UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

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

For the quarterly period ended March 31, 2005

OR

o 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 þ No o

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

At May 4, 2005 there were outstanding 13,986,906 Common Units and 11,353,658 Subordinated Units.

TABLE OF CONTENTS

2

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.

     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 and projected demand or supply for coal that will affect sales levels, prices and royalties realized by us.

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

     You should not put undue reliance on any forward-looking statements. Please read “Risks Related to Our Business” beginning on page 20 for important factors that could cause our actual results of operations or our actual financial condition to differ.

3

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.

4

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF INCOME

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

5

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

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

6

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 months ended March 31, 2005 are not necessarily indicative of the results that may be expected for future periods.

     You should refer to the information contained in the footnotes included in Natural Resource Partners L.P.’s 2004 Annual Report on Form 10-K in connection with the reading of these unaudited interim consolidated financial statements.

     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

Reclassification

     Certain reclassifications have been made to the prior year’s financial statements to conform to current year classifications.

New Accounting Standards

     Statement of Financial Accounting Standards No. 123R “Accounting for Stock-Based Compensation,” revised in 2004, superseded APB No. 25. Awards under our Long Term Incentive Plan have been accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R, effective for the first quarter of 2006, requires us to recognize a cumulative effect of the accounting change at the date of adoption based on the difference between the fair value of the unvested awards and the intrinsic value recorded. Additionally, FAS 123R provides that grants after the effective date must be accounted for using the fair value method which will require us to estimate the fair value of the grant using the Black-Scholes or another method and charge the estimated fair value to expense over the service or vesting period of the grant. FAS 123R requires that the fair value be recalculated at each reporting date over the service or vesting period of the grant. Use of the fair value method as compared with the intrinsic method, will not change the total expense to be reflected for a grant but it may impact the period in which expense is reflected by increasing expense in one period based upon the fair value calculation and lowering expense in a different period. The Partnership is in the process of evaluating the impact of the adoption of FAS 123R.

7

     3. Acquisitions

Plum Creek

     On March 3, 2005, the Partnership completed an acquisition of coal reserves from Plum Creek Timber Company, Inc. The purchase price was $21.25 million and was funded through a combination of the Partnership’s revolving credit facility and $3.25 million in cash. This property consists of approximately 85 million tons of coal reserves located on approximately 175,000 acres in Virginia, West Virginia and Kentucky with most of the reserves leased under 29 leases. The Partnership also assumed approximately $2.0 million in recoupable royalties that are included in deferred revenue on the balance sheet.

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:

     At March 31, 2005, the Partnership had an outstanding balance of $18 million on its revolving credit facility, and the weighted average interest rate on the outstanding balance was 4.37%. The Partnership incurs a commitment fee on the revolving credit facility at rates ranging from 0.30% to 0.40% per annum.

     The Partnership was in compliance with all terms under its long-term debt as of March 31, 2005.

8

6. Equity Offering

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

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

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

7. Net Income Per Unit Attributable to Limited Partners

     Net income per unit attributable to limited partners is based on the weighted-average number of common and subordinated units outstanding during the period and is allocated in the same ratio as quarterly cash distributions are made. Net income per unit attributable to limited partners is computed by dividing net income attributable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, by the weighted-average number of limited partnership units outstanding. Basic and 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 $0.2 million for the three months ended March 31, 2005 and $0.3 million for the same period in 2004. These costs are reflected in general and administrative expenses in the accompanying statements of income. At March 31, 2005, the Partnership also had accounts payable to affiliates of $0.1 million, which includes general and administrative expense payable to Quintana Minerals Corporation.

     WPP provides certain administrative services for the Partnership. Total expenses charged to the Partnership under this arrangement were $0.7 million for the three months ended March 31, 2005 and $0.7 million for the same period in 2004. These costs are reflected in general and administrative expenses in the accompanying statements of income.

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.

9

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 March 31, 2005. 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.

