Attributable to Limited Partners

     Net income per unit attributable to limited partners is based on the weighted-average number of common and subordinated units outstanding during the period and is allocated in the same ratio as quarterly cash distributions are made. Net income per unit attributable to limited partners is computed by dividing net income attributable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, by the weighted-average number of limited partnership units outstanding. Basic and diluted net income per unit attributable to limited partners are the same since the Partnership has no potentially dilutive securities outstanding.

8.

Related Party Transactions

     Quintana Minerals Corporation, a company controlled by Corbin J. Robertson, Jr., Chairman and CEO of GP Natural Resource Partners LLC, provided certain administrative services to the Partnership and charged it for direct costs related to the administrative services. Total expenses charged to the Partnership under this arrangement were $0.3 million and $0.9 million for the three and nine months ended September 30, 2004 and $0.2 million and $0.7 million for the same periods in 2003. These costs are reflected in general and administrative expenses in the accompanying statements of income. At September 30, 2004 and 2003, the Partnership also had accounts payable to affiliates of $0.1 million, which includes general and administrative expense payable to Quintana Minerals Corporation.

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     WPP provides certain administrative services for the Partnership. Total expenses charged to the Partnership under this arrangement were $0.7 million and $2.1 million for the three and nine months ended September 30, 2004 and $0.5 million and $1.5 million for the same periods in 2003. These costs are reflected in general and administrative expenses in the accompanying statements of income.

     At December 31, 2003, the Partnership had accounts receivable from affiliates of $1.4 million consisting of minimums due from Arch Coal, Inc. There were no accounts receivable from affiliates at September 30, 2004. On October 21, 2003, Arch entered into a guaranty agreement with the Partnership whereby Arch agreed to pay the Partnership a minimum of $11.3 million in coal royalties with respect to their leases in 2004. In conjunction with the Partnership’s public offering of 5,250,000 common units, the Partnership redeemed 2,616,752 of the common units held by Arch Coal, Inc. Please see Note 6. As a result of the redemption of Arch Coal’s common units in March 2004, Arch Coal is no longer an affiliate of the Partnership.

9. Commitments and Contingencies

Legal

     The Partnership is involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, Partnership management believes these claims will not have a material effect on the Partnership’s financial position, liquidity or operations.

Environmental Compliance

     The operations conducted on the Partnership’s properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Partnership’s coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Because Natural Resource Partners L.P. has no employees, WPP employees perform regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees and the duty to enforce regulations rests with the appropriate regulatory agencies. Management believes that the Partnership’s lessees will be able to comply with existing regulations and does not expect any lessee’s failure to comply with environmental laws and regulations to have a material impact on its financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties for the period ended September 30, 2004. The Partnership is not associated with any environmental contamination that may require remediation costs. However, lessees do, from time to time, conduct reclamation work on the properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, it is not responsible for the costs associated with these reclamation operations. All of the Partnership’s lessees are required to post bonds to cover reclamation costs. In the event these bonds are insufficient, some states, such as West Virginia have established funds to cover these shortfalls. The Partnership is also indemnified by WPP, GNP, NGCC and Arch Coal, Inc., jointly and severally, until October 16, 2005 against environmental and tax liabilities attributable to the ownership and operation of the assets contributed to the Partnership prior to the closing of the initial public offering in October 2002. The environmental indemnity is limited to a maximum of $10.0 million.

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10.

Major Lessees

     Coal royalty revenues from major lessees that exceeded ten percent of total revenues for the periods indicated below are as follows:

(1)	Certain of our leases have been combined since the period ending September 30, 2003. This table has been restated for comparative purposes.

11.

Incentive Plans

     Prior to the Partnership’s initial public offering, GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the “Long-Term Incentive Plan”) for employees and directors of GP Natural Resource Partners LLC and its affiliates who perform services for the Partnership. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.

     On August 19, 2003, the compensation committee amended the Long-Term Incentive Plan to provide only for the issuance of phantom units that are payable solely in cash. In connection with the amendment to the Long-Term Incentive Plan, the compensation committee terminated all of the existing option grants and issued to all of the holders of terminated options a number of phantom units equivalent in value to the terminated options.

     A phantom unit entitles the grantee to receive the fair market value of a common unit in cash upon the vesting of the phantom unit. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines. The compensation committee will determine the period over which the phantom units granted to employees and directors will vest. Phantom units vest upon a change in control of the Partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s phantom units will be automatically forfeited unless and to the extent the compensation committee provides otherwise.

