UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

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 June 30, 2007

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

NATURAL RESOURCE PARTNERS L.P.

Delaware		35-2164875
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

o Large Accelerated Filer                    þ Accelerated Filer                    o Non-accelerated Filer

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

At August 6, 2007 there were outstanding 53,537,502 Common Units and 11,353,634 Subordinated Units.

 

 

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2007 and December 31, 2006			4
Consolidated Statements of Income For the Three and Six Months Ended June 30, 2007 and 2006			5
Consolidated Statements of Cash Flows For the Six Months Ended June 30, 2007 and 2006			6
Notes to Consolidated Financial Statements			7
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview			15
Results of Operations			18
Liquidity and Capital Resources			22
Related Party Transactions			24
Environmental			25
ITEM 3. Quantitative And Qualitative Disclosures About Market Risk			25
ITEM 4. Controls And Procedures			25
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings			26
ITEM 1A. Risk Factors			26
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds			26
ITEM 3. Defaults Upon Senior Securities			26
ITEM 4. Submission Of Matters to a Vote of Security Holders			26
ITEM 5. Other Information			26
ITEM 6. Exhibits			27
Signatures			28
Certification of Chief Executive Officer Pursuant to 302
Certification of Chief Financial Officer Pursuant to 302
Certification of Chief Executive Officer
Certification of Chief Financial Officer

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 and other revenues 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 “Item 1A Risk Factors” in this Form 10-Q and our Form 10-K for the year ended December 31, 2006 for important factors that could cause our actual results of operations or our actual financial condition to differ.

Part I. Financial Information

Item 1. Financial Statements

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS
(In thousands)

		June 30,				December 31,
		2007				2006
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	54,454			$	66,044
Restricted cash			6,314				—
Accounts receivable, net of allowance for doubtful accounts			25,607				23,357
Accounts receivable — affiliate			570				21
Other			514				1,411
Total current assets			87,459				90,833
Land			24,522				17,781
Plant and equipment, net			55,245				29,615
Coal and other mineral rights, net			1,015,616				798,135
Intangible assets, net			111,511				—
Loan financing costs, net			3,300				2,197
Other assets, net			1,032				932
Total assets		$	1,298,685			$	939,493
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities		$	2,736			$	1,041
Accounts payable — affiliate			105				105
Current portion of long-term debt			9,542				9,542
Accrued incentive plan expenses — current portion			4,127				5,418
Property, franchise and other taxes payable			4,589				4,330
Accrued interest			6,443				3,846
Total current liabilities			27,542				24,282
Deferred revenue			28,571				20,654
Asset retirement obligation			39				—
Accrued incentive plan expenses			5,237				4,579
Long-term debt			474,149				454,291
Partners’ capital:
Common units			667,095				338,912
Subordinated units			79,973				83,772
General partners’ interest			16,412				12,138
Holders of incentive distribution rights			392				1,616
Accumulated other comprehensive loss			(725	)			(751	)
Total partners’ capital			763,147				435,687
Total liabilities and partners’ capital		$	1,298,685			$	939,493

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per unit data)

		Three months ended								Six months ended
		June 30,								June 30,
		2007				2006				2007				2006
						(Unaudited)
Revenues:
Coal royalties		$	40,733			$	36,527			$	81,706			$	75,637
Aggregate royalties			1,944				—				3,689				—
Coal processing fees			1,112				—				2,030				—
Transportation fees			845				—				1,306				—
Oil and gas royalties			1,278				928				2,536				2,647
Property taxes			2,645				1,546				4,873				3,295
Minimums recognized as revenue			331				250				785				621
Override royalties			1,023				181				2,041				484
Other			1,186				1,550				2,338				4,826
Total revenues			51,097				40,982				101,304				87,510
Operating costs and expenses:
Depreciation, depletion and amortization			12,527				7,236				24,279				15,089
General and administrative			5,559				3,420				12,193				7,535
Property, franchise and other taxes			3,524				2,099				6,625				4,344
Transportation costs			27				—				70				—
Coal royalty and override payments			382				263				668				954
Total operating costs and expenses			22,019				13,018				43,835				27,922
Income from operations			29,078				27,964				57,469				59,588
Other income (expense)
Interest expense			(7,133	)			(3,675	)			(14,460	)			(7,293	)
Interest income			686				755				1,503				1,273
Net income		$	22,631			$	25,044			$	44,512			$	53,568
Net income attributable to:
General partner(1)		$	3,074			$	2,253			$	5,893			$	4,348
Other holders of incentive distribution rights(1)		$	1,412			$	943			$	2,695			$	1,764
Limited partners		$	18,145			$	21,848			$	35,924			$	47,456
Basic and diluted net income per limited partner unit:
Common		$	0.28			$	0.43			$	0.56			$	0.94
Subordinated		$	0.28			$	0.43			$	0.56			$	0.94
Class B		$	0.28			$	—			$	0.56			$	—
Weighted average number of units outstanding:
Common			52,925				33,651				51,914				33,651
Subordinated			11,354				17,030				11,354				17,030
Class B			607				—				826				—

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

		Six months ended
		June 30,
		2007				2006
		(Unaudited)
Cash flows from operating activities:
Net income		$	44,512			$	53,568
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			24,279				15,089
Non-cash interest charge			209				191
Gain on sale of timber assets			—				(2,634	)
Change in operating assets and liabilities:
Accounts receivable			(2,799	)			(107	)
Other assets			557				243
Accounts payable and accrued liabilities			(294	)			(20	)
Accrued interest			2,597				1,217
Deferred revenue			7,917				408
Accrued incentive plan expenses			(633	)			1,510
Property, franchise and other taxes payable			259				(305	)
Net cash provided by operating activities			76,604				69,160
Cash flows from investing activities:
Acquisition of land, plant and equipment, coal and other mineral rights			(32,633	)			(51,438	)
Proceeds from sale of timber assets			—				4,761
Cash placed in restricted accounts			(6,314	)			—
Net cash used in investing activities			(38,947	)			(46,677	)
Cash flows from financing activities:
Proceeds from loans			255,400				50,000
Deferred financing costs			(1,286	)			—
Repayment of loans			(235,542	)			(24,350	)
Distributions to partners			(70,464	)			(43,204	)
Contribution by general partner			2,645				—
Net cash used in financing activities			(49,247	)			(17,554	)
Net increase (decrease) in cash and cash equivalents			(11,590	)			4,929
Cash and cash equivalents at beginning of period			66,044				47,691
Cash and cash equivalents at end of period		$	54,454			$	52,620
Supplemental cash flow information:
Cash paid during the period for interest		$	11,627			$	5,861
Non-cash investing activities:
Units issued in business combinations		$	350,741			$	—
Liability assumed in business combination			1,989				—

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

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 six months ended June 30, 2007 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 2006 Annual Report on Form 10-K in connection with the reading of these unaudited interim consolidated financial statements.