10. Major Lessees

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

11. Incentive Plans

     In February 2005, the board of directors of GP Natural Resource Partners LLC granted to directors and key employees 58,046 additional phantom units that vest in February 2009. There were 223,344 phantom units outstanding at March 31, 2005. The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $1.0 million and $0.6 million for the three months ended March 31, 2005 and 2004, respectively. In connection with the Long-Term Incentive Plans, cash payments of $0.8 million and $0.6 million were paid during the three months ended March 31, 2005 and 2004.

12. Distributions

     On February 14, 2005, the Partnership paid a cash distribution equal to $0.6625 per unit, or $2.65 on an annualized basis, to unitholders of record on February 1, 2005.

13. Subsequent Event

Distributions

     On April 20, 2005, the Partnership announced a $0.025 per unit increase in its quarterly distributions to $0.6875 per unit, or $2.75 per unit on an annualized basis. The distribution is payable on May 13, 2005 to unitholders of record on May 2, 2005.

10

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 February 28, 2005.

Executive Overview

     We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. As of December 31, 2004, we controlled approximately 1.8 billion tons of proven and probable coal reserves in nine states. For the three months ended March 31, 2005, approximately 60% of the coal produced from our properties came from underground mines and approximately 40% came from surface mines. As of December 31, 2004, approximately 69% of our reserves were low sulfur coal. Included in our low sulfur reserves is compliance coal, which constitutes approximately 37% of our reserves.

     We lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine our coal reserves in exchange for royalty payments. As of March 31, 2005, our reserves were subject to 157 leases with 57 lessees. For the three months ended March 31, 2005, our lessees produced 12.8 million tons of coal generating $32.5 million in coal royalty revenues from our properties and our total revenue was $36.2 million.

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

     Most of our coal is produced by large companies, many of which are publicly traded, with professional and sophisticated sales departments. We estimate that 80% of our coal is sold by our lessees under coal supply contracts that have terms of one year or more. However, over the long term, our coal royalty revenues are affected by changes in the market price of coal.

     Coal prices are based on supply and demand, specific coal characteristics, economics of alternative fuel, and overall domestic and international economic conditions. Beginning in the latter half of 2003, the combination of the weaker U.S. dollar, especially against the Euro and the Australian dollar, and the increase in ocean-going freight rates caused an increase in demand for export coal because the United States was better able to compete with Australia for the European market. Our lessees located in Appalachia have experienced a greater demand for coal, and coal prices for both metallurgical and steam coal for those producers increased during 2004. Because of these generally higher prices, our revenues in Appalachia have increased to an average of $2.73 per ton for the quarter ended March 31, 2005 from an average of $2.06 per ton for the same period of 2004. Coal royalty revenues from our Appalachian properties represented 85% of our total coal royalty revenues for the three months ended March 31, 2005. In spite of the higher prices, our lessees have not appreciably increased production due to a number of constraints, including a shortage of labor, permitting issues and rail transportation problems.

     For the three months ended March 31, 2005, approximately 31% of our coal royalty revenues were from metallurgical coal, which was sold to steel companies in the Eastern United States, South America, Europe and Asia. Prices of metallurgical coal have been extraordinarily high over the last two years. Metallurgical coal, because of its unique chemical characteristics, is usually priced higher than steam coal. The current pricing environment for U.S. metallurgical coal is strong in both the domestic and seaborne export markets.

     On July 8, 2004, the United States District Court for the Southern District of West Virginia issued an opinion and an injunctive order in the case of Ohio Valley Environmental Coalition, 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 Permit 21 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 at the time of the July 8 order. Pending the

11

resolution of any appeals, this decision will dramatically slow down the permitting process for our lessees in Southern West Virginia, and the increased cost of obtaining permits could render some of our smaller blocks of reserves uneconomic to develop.

