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, 2008

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		(I.R.S. Employer
incorporation or organization)		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, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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 11, 2008 there were 64,891,136 Common Units outstanding.

 

 

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007			4
Consolidated Statements of Income For the Three and Six Months Ended June 30, 2008 and 2007			5
Consolidated Statements of Cash Flows For the Six Months Ended June 30, 2008 and 2007			6
Notes to Consolidated Financial Statements			7
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview			13
Results of Operations			16
Liquidity and Capital Resources			20
Related Party Transactions			22
Environmental			22
ITEM 3. Quantitative And Qualitative Disclosures About Market Risk			23
ITEM 4. Controls And Procedures			23
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings			24
ITEM 1A. Risk Factors			24
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds			24
ITEM 3. Defaults Upon Senior Securities			24
ITEM 4. Submission Of Matters to a Vote of Security Holders			24
ITEM 5. Other Information			24
ITEM 6. Exhibits			25
Signatures			26
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 1350
Certification of CFO Pursuant to Section 1350

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 that are also forward-looking statements.

     Such forward-looking statements include, among other things, statements regarding capital expenditures, acquisitions and dispositions, expected commencement dates of mining, projected quantities of future production by our lessees and projected demand for or supply of coal and aggregates 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 our Form 10-K for the year ended December 31, 2007 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,
		2008				2007
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	60,454			$	58,341
Restricted cash			6,240				6,240
Accounts receivable, net of allowance for doubtful accounts			32,851				27,643
Accounts receivable — affiliate			4,768				1,005
Other			491				1,009
Total current assets			104,804				94,238
Land			24,343				24,343
Plant and equipment, net			66,680				61,441
Coal and other mineral rights, net			1,001,995				1,030,088
Intangible assets, net			104,691				106,222
Loan financing costs, net			2,889				3,098
Other assets, net			535				601
Total assets		$	1,305,937			$	1,320,031
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities		$	2,995			$	2,567
Accounts payable — affiliate			105				104
Current portion of long-term debt			17,234				17,234
Accrued incentive plan expenses — current portion			5,235				3,993
Property, franchise and other taxes payable			5,425				6,415
Accrued interest			6,011				6,276
Total current liabilities			37,005				36,589
Deferred revenue			39,012				36,286
Asset retirement obligations			39				39
Accrued incentive plan expenses			6,305				6,469
Long-term debt			486,514				496,057
Partners’ capital:
Common units			723,935				731,113
General partner’s interest			13,658				14,177
Holders of incentive distribution rights			142				—
Accumulated other comprehensive loss			(673	)			(699	)
Total partners’ capital			737,062				744,591
Total liabilities and partners’ capital		$	1,305,937			$	1,320,031

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,
		2008				2007				2008				2007
		(Unaudited)
Revenues:
Coal royalties		$	60,026			$	40,733			$	109,178			$	81,706
Aggregate royalties			1,933				1,944				5,295				3,689
Coal processing fees			1,757				1,112				3,654				2,030
Transportation fees			3,361				845				5,010				1,306
Oil and gas royalties			1,933				1,278				3,378				2,536
Property taxes			3,105				2,645				5,497				4,873
Minimums recognized as revenue			149				331				456				785
Override royalties			2,006				1,023				4,505				2,041
Other			1,322				1,186				2,674				2,338
Total revenues			75,592				51,097				139,647				101,304
Operating costs and expenses:
Depreciation, depletion and amortization			16,748				12,527				31,807				24,279
General and administrative			6,890				5,559				11,039				12,193
Property, franchise and other taxes			4,098				3,524				7,747				6,625
Transportation costs			408				27				529				70
Coal royalty and override payments			343				382				652				668
Total operating costs and expenses			28,487				22,019				51,774				43,835
Income from operations			47,105				29,078				87,873				57,469
Other income (expense)
Interest expense			(7,064	)			(7,133	)			(14,424	)			(14,460	)
Interest income			312				686				756				1,503
Net income		$	40,353			$	22,631			$	74,205			$	44,512
Net income attributable to:
General partner		$	6,647			$	3,074			$	11,862			$	5,893
Other holders of incentive distribution rights		$	3,144			$	1,412			$	5,928			$	2,695
Limited partners		$	30,562			$	18,145			$	56,415			$	35,924
Basic and diluted net income per limited partner unit		$	0.47			$	0.28			$	0.87			$	0.56
Weighted average number of units outstanding			64,891				64,886				64,891				64,094