     The Partnership engages principally in the business of owning, managing and leasing 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 royalty per ton of coal sold, in addition to a minimum payment.

     In addition, the Partnership owns coal transportation and preparation equipment, aggregate reserves, other coal related rights and oil and gas properties on which it earns revenue.

     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.

Business Combinations

     For purchase acquisitions accounted for as a business combination, the Partnership is required to record the assets acquired, including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques. The determination of the useful lives of intangible assets is subjective, as is the appropriate amortization method for such intangible assets. In addition, purchase acquisitions may result in goodwill, which is subject to ongoing periodic impairment testing based on the fair value of net assets acquired compared to the carrying value of goodwill. For additional discussion concerning our valuation of intangible assets, see Note 6, “Intangible Assets.”

New Accounting Standard

     In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115, which provides companies with an option to report selected financial assets and liabilities at fair value. The objective of SFAS No. 159 is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. The Partnership has not yet determined the impact on our financial statements of adopting SFAS No. 159 effective January 1, 2008.

3. Significant Acquisitions

     The following briefly describes the Partnership’s acquisition activity for the six months ended June 30, 2007:

	•		Mid-Vol Coal Preparation Plant. On May 21, 2007, the Partnership signed an agreement for the construction of a coal preparation plant, coal handling infrastructure and a rail load-out facility under its memorandum of understanding with Taggart Global USA, LLC. Consideration for the facility, located near Eckman, WV, is estimated to be approximately $16.2 million, of which $8.4 million was paid at closing for construction costs incurred to date.
	•		Mettiki. On April 3, 2007, the Partnership acquired approximately 35 million tons of coal reserves in Grant and Tucker Counties in Northern West Virginia for total consideration of 500,000 common units and approximately $10.2 million in cash. The assets were acquired from Western Pocahontas Properties Limited Partnership under the Partnership’s omnibus agreement. Western Pocahontas Properties has retained an overriding royalty interest on approximately 16 million tons of non-permitted reserves, which will be offered to the Partnership at the time those reserves are permitted.
	•		Westmoreland. On February 27, 2007, the Partnership acquired an overriding royalty on 225 million tons of coal in the Powder River Basin from Westmoreland Coal Company for $12.7 million in cash. The reserves are located in the Rocky Butte Reserve in Wyoming.
	•		Dingess-Rum. On January 16, 2007, the Partnership acquired 92 million tons of coal reserves and approximately 33,700 acres of surface and timber in Logan, Clay and Nicholas Counties in West Virginia from Dingess-Rum Properties, Inc. As consideration for the acquisition, the Partnership issued 4,800,000 common units to Dingess-Rum.
	•		Cline. On January 4, 2007, the Partnership acquired 49 million tons of coal reserves in Williamson County, Illinois and Mason County, West Virginia that are leased to affiliates of The Cline Group. In addition, it acquired transportation assets and related infrastructure at those mines. As consideration for the transaction the Partnership issued 7,826,160 common units and 1,083,912 Class B units representing limited partner interests in NRP. The Class B units were converted to common units during the second quarter.

     The Dingess-Rum and Cline acquisitions were accounted for as business combinations and, in the case of the Cline transaction, in the initial allocation, the purchase price exceeded the value of the identified tangible and intangible assets acquired, resulting in $15.8 million of goodwill being recorded as intangible assets as of March 31, 2007. In accordance with Statement of Financial Accounting Standards No. 141, Business Combinations, the Company continued the process of identifying and valuing the assets received in the transaction and refining the value of the consideration exchanged. Among other changes, this process resulted in the identification of certain additional intangible assets related to future revenue and an increase in the discount percentage applied to the common units issued as consideration. The impact of the changes resulted in an increase in finite-lived intangible assets and the elimination of the amount of goodwill recorded during the first quarter based on the initial valuation.

     The Partnership is continuing to evaluate the purchase price allocations for the acquisitions completed during the first quarter that were accounted for as business combinations and will further adjust the allocations if additional information relative to the fair market values of the assets and liabilities of the businesses become known or other information related to the fair value of consideration is received.

     The Cline transaction included the acquisition of four entities, none of which had conducted operations or generated material amounts of revenue or operating cost prior to acquisition. Total net operating losses of the four entities from startup through December 31, 2006 were $0.3 million. In the Dingess-Rum transaction, the Partnership acquired a group of assets from an entity that was formed for purposes of the transaction. That entity did not operate the assets acquired. Therefore, unaudited pro forma information of prior periods is not presented as it would not differ materially from the historic operations of the Partnership.

     The following table summarizes the aggregate estimated fair values of the assets acquired and liabilities assumed for each of the transactions accounted for as a business combination as of June 30, 2007:

		Dingess-Rum				Cline
		(In thousands)
Land, plant and equipment		$	7,935			$	17,783
Coal and other mineral rights			105,573				94,463
Other assets							72
Intangible assets							111,960
Equity consideration			113,396				221,089
Transaction costs and liabilities assumed			112				3,189

4. Plant and Equipment

     The Partnership’s plant and equipment consist of the following:

		June 30,				December 31,
		2007				2006
		(In thousands)
		(Unaudited)
Plant and equipment at cost		$	57,703			$	30,266
Accumulated depreciation			(2,458	)			(651	)
Net book value		$	55,245			$	29,615

		Six months ended
		June 30,
		2007				2006
		(In thousands)
		(Unaudited)
Total depreciation expense on plant and equipment		$	1,807			$	164

5. Coal and Other Mineral Rights

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

		June 30,				December 31,
		2007				2006
		(In thousands)
		(Unaudited)
Coal and other mineral rights		$	1,209,531			$	970,342
Less accumulated depletion and amortization			(193,915	)			(172,207	)
Net book value		$	1,015,616			$	798,135

		Six months ended
		June 30,
		2007				2006
		(In thousands)
		(Unaudited)
Total depletion and amortization expense on coal and other mineral interests		$	21,708			$	14,599

6. Intangible Assets

     During January 2007, the Partnership completed a business combination in which certain intangible assets were identified related to the royalty and lease rates of contracts acquired when compared to the estimate of current market rates for similar contracts. The estimated fair value of the above-market rate contracts was determined based on the present value of future cash flow projections related to the underlying coal reserves and transportation infrastructure acquired. In addition, in the second quarter, as part of the continuing identification of the assets acquired and refining the value of the consideration exchanged in the transaction, other intangible assets related to future revenues from the contractual rights to an area of mutual interest were identified, quantified and recorded. Further, changes in the discount rate used to value the common units issued in the transaction reduced the total consideration exchanged. These changes, along with others, increased the value of finite-lived intangibles and eliminated the goodwill recorded as part of the initial valuation. Amounts initially recorded as intangible assets along with the balances and accumulated amortization at June 30, 2007 are reflected in the table below.