     In January 2005, a lawsuit was filed in Eastern District of Kentucky on similar grounds challenging the legality of Nationwide Permit 21. In March 2005, the plaintiffs filed a motion for summary judgment requesting the court to (1) issue a declaratory judgment that Nationwide Permit 21 violates Section 404 and (2) issue an injunction prohibiting the Corps from issuing further authorizations pursuant to Nationwide Permit 21 in Kentucky. The motion also requested the court to suspend those authorizations for valley fills on which the placement of mining spoil in streams has not commenced as of the date of filing of the motion. The court is expecting to hear this motion in May 2005 once the government has had a chance to file a response. Should the district court follow the reasoning of Ohio Valley Environmental Coalition v. Bulen and similarly enjoin the Corps of Engineers from authorizing further general permits under Nationwide Permit 21, permittees may have to file for individual permits for fills that will result in increases in the costs of mining coal. We will continue to monitor this litigation and its impact on the development of our coal reserves.

     In addition to coal royalty revenues, other revenues accounted for approximately 3% of our total revenues for both of the three-month periods ended March 31, 2005 and 2004. Other revenues consist of: rentals; royalties on oil and gas and coalbed methane leases; timber; overriding royalty arrangements; and wheelage payments, which are toll payments for the right to transport third-party coal over or through our property.

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

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

Reconciliation of GAAP “Net cash provided by operating activities”
to Non-GAAP “Distributable cash flow”

12

Acquisitions

     Since our initial public offering in October 2002, we have completed ten acquisitions for an aggregate purchase price of $295 million. These acquisitions included approximately 824 million tons of coal reserves on approximately 998,000 mineral acres. Listed below are the acquisitions we have made in 2004 and 2005.

     2005 Acquisitions

     Plum Creek. On March 3, 2005, we completed an acquisition of coal reserves from Plum Creek Timber Company, Inc. The purchase price was $21.25 million and was funded through a combination of our revolving credit facility and $3.25 million in cash. This property consists of approximately 85 million tons of coal reserves located on approximately 175,000 acres in Virginia, West Virginia and Kentucky with most of the reserves leased under 29 leases.

     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.

Critical Accounting Policies

     Coal Royalties. We recognize coal royalty revenues on the basis of tons of coal sold by our lessees and the corresponding revenue from those sales. Generally, the lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time (usually three to five years) if sufficient royalties are generated from coal production in future periods. We do not recognize these minimum coal royalties as revenue until the applicable recoupment period has expired or they are recouped through production. Until recognized as revenue, these minimum royalties are carried as deferred revenue, a liability on the balance sheet.

     Timber Royalties. We primarily sell timber on a contract basis where independent contractors harvest and sell the timber. From time to time, we also sell timber in a competitive bid process. We recognize timber revenues when the independent contractors have harvested the timber, because title and risk of loss pass to the independent contractors at that time. When our timber is sold in a competitive bid process, we recognize revenue upon completion of the sale.

     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.

13

     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. Timberlands are stated at cost less depletion. We determine the cost of the timber harvested based on the volume of timber harvested in relation to the amount of estimated net merchantable volume by geographic areas. We estimate our timber inventory using statistical information and data obtained from physical measurements and other information gathering techniques. We update these estimates annually, which may result in adjustments of timber volumes and depletion rates that are recognized prospectively. Changes in these estimates have no effect on our cash flow.

New Accounting Standards

     Statement of Financial Accounting Standards No. 123R “Accounting for Stock-Based Compensation,” revised in 2004, superseded APB No. 25. Awards under our Long Term Incentive Plan have been accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R, effective for the first quarter of 2006, requires us to recognize a cumulative effect of the accounting change at the date of adoption based on the difference between the fair value of the unvested awards and the intrinsic value recorded. Additionally, FAS 123R provides that grants after the effective date must be accounted for using the fair value method which will require us to estimate the fair value of the grant using the Black-Scholes or another method and charge the estimated fair value to expense over the service or vesting period of the grant. FAS 123R requires that the fair value be recalculated at each reporting date over the service or vesting period of the grant. Use of the fair value method as compared with the intrinsic method, will not change the total expense to be reflected for a grant but it may impact the period in which expense is reflected by increasing expense in one period based upon the fair value calculation and lowering expense in a different period. We are in the process of evaluating the impact of the adoption of FAS 123R.

14

Results of Operations

Natural Resource Partners L.P.