     GP Natural Resource Partners LLC adopted the Natural Resource Partners Annual Incentive Compensation Plan (the “Annual Incentive Plan”) in October 2002. The Annual Incentive Plan is designed to enhance the performance of GP Natural Resource Partners LLC’s and its affiliates’ key employees by rewarding them with cash awards for achieving annual financial and operational performance objectives. The compensation committee in its discretion may determine individual participants and payments, if any, for each year. The board of directors of GP Natural Resource Partners LLC may amend or change the Annual Incentive Plan at any time. The Partnership reimburses GP Natural Resource Partners LLC for payments and costs incurred under the Annual Incentive Plan.

     In February 2004, the board of directors of GP Natural Resource Partners LLC granted to directors and key employees 55,950 additional phantom units that vest in February 2008. There were 194,030 phantom units outstanding at September 30, 2004. The Partnership accrued expenses to be reimbursed to its general partner of $0.7 million and $1.8 million for the three and nine months ended September 30, 2004 related to these plans. In connection with the Long-Term Incentive Plans, cash payments of $0.6 million were paid for the nine months ended September 30, 2004.

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12.

Distributions

     On August 13, 2004, the Partnership paid a cash distribution equal to $0.60 per unit, or $2.40 on an annualized basis, to unitholders of record on August 2, 2004.

13.

Subsequent Events

Distributions

     On October 21, 2004, the Partnership announced a $0.0375 per unit increase in its quarterly distributions to $0.6375 per unit, or $2.55 per unit on an annualized basis. The distribution is payable on November 12, 2004 to unitholders of record on November 1, 2004.

Credit Facility

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

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     The following discussion of the financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included elsewhere in this filing and the financial statements and footnotes included in the Natural Resource Partners L.P. Form 10-K, as filed on March 4, 2004.

Executive Overview

     We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. Coal produced from our properties is burned in electric power plants located east of the Mississippi River and in Montana and Minnesota. As of January 1, 2004, we controlled approximately 1.8 billion tons of proven and probable coal reserves in nine states. For the nine months ended September 30, 2004, approximately 68% of the coal produced from our properties came from underground mines and approximately 32% 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.

     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 September 30, 2004, our reserves were subject to 129 leases with 54 lessees. For the three months ended September 30, 2004, our lessees produced 13.1 million tons of coal from our properties and our total revenues were $34.2 million. For the nine months ended September 30, 2004, our lessees produced 36.7 million tons of coal from our properties and our total revenues were $90.1 million.

     Our revenue and profitability are dependent on our lessees’ ability to mine and market our coal reserves. Generally, our lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum monthly, quarterly or annual payments. In addition, our leases specify minimum monthly, quarterly or annual royalties. These minimum royalties are generally recoupable over a specified period of time (usually three to five years) if sufficient royalties are generated from coal production in future periods. We do not recognize these minimum coal royalties as revenue until the applicable recoupment period has expired or they are recouped through production. Until recognized as revenue, these minimum royalties are recorded as deferred revenue, a liability on 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, over the long term, our coal royalty revenue stream is affected by changes in market price of coal.

     Coal prices are based on supply and demand, specific coal characteristics, economics of alternative fuel, and overall domestic and international economic conditions. Beginning in the latter half of 2003, the combination of the weaker U.S. dollar, especially against the Euro and the Australian dollar, and the increase in ocean-going freight rates caused an increase in demand for export coal because the United States was better able to compete with Australia for the European market. Beginning in 2003, our lessees located in Appalachia experienced a greater demand for coal, and coal prices for both metallurgical and steam coal for those producers have increased over the first nine months of 2004. Because of these generally higher prices, our revenues in Appalachia have increased to an average of $2.28 per ton for the first nine months of 2004 from an average of $1.77 per ton for the same period of 2003. Coal royalty revenues from our Appalachian properties represented 88% of total coal royalty revenues for the first nine months of 2004. Our lessees have not appreciably increased production due to a number of constraints including a shortage of labor, permitting and bonding issues and rail transportation problems.

     Approximately 32% of our 2004 coal royalty revenues have been from metallurgical coal, which was sold to steel companies in the Eastern United States, South America, Europe and Asia. Prices of metallurgical coal have increased substantially in the past year. Metallurgical coal, because of its unique chemical characteristics, is usually priced higher than steam coal. 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 have been increasing. The temporary closure of PinnOak Resources’ Pinnacle Mine in West Virginia, together with the closure of another low volatile metallurgical mine in Alabama, caused a critical shortage of that type of coal and a significant increase of 80% to 100% in its price. Although the Pinnacle mine has restarted production, the metallurgical market remains tight and to date prices have generally not decreased. Some steam coal with marginal metallurgical characteristics is now being sold in the metallurgical markets. If demand for metallurgical coal falls below historic levels, metallurgical coal can also be used as steam coal.