						As of June 30, 2007
		As Originally				Gross Carrying				Accumulated
		Recorded				Amount				Amortization
						(In thousands)
						(Unaudited)
Finite-lived intangible assets
Above market transportation contracts		$	68,236			$	80,525			$	345
Above market coal leases			23,108				25,132				104
Contractual rights to an area of mutual interest			—				6,303				—
		$	91,344			$	111,960			$	449
Indefinite-lived intangible assets
Goodwill		$	15,817			$	—

     Amortization expense related to these contract intangibles was $315,000 and $449,000 for the three-month and six-month periods ended June 30, 2007 and is based upon the production and sales of coal from acquired reserves and the number of tons of coal transported using the transportation infrastructure. The estimates of expense for the periods as indicated below are based on current mining plans and are subject to revision as those plans change in future periods.

Estimated amortization expense (In thousands)
For remainder of year ended December 31, 2007		$	1,930
For year ended December 31, 2008			7,095
For year ended December 31, 2009			7,076
For year ended December 31, 2010			7,418
For year ended December 31, 2011			7,577
For year ended December 31, 2012			7,855

7. Two-For-One Limited Partner Unit Split

     On March 6, 2007 the Board of Directors approved a two-for-one split for all of the Partnership’s outstanding units. The unit split was effective for unitholders at the close of business on April 9, 2007 and entitled them to receive one additional unit for each unit held at that date. The additional units were distributed on April 18, 2007. All unit and per unit information in the accompanying financial statements, including distributions per unit, have been adjusted to retroactively reflect the impact of the two-for-one split.

8. Long-Term Debt

     Long-term debt consists of the following:

		June 30,				December 31,
		2007				2006
		(In thousands)
		(Unaudited)
$300 million floating rate revolving credit facility, due March 2012		$	18,400			$	214,000
5.55% senior notes, with semi-annual interest payments in June and December, maturing June 2013			35,000				35,000
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018			55,800				61,850
5.05% senior notes, with semi-annual interest payments in January and July, with scheduled principal payments beginning July 2008, maturing in July 2020			100,000				100,000
5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021			2,691				2,883
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023			46,800				50,100
5.82% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2010, maturing in March 2024			225,000				—
Total debt			483,691				463,833
Less — current portion of long term debt			(9,542	)			(9,542	)
Long-term debt		$	474,149			$	454,291

     On March 28, 2007, the Partnership completed an amendment and extension of its $300 million revolving credit facility. The amendment extends the term of the credit facility by two years to 2012 and lowers borrowing costs and commitment fees. The amendment also includes an option to increase the credit facility at least twice a year up to a maximum of $450 million under the same terms, as well as an annual option to extend the term by one year.

     The Partnership also issued $225 million in 5.82% senior notes on March 28, 2007, with semi-annual interest payments in March and September and scheduled principal payments beginning March 2010. The Partnership used the proceeds to pay down its credit facility.

     At June 30, 2007, the Partnership had an $18.4 million outstanding balance on its revolving credit facility. The Partnership incurs a commitment fee on the undrawn portion of the revolving credit facility at rates ranging from 0.10% to 0.30% per annum.

     The Partnership was in compliance with all terms under its long-term debt as of June 30, 2007.

9. 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, subordinated and Class B 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. All per unit amounts have been restated to reflect the two-for-one split of limited partner units.

10. Related Party Transactions

Reimbursements to Affiliates of our General Partner

     The Partnership’s 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. The Partnership also reimburses 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 the Partnership’s general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation totaled $1.3 million and $1.0 million for the three month periods ended June 30, 2007 and 2006, respectively and $2.5 million and $2.0 million for the six month periods ended June 30, 2007 and 2006, respectively.

Transactions with Cline Affiliates

     Williamson Energy, LLC, a company controlled by Chris Cline, leases coal reserves from the Partnership, and the Partnership provides transportation services to Williamson for a fee. Mr. Cline, through another affiliate, Adena Minerals, LLC, owns a 22% interest in our general partner, as well as 8,910,072 common units. At June 30, 2007, the Partnership had accounts receivable totaling $0.1 million from Williamson. For the three and six month periods ended June 30, 2007, the Partnership had total revenue of $0.4 million and $1.1 million from Williamson. In addition, the Partnership also received $3.1 million in advance minimum royalty payments that have not been recouped.

     Gatling, LLC, a company also controlled by Chris Cline, leases coal reserves from the Partnership and the Partnership provides transportation services to Gatling for a fee. At June 30, 2007, the Partnership had accounts receivable totaling $0.1 million from Gatling. For the three and six month periods ended June 30, 2007, the Partnership had total revenue of $0.9 million and $1.1 million from Gatling, LLC. In addition, the Partnership also received $3.0 million in advance minimum royalty payments that have not been recouped.

Quintana Energy Partners, L.P.

     In 2006, Corbin J. Robertson, Jr. formed Quintana Energy Partners, L.P., or QEP, a private equity fund focused on investments in the energy business. In connection with the formation of QEP, the Partnership general partner’s board of directors adopted a conflicts policy that establishes the opportunities that will be pursued by NRP and those that will be pursued by QEP. For a more detailed description of this policy, please see “Item 13. Certain Relationships and Related Transactions, and Director Independence” in our Form 10-K.