     Three months ended March 31, 2005 compared with three months ended March 31, 2004

     Revenues. For the quarter ended March 31, 2005, coal royalty revenues were $32.5 million on 12.8 million tons of coal produced, compared to $22.9 million in coal royalty revenues on 11.6 million tons of coal produced for the first quarter of 2004, representing a 42% increase in coal royalty revenues and a 10% increase in production. Coal royalty revenues comprise 90% of our total revenue, with property taxes, minimums recognized as revenue, override royalties and other totaling $3.7 million, or 10% of total revenue.

15

     The following is a breakdown of our major coal producing regions:

     Appalachia. As a result of significantly higher prices, coal royalty revenues in Appalachia for the quarter ended March 31, 2005 were $29.7 million compared to $21.3 million for the same period in 2004, an increase of $8.4 million or 39%. For the quarter ended March 31, 2005, production in Appalachia was 10.9 million tons compared to 10.3 million tons for the same period in 2004, an increase of 0.5 million tons or 5%.

     The following properties generated significantly higher production and/or coal royalty revenues during the quarter ended March 31, 2005.

	•	Pinnacle – production increased from zero tons to 610,000 tons while coal royalty revenues increased to $2.0 million. The increased tonnage was due to the mine resuming production after being idle during the quarter ended March 31, 2004 due to a ventilation disruption.
	•	Sincell – production increased from 61,000 tons to 820,000 tons and coal royalty revenues increased from $95,000 to $1.6 million. The increased production was due to a longwall unit moving onto our property.
	•	Eunice – production increased from 668,000 tons to 919,000 tons and coal royalty revenues increased from $1.2 million to $2.4 million. The increased tonnage was due to higher production by the longwall unit on our property.
	•	BLC Properties – production increased from 782,000 tons to 869,000 tons and coal royalty revenues increased from $1.8 million to $2.9 million. These increases in tonnage were due to a combination of some lessees increasing production and some having a greater proportion of production on our property, which offset reductions by a lessee who experienced geologic problems.
	•	Dorothy – production increased from 366,000 tons to 493,000 tons and coal royalty revenues increased from $747,000 to $1.5 million. The increased tonnage was due to additional producing units being on our property.
	•	Pardee – production increased from 346,000 tons to 459,000 tons and coal royalty revenues increased from $967,000 to $1.7 million. The increased production was due to a greater proportion of production from the mine being on our property.

     These increases were partially offset by lower production on our West Fork property. Production decreased from 776,000 tons to zero and royalty revenues decreased from $1.8 million to zero as longwall mining was completed on our property.

     Illinois Basin. On our Cummings/Hocking Wolford property, production increased from 247,000 tons to 452,000 tons and coal royalty revenues increased from $265,000 to $631,000. The increased production was due to a greater proportion of production being on our property and an increase in the royalty rate under the lease terms. Our Sato property production increased from 199,000 tons to 277,000 tons and coal royalty revenues increased from $273,000 to $451,000. The increased production was due to higher production from the active mine on our property.

     Northern Powder River Basin. Production from our Western Energy property increased from 686,000 tons to 1.0 million tons and coal royalty revenues increased from $850,000 to $1.6 million. These increases were due to the typical variations in production resulting from the checkerboard ownership pattern.

     Expenses. For the quarter ended March 31, 2005, total expenses were $13.6 million, compared to $11.8 million for the first quarter of 2004, representing an increase of $1.8 million, or 15%. Included in total expenses are:

	•	Depletion and amortization of $7.9 million for the first quarter of 2005, compared to $7.1 million for the first quarter of 2004, an increase of $0.8 million, or 11% due to the increase in production volumes;
	•	General and administrative expenses of $3.3 million for the first quarter of 2005, compared to $2.7 million for the first quarter of 2004, an increase of $0.6 million, or 22%. 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 $1.8 million for the first quarter of 2005, compared to $1.7 million for the first quarter of

16

2004, an increase of $0.1 million, or 10%, due to an increase in franchise taxes for 2005.