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

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

     In addition to coal royalty revenues, we generated approximately 4% and 3% of our revenues for three and nine months ended September 30, 2004, respectively, from rentals, royalties on oil and gas and coalbed methane leases, overriding royalty arrangements and wheelage payments, which are toll payments for the right to transport third-party coal over or through our property.

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

     Distributable cash flow represents cash flow from operations less actual principal payments and cash reserves set aside for scheduled principal payments on the senior notes. Although distributable cash flow is a “non-GAAP financial measure,” we believe it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. Distributable cash flow may not be calculated the same for NRP as for other companies. A reconciliation of distributable cash flow to net cash provided by operating activities is set forth below.

Reconciliation of GAAP Financial Measures
To Non-GAAP Financial Measures
(in thousands)

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Acquisitions

     We have completed the following acquisitions during 2004 and 2003 that have impacted our results of operations and liquidity. These acquisitions are discussed below:

     2004 Acquisitions

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

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

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

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

     2003 Acquisitions

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

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

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

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

Critical Accounting Policies

     Coal Royalties. We recognize coal royalty revenues on the basis of tons of coal sold by our lessees and the corresponding revenue from those sales. Because our leases provide for our lessees to report tonnage and revenue to us late in the month, the last month of each quarter we estimate a portion of our coal royalty revenues and production volumes. Generally, our lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum monthly, quarterly or annual payments. 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

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as revenue until the applicable recoupment period has expired or they are recouped through production. Until recognized as revenue, these minimum royalties are recorded as deferred revenue, a liability on the balance sheet.

     Oil and Gas Royalties. Oil and gas royalties are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the lessees make payments based on a percentage of the selling price. Some leases are subject to minimum annual payments or delay rentals. The minimum annual payments that are recoupable are generally recoupable over certain periods. The minimum payments are initially recorded as deferred revenue and recognized either when the lessee recoups the minimum payments through production or when the period during which the lessee is allowed to recoup the minimum payment expires.

     Depletion. We deplete coal properties on a units-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral properties and estimated proved and probable tonnage in those properties. We estimate proven and probable coal reserves with the assistance of third-party mining consultants, and we use estimation techniques and recoverability assumptions. Our estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. Historical revisions have not been material.

New Accounting Standards

     Historical practice in the extractive industry has been to classify leased mineral interests on a basis consistent with owned minerals due to similar rights of the lessor. SFAS No. 141, Business Combinations, provides mineral rights as an example of a contract-based intangible asset that should be considered for separate classification as the result of a business combination. Due to the potential for inconsistencies in applying the provisions of SFAS No. 141 (and SFAS No. 142, Goodwill and Other Intangible Assets) in the extractive industries as they relate to mineral interests controlled by other than fee ownership, the Emerging Issues Task Force (the “EITF”) established a Mining Industry Working Group that addressed this issue. At a March 17-18, 2004 meeting of the EITF,the task force reached consensus that an inconsistency existed as to the characterization of mineral rights as tangible assets as determined by the EITF and SFAS No. 141 and 142. As a result of the EITF’s consensus, the FASB issued FASB Staff Position (“FSP”) Nos. FAS 141-1 and FAS 142-1, Interaction of FASB Statements No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-02, Whether Mineral Rights Are Tangible or Intangible Assets, which amend SFAS No. 141 and 142 and result in the classification of mineral rights as tangible assets. Prior to this consensus, we provided separate line items for owned and leased coal interests within the consolidated balance sheet. At September 30, 2004, leased coal interests are included within coal and mineral rights in the unaudited consolidated balance sheet. Prior year amounts have been reclassified to conform with the current year presentation.

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Results of Operations

Natural Resource Partners L.P.

     Three months ended September 30, 2004 compared with three months ended September 30, 2003

     Revenues. For the quarter ended September 30, 2004, coal royalty revenues were $30.3 million on 13.1 million tons of coal produced, compared to $20.8 million in coal royalty revenues on 12.2 million tons of coal produced for the third quarter of 2003, representing a 46% increase in coal royalty revenues and a 7% increase in production. As a result of our acquisitions in Appalachia in 2003, the percentage of production from our Appalachian properties increased from 83% of total production in the third quarter of 2003 to 87% of total production in the third quarter of 2004.

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     Nearly 1.0 million tons and $3.0 million of the increase in coal royalty revenues generated during the third quarter of 2004 were attributable to the acquisitions made subsequent to September 30, 2003. The other changes in coal royalty revenues and production were primarily due to the increase in coal prices from the third quarter of 2003 to the third quarter of 2004.