     In February 2007, QEP acquired a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. The Partnership currently has a memorandum of understanding with Taggart Global pursuant to which the two companies have agreed to jointly pursue the development of coal handling and preparation plants. The Partnership will own and lease the plants to Taggart Global, which will design, build and operate the plants. The lease payments are based on the sales price for the coal that is processed through the facilities. To date, the Partnership has acquired three facilities under this agreement with Taggart, and for the three and six month periods ended June 30, 2007, the Partnership received total revenue of $0.7 million and $1.2 million, respectively from Taggart. At June 30, 2007, the Partnership had accounts receivable totaling $0.2 million from Taggart.

11. Commitments and Contingencies

Legal

     The Partnership is involved, from time to time, in various other 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 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. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties as of June 30, 2007. The Partnership is not associated with any environmental contamination that may require remediation costs.

12. Major Customers

     Revenues from major lessees or other customers that exceeded ten percent of total revenues for the periods indicated below are as follows:

		Three months ended																Six months ended
		June 30,																June 30,
		2007								2006								2007								2006
		Revenues				Percent				Revenues				Percent				Revenues				Percent				Revenues				Percent
						Dollars in thousands																Dollars in thousands
						(Unaudited)																(Unaudited)
Lessee A			7,860				15.4	%			897				2.2	%			14,544				14.4	%			2,172				2.5	%
Lessee B			4,931				9.7	%			5,530				13.5	%			10,670				10.5	%			11,371				13.0	%

13. Incentive Plans

     GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the “Long-Term Incentive Plan”) for directors of GP Natural Resource Partners LLC and employees of 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.

     Under the plan a grantee will receive the market value of a common unit in cash upon vesting. Market value is defined as the average closing price over the last 20 trading days prior to the vesting date. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines, including the vesting period. Outstanding grants 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, outstanding grants will be automatically forfeited unless and to the extent the compensation committee provides otherwise.

     A summary of activity in the outstanding grants for the first six months of 2007 are as follows:

Outstanding grants at the beginning of the period			515,220
Grants during the period			174,002
Grants vested and paid during the period			(181,356	)
Forfeitures during the period			(400	)
Outstanding grants at the end of the period			507,466

     Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The liability fluctuates with the market value of the Partnership units and because of changes in estimated fair value determined each quarter using the Black-Scholes option valuation model. Risk free interest rates and volatility are reset at each calculation based on current rates corresponding to the remaining vesting term for each outstanding grant and ranged from 4.76% to 4.89% and 21.77% to 24.88%, respectively at June 30, 2007. The Partnership’s historic dividend rate of 5.86% was used in the calculation at June 30, 2007. The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $2.4 million and $0.9 million for the three months ended June 30, 2007 and 2006, respectively and $4.2 million and $2.2 million for the six month periods ended June 30, 2007 and 2006, respectively. Included in the first quarter of 2006, was $661,000 related to the cumulative effect of the change in accounting method for the adoption of FAS 123R. In connection with the Long-Term Incentive Plans, cash payments of $5.8 million and $0.8 million were paid during each of the six month periods ended June 30, 2007 and 2006, respectively. The unaccrued cost associated with the outstanding grants at June 30, 2007 was $11.5 million.

14. Distributions

     On May 14, 2007, the Partnership paid a cash distribution equal to $0.455 per unit to unitholders of record on May 1, 2007.

15. Subsequent Events

     On July 18, 2007, the Partnership declared a second quarter 2007 distribution of $0.465 per unit. The distribution will be paid on August 14, 2007 to unitholders of record on August 1, 2007.

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, 2007.

Executive Overview

     Our Business

     We engage principally in the business of owning, managing and leasing 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, 2006, we owned or controlled approximately 2.1 billion tons of proven and probable coal reserves in eleven states, and 60% of our reserves were low sulfur coal. We lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine and sell coal from our reserves in exchange for royalty payments.

     Our revenue and profitability are dependent on our lessees’ ability to mine and market our coal reserves. Most of our coal is produced by large companies, many of which are publicly traded, with experienced and professional sales departments. A significant portion 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.

     In our coal royalty business, our lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed royalty 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 those 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.

     In addition to coal royalty revenues, we generated approximately 20% of our second quarter revenues from other sources, compared to 11% for the same period in 2006. The increase represents our commitment to continuing to diversify our sources of revenue. These other sources include: aggregate royalties; coal processing and transportation fees; rentals; royalties on oil and gas and coalbed methane leases; timber; overriding royalty arrangements; and wheelage payments.

Current Results

     As of June 30, 2007, our reserves were subject to 188 leases with 69 lessees. For the quarter ended June 30, 2007, our lessees produced 13.6 million tons of coal generating $40.7 million in coal royalty revenues from our properties, and our total revenues were $51.1 million.

     Although we have recently acquired a large number of reserves in the Illinois Basin and diversified into aggregates and coal transportation and processing, a significant portion of our total revenue remains dependent upon Appalachian coal production and prices. Coal royalty revenues from our Appalachian properties represented 74% of our total revenues for both the quarter and the six months ended June 30, 2007. Approximately 27% of our coal royalty revenues and 22% of the related production during the first six months were from metallurgical coal, which is used in the production of steel. Prices of metallurgical coal have been substantially higher than steam coal over the past few years, and we expect them to remain at high levels for the next several years. The current pricing environment for U.S. metallurgical coal is strong in both the domestic and export markets.

     Several significant developments impacted our second quarter and first half results of operations. During the first quarter, we closed several acquisitions that we believe will be large positive contributors to our revenue over the long-term. However, the properties acquired in the Cline acquisition remain behind schedule in ramping up to full production and some of the properties acquired in the Dingess-Rum acquisition continued to experience operational and geological issues during the second quarter and some of the acquired properties incurred some temporary closures as a result of the pending permit litigation discussed below. We believe that the issues facing these mines are temporary, but do not expect to see the full benefits of the acquisitions during 2007.

     The difficulties at the Cline and Dingess-Rum properties were offset in part by the strong performance of the other assets we acquired in the last year. With respect to the rest of our properties, we have continued to benefit from the strong pricing environment, which has countered some modest production declines across the industry.

     Although we view coal prices in Appalachia as moving in a positive direction over the remainder of 2007, the political, legal and regulatory environment is becoming increasingly difficult for the coal industry. The recent judicial decision by the Southern District of West Virginia regarding permits issued under Section 404 of the Clean Water Act in West Virginia has created significant regulatory uncertainty for the coal industry. If the ruling is ultimately upheld on appeal, it could have long-term negative implications for the future of surface mining in Appalachia as well as our coal royalty revenues derived from that region.

Distributable Cash Flow

     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 important measure of our success as a company. Distributable cash flow is also the quantitative standard used in the investment community with respect to publicly traded partnerships.