     Interest Expense. For the quarter ended March 31, 2005, interest expense was $2.5 million compared to $3.4 million for 2004, a decrease of $0.9 million. This decrease is attributed to lower outstanding balances on our credit facility and senior notes during the first quarter of 2005.

Related Party Transactions

Partnership Agreement

     Our general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with our partnership agreement, our general partner and its affiliates are reimbursed for expenses incurred on our behalf. All direct general and administrative expenses are charged to us as incurred. We also reimburse indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates. 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 $0.9 million and $1.0 million for the three months ended March 31, 2005 and 2004, respectively.

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 is one of our largest lessees. 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 362.5 million tons of proven and probable reserves as of December 31, 2004.
	•	Kingwood in West Virginia, which contains 17.8 million tons of proven and probable reserves as of December 31, 2004.
	•	Welch/Wyoming in West Virginia, which contains 7.5 million tons of proven and probable reserves as of December 31, 2004.
	•	Kentucky Land in Kentucky, which contains 20.3 million tons of proven and probable reserves as of December 31, 2004.

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

     Coal royalty revenues payable under these leases based on first quarter 2005 production totaled $4.8 million, representing 15% of our total coal royalty revenues for the three months ended March 31, 2005. If no production had taken place in 2005, minimum recoupable royalties of $1.1 million would have been payable under the leases. At March 31, 2005 we had accounts receivable outstanding of $0.9 million with Alpha Natural Resources.

     We believe the production and minimum royalty rates contained in the Alpha leases are consistent with current market royalty rates.

Foundation Coal Holdings, Inc.

     First Reserve also has a significant interest in Foundation Coal Holdings, Inc. who controls our lessee on our Kingston Property in West Virginia, which contains approximately 7.7 million tons of proven and probable reserves as of December 31, 2004.

     The Kingston lease has a term of ten years with the ability to renew the lease for subsequent terms of five years unless the lessee gives notice it will not renew the lease. The lease provides for payments to us based on the higher of a percentage of the gross sales price or a fixed minimum per ton of coal sold from the properties, with annual minimum payments. Under the Kingston lease minimum royalty payments are credited against future production royalties. We believe the production and minimum royalty rates contained in the Kingston lease are consistent with current market royalty rates.

17

     Coal royalty revenues payable under the lease based on 2005 production totaled $0.9 million, representing 3% of our coal royalty revenues for the three months ended March 31, 2005. If no production had taken place in 2005, minimum recoupable royalties of $0.3 million would have been payable under the lease. At March 31, 2005 we had accounts receivable outstanding of $0.3 million with Foundation Coal Holdings, Inc.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

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

     Net cash provided by operations for the quarters ended March 31, 2005 and 2004 was $26.1 million and $18.9 million, respectively. Substantially all of our cash provided by operations is generated from coal royalty revenues.

     Net cash used in investing activities for the quarter ended March 31, 2005 was $21.5 million compared to $75.7 million for 2004. The 2005 results include the acquisition of coal reserves from Plum Creek Timber Company, Inc. Net cash used in investing activities for 2004 include the acquisitions of coal reserves from BLC and Apollo.

     Net cash provided by financing activities for the quarter ending March 31, 2005 was $0.5 million compared to $62.4 million for the same period a year ago. In the quarter ending March 31, 2005, we borrowed $18.0 million under our credit facility to fund the Plum Creek acquisition and paid $17.5 million in distributions to our partners. The first quarter 2004 results include $200.4 million in net proceeds from our equity offering in March 2004, a $2.1 million capital contribution from our general partner to maintain its 2% general partner interest, as well as $75.5 million in proceeds from borrowings on our credit facility. We used $102.5 million of the net proceeds from the equity offering to pay the outstanding balance on our credit facility and $100.1 million to redeem 2.6 million common units owned by Arch Coal. We also paid distributions to our partners totaling $13 million.