     Appalachia. Coal royalty revenues in Appalachia for the quarter ended September 30, 2004 were $27.9 million compared to $18.2 million for the same period in 2003, an increase of $9.7 million or 53%. For the quarter ended September 30, 2004, production in Appalachia was 11.4 million tons compared to 10.1 million tons for the same period in 2003, an increase of 1.3 million tons or 13%.

     The following properties generated significantly higher production and/or coal royalty revenues during the quarter ended September 30, 2004.

•		Sincell – production increased from 7,000 tons to 708,000 tons and coal royalty revenues increased from $9,000 to $1.5 million. These increases were due to the longwall unit moving onto the property.
•		Lynch – production increased from 734,000 tons to 1.2 million tons and coal royalty revenues increased from $1.2 million to $2.3 million. These increases were due, in part, to new mines being opened on the property and also to higher prices being realized by the lessee.
•		Pinnacle – production decreased from 747,000 tons to 737,000 tons and coal royalty revenue increased from $1.6 million to $2.6 million. The decrease in production was more than offset by the higher prices bring realized by the lessee.
•		Pardee – production increased from 202,000 tons to 357,000 tons while coal royalty revenues increased from $429,000 to $1.3 million. These increases were due to a greater proportion of production being on our property and higher prices being realized by our lessee.
•		VICC/Alpha – production decreased from 2.1 million tons to 1.7 million tons but coal royalty revenue increased from $3.5 million to $3.9 million. The decrease in production on our property is due to lower production on some mines and mining on adverse property, which was more than offset by the increased sales prices, resulting in an increase in coal royalty revenues.

     These increases were partially offset by lower production and coal royalty revenues from our Oak Grove and Boone-Lincoln properties. The decline in coal royalty revenues on our Oak Grove property from $983,000 to $621,000, was primarily due to a decline in production from 446,000 tons to 226,000 tons. On our Boone-Lincoln property, production decreased from 139,000 tons to 9,000 tons and coal royalty revenues decreased from $235,000 to $19,000 as production from the existing mines moved to adjacent property during the quarter.

     Illinois Basin. On our Cummings/Hocking Wolford property, production increased from 470,000 tons to 558,000 tons and coal royalty revenues increased from $467,000 to $569,000. These increases were due to a greater proportion of the production occurring on our property. On our Sato property, production increased from 220,000 tons to 272,000 tons and coal royalty revenues increased from $298,000 to $391,000. The increase in coal royalty revenues was primarily due to higher production on the properties.

     Northern Powder River Basin. Production from our Western Energy property decreased from 1.1 million tons to 757,000 tons and coal royalty revenues decreased from $1.5 million to $1.3 million. This decrease was due to the typical variations in production resulting from the checkerboard ownership pattern. On our Big Sky property production decreased from 145,000 tons to zero and coal royalty revenues decreased from $135,000 to zero as operations were idled at the Big Sky mine. Included in our coal royalty revenues for the third quarter of 2004 is a one-time settlement of $170,000, or $0.23 per ton, resulting from an arbitration award between our lessee and a third party.

     Expenses. For the quarter ended September 30, 2004, total expenses were $12.5 million, compared to $11.0 million for the third quarter of 2003, representing an increase of $1.5 million, or 14%. Included in total expenses are:

•		Depletion and amortization of $8.1 million for the third quarter of 2004, compared to $6.8 million for the third quarter of 2003, an increase of $1.2 million, or 18% due to the increase in production volumes;
•		General and administrative expenses of $2.5 million for the third quarter of 2004, compared to $2.2 million for the third quarter of 2003, an increase of $0.3 million, or 15%. Most of the increase in general and administrative expenses is

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		attributable to compensation expenses for additional staff required to manage the properties we acquired as well as accruals under our long-term incentive compensation plans due to the increase in our unit price; and
•		Taxes other than income of $1.5 million for the third quarter of 2004, compared to $1.7 million for the third quarter of 2003, a decrease of $0.2 million, or 13%, due to a reduction in franchise taxes for 2004.

     Interest Expense. For the quarter ended September 30, 2004 interest expense was $2.4 million compared to $2.5 million for 2003, or a decrease of $0.1 million. This decrease is attributable to having no outstanding balance on the credit facility during the third quarter as well as a $9.4 million principal reduction in the Partnership’s long term debt.

Nine months ended September 30, 2004 compared with nine months ended September 30, 2003

     Revenues. For the nine months ended September 30, 2004, coal royalty revenues were $79.3 million on 36.7 million tons of coal produced, compared to $55.4 million in coal royalty revenues on 33.4 million tons of coal produced for the nine months ended September 30, 2003, representing a 43.2% increase in coal royalty revenues and an 10% increase in production. As a result of our acquisitions in Appalachia in 2003, the percentage of production from our Appalachian properties increased from 81% of total production for the first nine months of 2003 to 88% of total production for the first nine months of 2004.