     Our distributable cash flow represents cash flow from operations less actual principal payments and cash reserves set aside for scheduled principal payments on our 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”
(In thousands)

		For the quarter ended								For the six months ended
		June 30,								June 30,
		2007				2006				2007				2006
						(Unaudited)
Cash flow from operations		$	45,861			$	32,510			$	76,604			$	69,160
Less scheduled principal payments			(9,350	)			(9,350	)			(9,350	)			(9,350	)
Less reserves for future principal payments			(2,400	)			(2,350	)			(4,800	)			(4,700	)
Add reserves used for scheduled principal payments			9,400				9,400				9,400				9,400
Distributable cash flow		$	43,511			$	30,210			$	71,854			$	64,510

Acquisitions

     We are a growth-oriented company and have closed a number of acquisitions over the last several years. Our most recent acquisitions are briefly described below.

     Mid-Vol Coal Preparation Plant. On May 21, 2007, we signed an agreement for the construction of a coal preparation plant, coal handling infrastructure and a rail load-out facility under our memorandum of understanding with Taggart Global USA, LLC. Consideration for the facility, located near Eckman, WV, is estimated to be approximately $16.2 million, of which $8.4 million was paid at closing for construction costs incurred to date.

     Mettiki. On April 3, 2007, we acquired approximately 35 million tons of coal reserves in Grant and Tucker Counties in Northern West Virginia for total consideration of 500,000 NRP common units and approximately $10.2 million in cash. The assets were acquired from Western Pocahontas Properties under our omnibus agreement. Western Pocahontas Properties has retained an overriding royalty interest on approximately 16 million tons of non-permitted reserves, which will be offered to NRP at the time those reserves are permitted.

     Westmoreland. On February 27, 2007, we acquired an overriding royalty on 225 million tons of coal in the Powder River Basin from Westmoreland Coal Company for $12.7 million. The reserves are located in the Rocky Butte Reserve in Wyoming.

     Dingess-Rum. On January 16, 2007, we acquired 92 million tons of coal reserves and approximately 33,700 acres of surface and timber in Logan, Clay and Nicholas Counties in West Virginia from Dingess-Rum Properties, Inc. As consideration for the acquisition, we issued 4,800,000 common units to Dingess-Rum.

     Cline. On January 4, 2007, we acquired 49 million tons of reserves in Williamson County, Illinois and Mason County, West Virginia that are leased to affiliates of The Cline Group. In addition, we acquired transportation assets and related infrastructure at those mines. As consideration for the transaction we issued 7,826,160 common units and 1,083,912 Class B units representing limited partner interests in NRP. Through its affiliate Adena Minerals, LLC, The Cline Group received a 22% interest in our general partner and in the incentive distribution rights of NRP in return for providing NRP with the exclusive right to acquire additional reserves, royalty interests and certain transportation infrastructure relating to future mine developments by The Cline Group. Simultaneous with the closing of this transaction, we signed a definitive agreement to purchase the coal reserves and transportation infrastructure at Cline’s Gatling Ohio complex. This transaction will close upon commencement of coal production, which is currently expected to occur in 2008. At the time of closing, NRP will issue Adena 4,560,000 additional units, and the general partner of NRP will issue Adena an additional 9% interest in the general partner and the incentive distribution rights.

New Accounting Standard

     In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115, which provides companies with an option to report selected financial assets and liabilities at fair value. The objective of SFAS No. 159 is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. We have not yet determined the impact on our financial statements of adopting SFAS No. 159 effective January 1, 2008.

Results of Operations

		Three Months Ended
		June 30,								Increase				Percentage
		2007				2006				(Decrease)				Change
		(In thousands, except per ton data)
						(Unaudited)
Coal royalties
Appalachia
Northern		$	4,353			$	2,730			$	1,623				59	%
Central			28,339				24,543				3,796				15	%
Southern			4,989				5,133				(144	)			(3	%)
Total Appalachia			37,681				32,406				5,275				16	%
Illinois Basin			1,365				1,704				(339	)			(20	%)
Northern Powder River Basin			1,687				2,417				(730	)			(30	%)
Total		$	40,733			$	36,527			$	4,206				12	%
Production (tons)
Appalachia
Northern			1,901				1,482				419				28	%
Central			8,855				7,982				873				11	%
Southern			1,297				1,436				(139	)			(10	%)
Total Appalachia			12,053				10,900				1,153				11	%
Illinois Basin			659				977				(318	)			(33	%)
Northern Powder River Basin			861				1,497				(636	)			(42	%)
Total			13,573				13,374				199				1	%
Average gross royalty per ton
Appalachia
Northern		$	2.29			$	1.84			$	0.45				24	%
Central			3.20				3.07				0.13				4	%
Southern			3.85				3.58				0.27				7	%
Total Appalachia			3.13				2.97				0.16				5	%
Illinois Basin			2.07				1.74				0.33				19	%
Northern Powder River Basin			1.96				1.61				0.34				21	%
Combined average gross royalty per ton			3.00				2.73				0.27				10	%
Aggregates:
Revenue		$	1,944				—			$	1,944				100	%
Production			1,531				—				1,531				100	%
Average gross royalty		$	1.27				—			$	1.27				100	%

     Coal Royalty Revenues and Production. Coal royalty revenues comprised approximately 80% and 89% of our total revenue for each of the three month periods ended June 30, 2007 and 2006. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:

     Appalachia. As a result of acquisitions completed since the end of the second quarter of 2006 and slightly higher prices, both coal royalty revenues and production in Appalachia increased compared to same period in 2006. The Appalachian results by region are set forth below.

     Northern Appalachia. Coal royalty revenues and production increased primarily due to acquisitions completed since the end of the second quarter of 2006. Coal royalty revenues attributable to those acquisitions were $2.6 million and production was 1.0 million tons. These increases were partially offset by lower production at our Kingwood and AFC properties, where a greater proportion of the production for the quarter ended June 30, 2007 was on adjacent property compared to the quarter ended June 30, 2006.

     Central Appalachia. Coal royalty revenues attributable to acquisitions completed since the end of the second quarter of 2006 were $8.8 million and production was 2.4 million tons. Offsetting the coal royalty revenues and production from these acquisitions, our VICC/Kentucky Land, Pinnacle, Dorothy and Evans Lavier properties all had some mining activity move to

adjacent properties, resulting in an aggregate $4.5 million reduction in coal royalty revenues from those properties for the current quarter compared to the same period in 2006.