Contractual Obligations and Commercial Commitments

     At March 31, 2005, our debt consisted of:

	•	$175 million revolving credit facility that matures in October 2009, of which $157 million was available at March 31, 2005;
	•	$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 replaced NRP Operating’s previous 3-year facility, which would have expired in October 2005. In addition to substantially improved pricing terms, the new facility permits NRP Operating to increase the size of the facility up to $300 million without obtaining lender consents. As a result of entering into the new credit facility, we expensed $1.1 million in the fourth quarter 2004 of unamortized loan financing costs related to NRP Operating’s early extinguishment of its previous credit facility.

     Our obligations under the new credit facility are unsecured but are guaranteed by our operating subsidiaries. We may prepay all loans at any time without penalty. Indebtedness under the revolving credit facility bears interest, at our option, at either:

18

•

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 revolving credit facility at rates ranging from 0.30% to 0.40% per annum.

     The credit agreement contains covenants requiring us to maintain:

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

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

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

•

not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and

•

maintain the ratio of consolidated EBITDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.

     The following table reflects our long-term non-cancelable contractual obligations as of March 31, 2005 (in millions):

Shelf Registration Statement

     On December 23, 2003, we and our operating subsidiaries jointly filed a $500 million “universal shelf” registration statement with the Securities and Exchange Commission for the proposed sale of debt and equity securities. Securities issued under this registration statement may be in the form of common units representing limited partner interests in Natural Resource Partners or debt securities of NRP or any of our operating subsidiaries. We currently have approximately $290.2 million available under our registration statement. The registration statement also covers, for possible future sales, up to 373,715 common units held by Great Northern Properties Limited Partnership.

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

19

     Inflation

     Inflation in the United States has been relatively low in recent years and did not have a material impact on operations for the first quarter of 2005 or 2004.

     Environmental

     The operations our lessees conduct on our properties are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As an owner of surface interests in some properties, we may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of our coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify us against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Because we have no employees, employees of Western Pocahontas Properties Limited Partnership make regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. We believe that our lessees will be able to comply with existing regulations and do not expect any lessee’s failure to comply with environmental laws and regulations to have a material impact on our financial condition or results of operations. We have neither incurred, nor are aware of, any material environmental charges imposed on us related to our properties for the period ended March 31, 2005. We are not associated with any environmental contamination that may require remediation costs. However, our lessees do conduct reclamation work on the properties under lease to them. Because we are not the permittee of the mines being reclaimed, we are not responsible for the costs associated with these reclamation operations. In addition, West Virginia has established a fund to satisfy any shortfall in our lessees’ reclamation obligations. We are also indemnified by Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and Arch Coal, Inc., jointly and severally, until October 17, 2005 against environmental and tax liabilities attributable to the ownership and operation of the assets contributed to us prior to the closing of the initial public offering. The environmental indemnity is limited to a maximum of $10.0 million.

     Risks Related to Our Business

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

20

		subject to variable interest rates based upon LIBOR.
	•	Our lessees are subject to federal, state and local laws and regulations that may limit their ability to produce and sell coal from our properties.
	•	A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period.

Item 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 effective marketing and efficient mining of our coal reserves by our lessees. Our lessees sell coal under various long-term and short-term contracts as well as on the spot market. A large portion of these sales are 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 or 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. At March 31, 2005, we had outstanding $18.0 million in variable interest rate debt. If LIBOR rates were to increase by 100 basis points, annual interest expense would increase by $180,000, assuming the same principal amount remained outstanding over the next twelve months.

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 information to management as appropriate to allow for timely decisions with regard to required disclosure.

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

21

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.

22

Item 6. Exhibits

23

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.

Date: May 4, 2005

	By:	/s/ Corbin J. Robertson, Jr.
		Corbin J. Robertson, Jr.,
		Chairman of the Board and Chief Executive Officer (Principal Executive Officer)

Date: May 4, 2005

	By:	/s/ Dwight L. Dunlap
		Dwight L. Dunlap,
		Chief Financial Officer and Treasurer (Principal Financial Officer)

Date: May 4, 2005

	By:	/s/ Kenneth Hudson
		Kenneth Hudson
		Controller (Principal Accounting Officer)

24

Exhibit Index