     Approximately 2.8 million tons and $7.2 million of the increase in coal royalty revenues generated during the nine months ended September 30, 2004 were attributable to the acquisitions made subsequent to September 30, 2003. The other changes in coal royalty revenues and production were primarily due to the increase in coal prices from the first nine months of 2003 to the first nine months of 2004.

     Appalachia. Coal royalty revenues in Appalachia for the nine months ended September 30, 2004 were $73.6 million compared to $47.8 million for the same period in 2003, an increase of $25.7 million or 54%. For the nine months ended September 30, 2004, production in Appalachia was 32.2 million tons compared to 27.0 million tons for the same period in 2003, an increase of 5.2 million tons or 19%.

     The properties that had significant increases in production and/or coal royalty revenues were:

•		VICC/Alpha – production increased from 5.0 million tons to 5.5 million tons and coal royalty revenues increased from $8.0 million to $11.7 million. These increases were due in part to our acquisition of additional property in this area in April 2003. In addition, the lessee realized higher sales prices for its production during 2004.
•		Lynch – production increased from 2.1 million tons to 3.1 million tons and coal royalty revenues increased from $3.4 million to $5.9 million. These increases were due in part to new mines being opened on the property and also to higher prices being realized by the lessee.
•		Pinnacle – production increased from 747,000 tons to 1.1 million tons and coal royalty revenues increased from $1.6 million to $3.6 million. These increases were due to owning the property for the entire nine months of 2004 versus three months of 2003 and the resumption of production at the mine along with higher pricing.
•		Sincell – production increased from 7,000 tons to 927,000 tons and coal royalty revenues increased from $8,000 to $1.8 million. These increases were due to production moving onto our property which also benefited from the higher coal prices.
•		Oak Grove – production increased from 446,000 tons to 1.1 million tons and coal royalty revenues increased from $983,000 to $2.6 million. These increases were due to higher prices and owning the property for the entire nine months of 2004 versus three months in 2003.
•		West Fork – production was constant at 2.1 million tons and coal royalty revenues increased from $4.6 million to $5.9 million. These increases were due to higher prices being realized by the lessee.
•		Lone Mountain – production decreased from 1.9 million tons to 1.8 million tons but coal royalty revenues increased from $3.6 million to $4.6 million. Although production decreased slightly, this was more than offset by the higher prices being realized by the lessee.

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•

Pardee – production increased from 912,000 tons to 1.0 million tons and coal royalty revenues increased from $1.7 million to $3.4 million. These increases were due to a higher proportion of production on our property and higher prices being realized by the lessee.

     These increases were partially offset by decreases in production and coal royalty revenues from our Boone-Lincoln and Davis Lumber properties. On our Boone-Lincoln property, production decreased from 511,000 tons to 87,000 tons and coal royalty revenues decreased from $926,000 to $179,000. These decreases were due to a greater proportion of production occurring on adjacent property. On our Davis Lumber property, production decreased from 458,000 tons to 44,000 tons and coal royalty revenues decreased from $623,000 to $104,000. These decreases were due to a previously active mine ceasing production.

     Illinois Basin. On our Cummings/Hocking Wolford property, production decreased from 1.3 million tons to 1.2 million tons and coal royalty revenues decreased from $1.4 million to $1.2 million as a greater proportion of production from the active mine was on adjacent property.

     Northern Powder River Basin. Production from our Western Energy property decreased from 3.3 million tons to 2.2 million tons and coal royalty revenues decreased from $4.1 million to $3.1 million. This decrease was due to the typical variations in production resulting from the checkerboard ownership pattern. On our Big Sky property production decreased from 713,000 tons to zero and coal royalty revenues decreased from $660,000 to zero as operations were idled at the Big Sky mine. Included in our coal royalty revenues for the nine months ended September 30, 2004 is a one-time settlement of $170,000, or $0.08 per ton, resulting from an arbitration award between our lessee and a third party.

     Expenses. For the nine months ended September 30, 2004 total expenses were $36.6 million, compared to $30.7 million for the same period of 2003, representing an increase of $5.9 million, or 19%. Included in total expenses are:

•		Depletion and amortization of $22.9 million for the nine months ended September 30, 2004, compared to $19.0 million for the nine months ended September 30, 2003, an increase of $3.9 million, or 20% due to the increase in production volumes on properties;
•		General and administrative expenses of $7.7 million for the nine months ended September 30, 2004, compared to $6.5 million for the nine months ended September 30, 2003, an increase of $1.2 million, or 18%. Most of the increase in general and administrative expenses is attributable to compensation expenses for additional staff required to manage the properties we acquired as well as accruals under our long term incentive compensation plans due to the increase in our unit price; and
•		Taxes other than income of $4.8 million for the nine months ended September 30, 2004, compared to $4.3 million for the nine months ended September 30, 2003, an increase of $0.5 million, or 14%, due to increased assessments and properties acquired during the year. The increase in property taxes was partially offset by a reduction in franchise taxes.