     Southern Appalachia. Our coal royalty revenues and production in Southern Appalachia decreased for the quarter ended June 30, 2007 compared to the quarter ended June 30, 2006 because our major lessees on our BLC Properties and Twin Pines/Drummond properties had more production coming from adjacent property.

     Illinois Basin. Coal royalty revenues and production attributable to our Williamson and James River acquisitions were $0.4 million and production was 0.2 million tons for the current quarter. This increase was partially offset by reduced production and coal royalty revenues on our Hocking Wolford/Cummings property as the lessee mined a greater proportion of their production on adjacent property.

     Northern Powder River Basin. The decrease in production on our Western Energy property was due to the normal variations that occur due to the checkerboard nature of our ownership, but was partially offset by higher prices being received by our lessee.

     Aggregates Royalty Revenues, Reserves and Production. In December 2006, we acquired aggregate reserves located in DuPont, Washington. For the quarter ended June 30, 2007, we recorded $1.9 million in royalty revenues from aggregates and had production of 1.5 million tons.

     Coal Transportation and Processing Revenues. In the second half of 2006, we acquired two preparation plants and coal handling facilities under our memorandum of understanding with Taggart Global. These facilities, combined with a third coal preparation plant and rail load-out facility that we acquired in Greenbrier County, West Virginia in 2005, generated approximately $1.1 million in coal processing fees for the quarter ended June 30, 2007. In addition, construction has begun on our Mid-Vol preparation plant, but we did not receive any processing revenues from that facility during the quarter. We do not operate the preparation plants, but receive a fee for coal processed through them. Similar to our coal royalty structure, the throughput fees are based on a percentage of the ultimate sales price for the coal that is processed through the facilities.

     In addition to our preparation plants, as part of the January 2007 Cline transaction, we acquired coal handling and transportation infrastructure associated with the Gatling mining complex in West Virginia and beltlines and rail load-out facilities associated with Williamson Energy’s Pond Creek No. 1 mine in Illinois. In contrast to our typical royalty structure, we are operating the coal handling and transportation infrastructure and have subcontracted out that responsibility to third parties. We anticipate that these assets will contribute significant revenues to us in future years. We generated approximately $0.8 million in transportation fees from these assets in the second quarter of 2007.

     Other revenues. Included in other revenues for the quarter ended June 30, 2006 is the sale of timber and related surface acreage located on our property in Wise and Dickenson Counties, Virginia. We received proceeds from the sale of $0.8 million, resulting in a gain of $0.5 million.

     Operating costs and expenses. Included in total expenses are:

	•		Depletion and amortization of $12.5 million, or $5.3 million over second quarter last year due to acquisitions made during the fourth quarter of 2006 and first half of 2007.
	•		General and administrative expenses of $5.6 million for the second quarter of 2007, compared to $3.4 million for the second quarter of 2006, an increase of $2.2 million, or 65% due predominately to accruals on long-term incentive plans and additional staff added to manage our acquisitions made in the first quarter of 2007.
	•		Property, franchise and other taxes of $3.5 million for the first quarter of 2007, compared to $2.1 million for the first quarter of 2006, an increase of $1.4 million, or 67%, due to taxes on additional properties we have acquired.

     Interest Expense. The increase in interest expense is attributed to borrowings on our credit facility and the issuance of senior notes used to fund acquisitions in 2006 and the first half of 2007.

		Six Months Ended
		June 30,								Increase				Percentage
		2007				2006				(Decrease)				Change
		(In thousands, except per ton data)
						(Unaudited)
Coal royalties
Appalachia
Northern		$	7,123			$	6,038			$	1,623				59	%
Central			58,586				50,385				3,795				15	%
Southern			9,028				10,617				(1,589	)			(15	%)
Total Appalachia			74,737				67,040				7,697				11	%
Illinois Basin			2,479				3,656				(1,177	)			(32	%)
Northern Powder River Basin			4,490				4,941				(451	)			(9	%)
Total		$	81,706			$	75,637			$	6,069				8	%
Production (tons)
Appalachia
Northern			3,235				3,214				21				1	%
Central			18,095				16,176				1,919				12	%
Southern			2,330				2,862				(532	)			(19	%)
Total Appalachia			23,660				22,252				1,408				6	%
Illinois Basin			1,161				2,140				(979	)			(46	%)
Northern Powder River Basin			2,261				2,998				(737	)			(25	%)
Total			27,082				27,390				(308	)			(1	%)
Average gross royalty per ton
Appalachia
Northern		$	2.20			$	1.88			$	0.32				17	%
Central			3.24				3.11				0.12				4	%
Southern			3.87				3.71				0.17				4	%
Total Appalachia			3.16				3.01				0.15				5	%
Illinois Basin			2.14				1.71				0.43				25	%
Northern Powder River Basin			1.99				1.65				0.34				20	%
Combined average gross royalty per ton			3.02				2.76				0.26				9	%
Aggregates:
Revenues		$	3,689				—			$	3,689				100	%
Production			2,872				—				2,872				100	%
Average gross royalty		$	1.28				—			$	1.28				100	%

     Coal Royalty Revenues and Production. Coal royalty revenues comprised approximately 81% and 86% of our total revenue for each of the six month periods ended June 30, 2007 and 2006. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:

     Appalachia. As a result of acquisitions completed since the end of the second quarter of 2006 and slightly higher prices, coal royalty revenues and production in Appalachia increased compared to the same period in 2006. The Appalachian results by region are set forth below.

     Northern Appalachia. Coal royalty revenues increased, while production stayed the same primarily due to acquisitions completed since the end of the second quarter of 2006. Coal royalty revenues attributable to those acquisitions were $3.1 million and production was 1.2 million tons. These increases were partially offset by lower production at our Sincell property, where longwall mining was completed, and our AFC and Kingwood properties, where a greater proportion of the production for the six months ended June 30, 2007 was on adjacent property compared to the six months ended June 30, 2006.

     Central Appalachia. Coal royalty revenues and production increased primarily as a result of acquisitions. Coal royalty revenues attributable to acquisitions completed since the end of the second quarter of 2006 were $17.4 million and production was 4.8 million tons. Offsetting the production from these acquisitions, our VICC/Kentucky Land, Pinnacle, Dorothy and Evans

Lavier properties all had some mining move to adjacent properties, resulting in reduced coal royalty revenues of approximately $8.6 million from these properties for the current year compared to the same period in 2006.

     Southern Appalachia. Our coal royalty revenues and production in Southern Appalachia decreased because our major lessees on our Twin Pines/Drummond and BLC Properties had more production coming from adjacent property.

     Illinois Basin. Coal royalty revenues and production in the Illinois Basin decreased in the first six months of 2007 as compared to the first six months of 2006. Coal royalty revenues attributable to our Williamson and James River acquisitions were $0.9 million and production was 0.4 million tons for the first half of 2007. This increase was more than offset by reduced production and coal royalty revenues on our Hocking Wolford/Cummings property as the lessee mined a greater proportion of their production adjacent property.

     Northern Powder River Basin. Coal royalty revenues and production from our Western Energy property decreased due to the normal variations that occur due to the checkerboard nature of our ownership, but was partially offset by higher prices being received by our lessee.

     Aggregates Royalty Revenues, Reserves and Production. In December 2006, we acquired aggregate reserves located in DuPont, Washington. For the six months ended June 30, 2007, we recorded $3.7 million in royalty revenues from aggregates and had production of 2.9 million tons.

     Coal Transportation and Processing Revenues. In the second half of 2006, we acquired two preparation plants and coal handling facilities under our memorandum of understanding with Taggart Global. These facilities, combined with a third coal preparation plant and rail load-out facility that we acquired in Greenbrier County, West Virginia in 2005, generated approximately $2.0 million in coal processing fees for the six months ended June 30, 2007. We do not operate the preparation plants, but receive a fee for coal processed through them. Similar to our coal royalty structure, the throughput fees are based on a percentage of the ultimate sales price for the coal that is processed through the facilities.

     In addition to our preparation plants, as part of the January 2007 Cline transaction, we acquired coal handling and transportation infrastructure associated with the Gatling mining complex in West Virginia and beltlines and rail load-out facilities associated with Williamson Energy’s Pond Creek No. 1 mine in Illinois. In contrast to our typical royalty structure, we are operating the coal handling and transportation infrastructure and have subcontracted out that responsibility to third parties. We anticipate that these assets will contribute significant revenues to us in future years. We generated approximately $1.3 million in transportation fees from these assets in the first half of 2007.

     Other revenues. Included in other revenues for the six months ended June 30, 2006 is the sale of timber and related surface acreage located on our property in Wise and Dickenson Counties, Virginia. We received proceeds from the sale of $4.8 million, resulting in a gain of $2.6 million.

     Operating costs and expenses. Included in total expenses are:

	•		Depletion and amortization of $24.3 million, or $9.2 million over first half last year due to acquisitions made during the fourth quarter of 2006 and first half of 2007.
	•		General and administrative expenses of $12.2 million for the first half of 2007, compared to $7.5 million for the first half of 2006, an increase of $4.7 million, or 63% due predominately to accruals on long-term incentive plans and additional staff added to manage our acquisitions made in the first quarter of 2007.
	•		Property, franchise and other taxes of $6.6 million for the first half of 2007, compared to $4.3 million for the first half of 2006, an increase of $2.3 million, or 53%, due to taxes on additional properties we have acquired.

     Interest Expense. The increase in interest expense is attributed to borrowings on our credit facility and the issuance of senior notes used to fund acquisitions in 2006 and the first half of 2007.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

     We satisfy our working capital requirements with cash generated from operations. We fund our property acquisitions through borrowings under our revolving credit facility, the issuance of our senior notes and the issuance of additional common units and cash. 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 debt service obligations, fund planned capital expenditures, make acquisitions and 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 the amount of cash we generate from our operations, please read “Item 1A — Risk Factors” in this Form 10-Q and our Form 10-K for the year ended December 31, 2006. Our capital expenditures, other than for acquisitions, have historically been minimal.

     Net cash provided by operations for the six months ended June 30, 2007 and 2006 was $76.6 million and $69.2 million, respectively. A significant portion of our cash provided by operations is generated from coal royalty revenues. In addition, we have received approximately $7.9 million in advance royalty payments that have not been recouped.

     Net cash used in investing activities for the six months ended June 30, 2007 was $38.9 million compared to $46.7 million for the same period in 2006. Results for the six months ending June 30, 2007 include $12.7 for the acquisition of the Westmoreland overriding interest, $10.2 million for the cash portion of the Mettiki acquisition, $8.4 million toward the construction of the Mid-Vol coal preparation plant and $1.3 million of cash costs related to the Cline and Dingess-Rum acquisitions. We placed $6.3 million in an interest bearing restricted cash account to terminate a tenancy in common agreement in connection with the Cline acquisition. The 2006 results include the funding of the second phase of the Williamson Development acquisition for $35 million partially offset by the proceeds from the sale of our Virginia timber assets and related surface tracts for $4.7 million.

     Net cash used in financing activities for the six months ended June 30, 2007 was $49.2 million compared to $17.6 million for the same period a year ago. In the first half of 2007 we borrowed $30.4 million on our revolving credit facility to fund acquisitions and we issued $225 million in senior notes and used the proceeds to pay down $225.0 million on the credit facility. For the first half of 2007 we made principal payments of $9.5 million. As a part of the Dingess-Rum and Mettiki acquisitions we received $2.6 million cash contributions from our general partner to maintain its 2% interest. In the six months ended June 30, 2006, we issued $50.0 million of senior notes to fund the second phase of the Williamson Development acquisition for $35 million and to repay $15.0 million on our credit facility. We also made $9.3 million in principal payments on our senior notes. Distributions to our partners were $70.5 million and $43.2 million for the six months ended June 30, 2007 and 2006, respectively.

Long-Term Debt

     At June 30, 2007, our debt consisted of:

	•		$18.4 million of our $300 million floating rate revolving credit facility, due March 2012;
	•		$35 million of 5.55% senior notes due 2013, with a 9-year average life;
	•		$55.8 million of 4.91% senior notes due 2018, with a 7.5-year average life;
	•		$100 million of 5.05% senior notes due 2020, with a 9-year average life;
	•		$2.7 million of 5.31% utility local improvement obligation due 2021;
	•		$46.8 million of 5.55% senior notes due 2023, with a 10-year average life; and
	•		$225 million of 5.82% senior notes due 2024, with a 10-year average life.