     Interest Expense. For the nine months ended September 30, 2004 interest expense was $7.9 million compared to $4.1 million for 2003, an increase of $3.8 million. This increase is attributable to increased borrowings to fund acquisitions during 2003 and 2004.

Related Party Transactions

Partnership Agreement

     Our general partner will not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with our partnership agreement, our general partner and its affiliates are reimbursed for expenses incurred on our behalf. All direct general and administrative expenses are charged to us as incurred. We also reimburse indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates. Reimbursements to affiliates of our general partner may be substantial and will reduce our cash available for distribution to unitholders. The reimbursements to affiliates of our general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation totaled $3.0 million in the nine months ended September 30, 2004 and $2.0 million in the nine months ended September 30, 2003.

Agreements with Alpha Natural Resources

     First Reserve, which has the right to nominate two members to the board of directors of GP Natural Resource Partners LLC, has a controlling interest in Alpha Natural Resources, which was our largest lessee in 2003 and the first nine months of 2004, based on

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revenues. We have entered into a number of coal mining leases with Alpha through a combination of new leases entered into upon our purchase of the Alpha property and through leases we had with entities that Alpha acquired. The leases we have with Alpha or related companies consist of the following properties:

•		VICC/Alpha in Virginia, which contains 365.0 million tons of proven and probable reserves as of December 31, 2003.
•		Kingwood in West Virginia, which contains 20.8 million tons of proven and probable reserves as of December 31, 2003.
•		Welch/Wyoming in West Virginia, which contains 8.0 million tons of proven and probable reserves as of December 31, 2003.
•		Davis Lumber in West Virginia, which contains 17,000 tons of proven and probable reserves as of December 31, 2003.
•		Kentucky Land in Kentucky, which contains 20.3 million tons of proven and probable reserves as of December 31, 2003.

     Coal royalty revenues payable under these leases totaled $14.3 million, representing 18% of our total coal royalty revenues for the nine months ended September 30, 2004. If no production had taken place in the second quarter of 2004, minimum recoupable royalties of $3.5 million would have been payable under the leases.

     The Alpha leases in general have terms of five to ten years with the ability to renew the leases for subsequent terms of five to ten years, until the earlier to occur of: (1) delivery of notice that the lessee will not renew the lease or (2) all mineable and merchantable coal has been mined. The leases provide for payments to us based on the higher of a percentage of the gross sales price or a fixed minimum per ton of coal sold from the properties, with minimum annual payments. Under the Alpha leases minimum royalty payments are credited against future production royalties. We believe the production and minimum royalty rates contained in the Alpha leases are consistent with current market royalty rates.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

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

     Net cash provided by operations for the nine months ended September 30, 2004 was $67.3 million and for the same period of 2003 it was $47.2 million, substantially all of which was from coal royalty revenues.

     Net cash used in investing activities for the nine months ended September 30, 2004 was $77.7 million compared to $123.7 million for the same period of 2003. The 2004 results represent the BLC, Appolo, Pardee Minerals, and Clinchfield acquisitions. The net cash used in investing activities for the nine months ended September 30, 2003 represents the acquisition of the Alpha overriding royalty interest in February 2003 for $11.9 million and the acquisition of 295,000 mineral acres from two subsidiaries of Alpha Natural Resources, LLC for $53.6 million in April 2003 and the PinnOak Resources properties for $58.0 million in July 2003.

     Net cash provided by financing activities for the nine months ending September 30, 2004 was $22.4 million compared to $90.5 million for the same period a year ago. The 2004 period includes $200.4 million in net proceeds from our equity offering in March 2004, a $2.1 million capital contribution from our general partner to maintain its 2% general partner interest, as well as $75.5 million in proceeds from borrowings on our credit facility. We used $102.5 million of the net proceeds from the equity offering to pay the outstanding balance on our credit facility and $100.1 million to redeem 2.6 million common units owned by Arch Coal. We also paid distributions to our partners totaling $43.6 million.

     Net cash provided by financing activities for the nine months ended September 30, 2003 was $90.5 million. During the period we received proceeds from additional borrowings of $298.1 million, which included $173.1 million under our revolving credit facility and $125.0 million from the issuance of our senior unsecured debt. These borrowings were partially offset by repayments of debt on our revolving credit facility of $172.6 million. We paid $1.4 million to settle an interest rate hedge entered into in connection with

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issuance of our senior notes, and we also paid cash distributions to our partners totaling $34.0 million.