     Credit Facility. In March 2007, we completed an amendment and extension of our $300 million revolving credit facility. The amendment extends the term of the credit facility by two years to 2012 and lowers the borrowing costs and commitment fees. The amendment also includes an option to increase the credit facility up to a maximum of $450 million under the same terms.

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

	•		the higher of the federal funds rate plus an applicable margin ranging from 0% to 0.50% or the prime rate as announced by the agent bank; or
	•		at a rate equal to LIBOR plus an applicable margin ranging from 0.45% to 1.50%.

     We incur a commitment fee on the unused portion of the revolving credit facility at a rate ranging from 0.10% to 0.30% 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.

Two-for-One Limited Partner Unit Split

     On April 18, 2007, we completed a two-for-one split of all of our limited partner units. Accordingly, all unit and per unit amounts reported in this quarterly report reflect the split.

Conversion of Class B Units

     On January 4, 2007, we issued 541,956 Class B units to Adena Minerals in connection with the Cline acquisition. The Class B units were subsequently split, along with our common and subordinated units, on a two-for-one basis into 1,083, 912 Class B units. We issued the Class B units to Adena instead of additional common units because Section 312.03(b) of the New York Stock Exchange Listed Company Manual prohibited the issuance of any further common units to Adena without unitholder approval. Pursuant to the terms of our partnership agreement, the Class B units convert into common units on a one-for-one basis upon the earlier to occur of (i) the approval of such conversion by our unitholders or (ii) the rules of the NYSE being changed so that no vote or consent of unitholders is required as a condition to the listing or admission to trading of the common units that would be issued upon any conversion of any Class B units into common units.

     On May 22, 2007, the Securities and Exchange Commission approved an amendment to Section 312.03(b) of the NYSE Listed Company Manual which, among other things, exempted limited partnerships from the provisions of Section 312.03(b). As a result of the amendment, a vote of our unitholders is no longer required to issue common units to Adena. Consequently, all 1,083,912 Class B units held by Adena converted to 1,083,912 common units effective May 22, 2007. After the conversion, no Class B units are outstanding.

Shelf Registration Statement

     We have approximately $290.2 million available under our shelf registration statement. 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.

Off-Balance Sheet Transactions

     We do not have any off-balance sheet arrangements with unconsolidated entities or related parties and accordingly, there are no off-balance sheet risks to our liquidity and capital resources from unconsolidated entities.

Related Party Transactions

Reimbursements to Affiliates of our General Partner

     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 $1.3 million and $1.0 million for the three month periods ended June 30, 2007 and 2006, respectively and $2.5 million and $2.0 million for the six month periods ended June 30, 2007 and 2006, respectively.

Transactions with Cline Affiliates

     Williamson Energy, LLC, a company controlled by Chris Cline, leases coal reserves from us, and we provide transportation services to Williamson for a fee. Mr. Cline, through another affiliate, Adena Minerals, LLC, owns a 22% interest in our general partner, as well as 8,910,072 common units. At June 30, 2007, we had accounts receivable totaling $0.1 million from Williamson. For the three and six month periods ended June 30, 3007, we had total revenue of $0.4 million and $1.1 million from Williamson. In addition, we have received advance minimum royalties of $3.1 million that have not been recouped.

     Gatling, LLC, a company also controlled by Chris Cline, leases coal reserves from us and we provide transportation services to Gatling for a fee. At June 30, 2007, we had accounts receivable totaling $0.1 million from Gatling. For the three and six month periods ended June 30, 2007, we had total revenue of $0.9 million and $1.1 million from Gatling, LLC. In addition, we have received advance minimum royalty payments of $3.0 million that have not been recouped.

Quintana Energy Partners, L.P.

     In 2006, Corbin J. Robertson, Jr. formed Quintana Energy Partners, L.P., or QEP, a private equity fund focused on investments in the energy business. In connection with the formation of QEP, our general partner’s board of directors adopted a conflicts policy that establishes the opportunities that will be pursued by NRP and those that will be pursued by QEP. For a more detailed description of this policy, please see “Item 13. Certain Relationships and Related Transactions, and Director Independence” in our Form 10-K.

     In February 2007, QEP acquired a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. NRP currently has a memorandum of understanding with Taggart Global pursuant to which the two companies have agreed to jointly pursue the development of coal handling and preparation plants. NRP will own and lease the plants to Taggart Global, which will design, build and operate the plants. The lease payments are based on the sales price for the coal that is processed through the facilities. To date, NRP has acquired three facilities under this agreement with Taggart, and for the three and six month periods ended June 30, 2007, we received total revenue of 0.7 million and $1.2 million, respectively, from Taggart. At June 30, 2007, we had accounts receivable totaling $0.2 million from Taggart.

     In July 2007, QEP acquired a controlling interest in Kopper-Glo Fuel, Inc., a coal operating company that is one of our lessees. For the three and six month periods ended June 30, 2007, we had total revenue of $0.4 million and $1.0 million from Kopper-Glo, and at June 30, 2007, we had accounts receivable totaling $0.1 million.

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 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 as of June 30, 2007. We are not associated with any environmental contamination that may require remediation costs. However, our lessees regularly conduct reclamation work on the properties under lease to them. Because we are not the permittee of the operations on our property, we are not responsible for the costs associated with these operations. In addition, West Virginia has established a fund to satisfy any shortfall in our lessees’ reclamation obligations.

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 at historically high levels. 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 economical 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 June 30, 2007, we had $18.4 million outstanding in variable interest rate debt.

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.

Part II. Other Information

Item 1. Legal Proceedings

     None.

Item 1A. Risk Factors

     During the period covered by this report, there were no material changes from the risk factors previously disclosed in Natural Resource Partners L.P.’s Form 10-K for the year ended December 31, 2006.

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

Mettiki Transaction

     As previously reported in our Current Report on Form 8-K filed on April 3, 2007, we acquired from Western Pocahontas Properties approximately 35 million tons of coal reserves in Grant and Tucker Counties in Northern West Virginia. As consideration for the coal reserves, we issued 500,000 common units and paid approximately $10.2 million in cash. We borrowed substantially all the cash portion of the purchase price under our credit facility. The common units were offered and issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended.

Item 3. Defaults Upon Senior Securities

     None.

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

     None.

Item 5. Other Information

     None.

Item 6. Exhibits

31.1*		—		Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.
31.2*		—		Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.
32.1**		—		Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.
32.2**		—		Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.

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.

EXHIBIT INDEX

31.1*		—		Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.
31.2*		—		Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.
32.1**		—		Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.
32.2**		—		Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.