Contractual Obligations and Commercial Commitments

          At September 30, 2004, our debt consisted of:

•		$175 million revolving credit facility that matures in October 2005, all of which was available at September 30, 2004;
•		$56.7 million of 5.55% senior notes due 2023, with a 10-year average life;
•		$73.9 million of 4.91% senior notes due 2018, with a 7.5-year average life; and
•		$35 million of 5.55% senior notes due 2013.

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

          Our obligations under the new credit facility are unsecured but are guaranteed by our operating subsidiaries. We may prepay all loans at any time without penalty. We must reduce all borrowings incurred to pay distributions to zero for a period of at least 15 consecutive days once during each twelve-month period.

          Indebtedness under the revolving credit facility bears interest, at our option, at either:

•		the higher of the federal funds rate plus an applicable margin ranging from 0.25% to 1.00% or the prime rate as announced by the agent bank; or
•		at a rate equal to LIBOR plus an applicable margin ranging from 1.25% to 2.00%.

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

          The credit facility prohibits us from making distributions to unitholders and distributions in excess of available cash if any potential default or event of default, as defined in the credit agreement, occurs or would result from the distribution. In addition, the credit facility contains various covenants limiting our operating company’s and its subsidiaries’ ability to:

•		incur indebtedness;
•		prepay our senior notes or amend or modify the terms thereof;
•		grant liens;
•		engage in mergers and acquisitions;
•		amend our organizational documents or omnibus agreement;
•		make loans and investments;
•		sell assets; or
•		enter into transactions with affiliates.

          The credit agreement also contains covenants requiring us to maintain:

•		a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) of 3.75 to 1.0 for the four most recent quarters; provided however, if during one of those quarters we have made an acquisition, then the ratio shall not exceed 4.0 to 1.0 for the quarter in which the acquisition occurred and (1) if the acquisition is in the first half of the quarter, the next two quarters or (2) if the acquisition is in the second half of the quarter, the next three quarters; and
•		a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of 4.0 to 1.0 for the four most recent quarters.

          If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of any indebtedness outstanding under the credit agreement and exercise other rights and remedies. Each of the following will be an event of default:

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•		failure to pay any principal, interest, fees or other amount when due;
•		failure to pay any indebtedness, other than indebtedness under the credit facility, in excess of $10 million when due or the occurrence and continuance of any other default beyond any applicable grace period, if the default permits or causes the acceleration of the indebtedness or termination of any commitment to lend;
•		bankruptcy or insolvency events;
•		termination of existence;
•		failure to comply with the loan documents, subject to certain grace periods;
•		any representation, warranty or document provided is determined to have been materially untrue when made or provided;
•		entry and the failure to pay, bond, stay or contest adverse judgments or similar processes in excess of $10 million more than any applicable insurance coverage; and
•		any of the following changes in control:

•		we cease to own all of the member interests of the operating company;
•		our general partner ceases to own directly all of our general partner interests; or
•		Corbin J. Robertson, Jr. and the WPP Group, Arch Coal and one or more of their direct or indirect subsidiaries cease to own more than 50% of the partnership interests of our general partner.

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

•		enter into transactions with affiliates;
•		engage in mergers or sell assets;
•		grant liens;
•		incur additional debt if the ratio of consolidated debt (as defined in the note purchase agreement) to consolidated EBITDA (as defined in the note purchase agreement) would exceed 4.0 to 1.0; and
•		change the nature of its business.

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

•		not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and
•		maintain the ratio of consolidated EBITDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.

          If an event of default exists under the note purchase agreement, the noteholders will be able to accelerate the maturity of the senior notes and exercise other rights and remedies. Each of the following will be an event of default:

•		failure to pay principal on any make-whole amount when due;
•		failure to pay interest for more than five business days after it becomes due;
•		failure to comply with the note purchase agreement, subject to certain grace periods;
•		any representation or warranty provided proves to have been false or incorrect in any material respect when made;
•		failure to pay any debt (or interest thereon) in excess of $10.0 million beyond any applicable grace period, a default in the performance of or compliance with any term of any debt in excess of $10.0 million if the default causes the debt to become due;
•		the occurrence or continuation of any event that results in the borrower becoming obligated to repay or repurchase any of its debt, such as a change of control provision;
•		bankruptcy or insolvency events;
•		entry and failure to pay bond, stay or discharge a final judgment in excess of $10.0 million;
•		the occurrence of certain ERISA events; and
•		the note purchase agreement, any note or subsidiary guarantee ceases to be in full force and effect.

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The following table reflects our long-term non-cancelable contractual obligations as of September 30, 2004 (in millions):

Shelf Registration Statement/Equity Offering

     On December 23, 2003, we and our operating subsidiaries jointly filed a $500 million “universal shelf” registration statement with the Securities and Exchange Commission for the proposed sale of debt and equity securities. Securities issued under this shelf may be in the form of common units representing limited partner interests in Natural Resource Partners L.P. or debt securities of NRP or any of our operating subsidiaries. The registration statement also covers, for possible future sales, up to 673,715 common units held by Great Northern Properties Limited Partnership. Great Northern Properties acquired the common units as consideration for its contribution to us of properties and debt in connection with our initial public offering.

     The securities may be offered from time to time directly or through underwriters at amounts, prices, interest rates and other terms to be determined at the time of any offering. The net proceeds from the sale of securities from the shelf will be used for future acquisitions and other general corporate purposes, including the retirement of existing debt. We will not receive any proceeds from the sale of common units by Great Northern Properties.

     On March 16, 2004, we closed our public offering of 5,250,000 common units. We received net proceeds of $200.4 million from the sale of the 5,250,000 common units. These proceeds were based on an offering price of $39.96 per common unit and after deducting underwriting discounts and commissions and offering expenses. In connection with the offering, we also received a capital contribution of $2.1 million from our general partner to maintain its 2% general partner interest.

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

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

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

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

Environmental

     The operations of our lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of substantially all of our leases impose liability on the relevant lessees for all environmental and reclamation liabilities arising under those laws and regulations. All of our lessees are required to post bonds to cover reclamation costs. In the event these bonds are insufficient, some states, such as West Virginia, have established funds to cover these shortfalls.

Forward-Looking Statements

     Statements included in this Form 10-Q are forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements.

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     Such forward-looking statements include, among other things, statements regarding capital expenditures, acquisitions and dispositions, expected commencement dates of coal mining, projected quantities of future coal production by our lessees producing coal from our reserves leased, projected demand or supply for coal that will affect sales levels, prices and royalties realized by us.

     These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events affecting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

     You should not put undue reliance on any forward-looking statements. Please read “Risks Related to Our Business” below for important factors that could cause our actual results of operations or our actual financial condition to differ.

Risks Related to Our Business

•

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

•

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

•

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

•

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

•

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.

•

We may not be able to terminate our leases if any of our lessees declare bankruptcy, and we may experience delays and be unable to replace lessees that do not make royalty payments.

•

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

•

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

•

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

•

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

•

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

•

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.

•

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

•

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

•

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

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•

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

•

The current shortage of labor in the coal industry could result in our lessees reducing the production of coal mined from our properties.

•

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

•

We may be exposed to changes in interest rates because our current borrowings under our revolving credit facility may be subject to variable interest rates generally based upon LIBOR.

•

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

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

     We are dependent upon the efficient marketing of the coal mined by our lessees. Our lessees sell coal under various long-term and short-term contracts as well as on the spot market. In previous years, a large portion of these sales were under long-term contracts. The coal industry in Appalachia is experiencing an increase in both domestic and foreign demand, as well as a shortage of supply. As a result, the current price of coal in Appalachia is abnormally high. If this price level is not sustained and our lessees’ costs increase, some of our coal could become uneconomic to mine, which would adversely affect our coal royalty revenues. In addition, the current prices may make coal from other regions more economic and may make other competing fuels relatively less costly than Appalachian coal.

Interest Rate Risk

     Our exposure to changes in interest rates results from our borrowings under our revolving credit facility, which may be subject to variable interest rates based upon LIBOR. We currently do not have any balance outstanding under our credit facility and thus are not exposed to any variable interest rate risk.

Inflation

     Inflation in the United States has been relatively low in recent years and did not have a material impact on operations for the nine months ended September 30, 2004.

Item 4. Controls and Procedures

     NRP carried out an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of NRP management, including the Chief Executive Officer and Chief Financial Officer of the general partner of the general partner of NRP. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and procedures are effective in producing the timely recording, processing, summarizing and reporting of information and in accumulating and communicating of information to management as appropriate to allow for timely decisions with regard to required disclosure.

     No changes were made to NRP’s internal control over financial reporting during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, NRP’s internal control over financial reporting.

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Part II. Other Information

Item 1. Legal Proceedings

     None.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

     None.

Item 3. Defaults Upon Senior Securities

     None.

Item 4. Submission of Matters to a Vote of Security Holders

     None.

Item 5. Other Information

     None.

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Item 6. Exhibits

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.

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EXHIBIT INDEX