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,
		2008				2007
		(Unaudited)
Cash flows from operating activities:
Net income		$	74,205			$	44,512
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			31,807				24,279
Non-cash interest charge			235				209
Loss from disposition of assets			32				—
Change in operating assets and liabilities:
Accounts receivable			(8,971	)			(2,799	)
Other assets			584				557
Accounts payable and accrued liabilities			429				(294	)
Accrued interest			(265	)			2,597
Deferred revenue			2,726				7,917
Accrued incentive plan expenses			1,078				(633	)
Property, franchise and other taxes payable			(990	)			259
Net cash provided by operating activities			100,870				76,604
Cash flows from investing activities:
Acquisition of land, coal and other mineral rights			—				(24,233	)
Acquisition or construction of plant and equipment			(7,454	)			(8,400	)
Cash placed in restricted accounts			—				(6,240	)
Net cash used in investing activities			(7,454	)			(38,873	)
Cash flows from financing activities:
Proceeds from loans			—				255,400
Deferred financing costs			—				(1,286	)
Repayment of loans			(9,543	)			(235,542	)
Distributions to partners			(81,760	)			(70,464	)
Contribution by general partner			—				2,645
Net cash used in financing activities			(91,303	)			(49,247	)
Net increase (decrease) in cash and cash equivalents			2,113				(11,516	)
Cash and cash equivalents at beginning of period			58,341				66,044
Cash and cash equivalents at end of period		$	60,454			$	54,528
Supplemental cash flow information:
Cash paid during the period for interest		$	14,450			$	11,627
Non-cash investing activities:
Equity 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, 2008 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 2007 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. Recent Accounting Pronouncements

     In September 2006, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 157, “Fair Value Measurements”. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This standard eliminates inconsistencies found in various prior pronouncements but does not require any new fair value measurements. SFAS No. 157 was effective for the Partnership on January 1, 2008, but in February 2008, the FASB issued Staff Position 157-2, permitting entities to delay application of SFAS 157 to fiscal years beginning after November 15, 2008, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Beginning January 1, 2009, we will apply SFAS 157 fair value requirements to nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a recurring basis. Adoption of the standard for financial assets and liabilities on January 1, 2008 did not impact the Partnership’s accounting measurements but it is ultimately expected to result in additional disclosures for both financial and nonfinancial assets and liabilities.

     In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS 141(R)”), which replaces SFAS 141. SFAS 141(R) establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any controlling interest; recognizes and measures goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions by the Partnership taking place on or after January 1, 2009. Early adoption is prohibited. Accordingly, a calendar year-end partnership is required to record and disclose business combinations following existing accounting guidance until January 1, 2009. Acquisitions accounted for as business combinations that are completed by the Partnership in 2009 and thereafter will be impacted by this new standard.

     In December 2007, the FASB issued SFAS No. 160. “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 is effective for the Partnership on January 1, 2009. Earlier adoption is prohibited. The Partnership currently does not think the adoption of this standard will materially impact its

financial statements although future opportunities for acquisitions may include investments that will be accounted for under this standard.

     On March 26, 2008, the FASB ratified Issue No. 07-04, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” to provide specific guidance to how income is allocated to incentive distribution rights. The Task Force reached a consensus that for application of the two-class method, a master limited partnership should reflect its contractual obligation to make distributions as of the end of the current reporting period. This Issue is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application is not permitted. The Partnership is currently completing an evaluation of the impact of Issue 07-04 on how the Partnership allocates income and reports earnings per unit.

     Other accounting standards that have been issued or proposed by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

3. Plant and Equipment

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

		June 30,				December 31,
		2008				2007
		(In thousands)
		(Unaudited)
Construction in process		$	17,881			$	11,238
Plant and equipment at cost			55,535				54,758
Accumulated depreciation			(6,736	)			(4,555	)
Net book value		$	66,680			$	61,441

		Six months ended
		June 30,
		2008				2007
		(In thousands)
		(Unaudited)
Total depreciation expense on plant and equipment		$	2,184			$	1,807

4. Coal and Other Mineral Rights

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

		June 30,				December 31,
		2008				2007
		(In thousands)
		(Unaudited)
Coal and other mineral rights		$	1,247,814			$	1,247,814
Less accumulated depletion and amortization			(245,819	)			(217,726	)
Net book value		$	1,001,995			$	1,030,088

		Six months ended
		June 30,
		2008				2007
		(In thousands)
		(Unaudited)
Total depletion and amortization expense on coal and other mineral interests		$	28,093			$	21,708

5. Intangible Assets

     Amounts recorded as intangible assets along with the balances and accumulated amortization are reflected in the table below:

		June 30, 2008								December 31, 2007
		Gross Carrying				Accumulated				Gross Carrying				Accumulated
		Amount				Amortization				Amount				Amortization
		(In thousands)								(In thousands)
		(Unaudited)
Finite-lived intangible assets
Above market transportation contracts		$	82,276			$	2,238			$	82,276			$	1,045
Above market coal leases			25,281				628				25,281				290
		$	107,557			$	2,866			$	107,557			$	1,335

     Amortization expense related to these contract intangibles was $1.0 million and $0.3 million for the three months ended June 30, 2008 and 2007 and $1.5 million and $0.4 million for the six months ended June 30, 2008 and 2007, respectively, 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, 2008		$	2,729
For year ended December 31, 2009			4,810
For year ended December 31, 2010			5,862
For year ended December 31, 2011			5,862
For year ended December 31, 2012			5,862
For year ended December 31, 2013			5,862

6. Long-Term Debt

     Long-term debt consists of the following:

		June 30,				December 31,
		2008				2007
		(In thousands)
		(Unaudited)
$300 million floating rate revolving credit facility, due March 2012		$	48,000			$	48,000
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			49,750				55,800
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			2,498				2,691
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023			43,500				46,800
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				225,000
Total debt			503,748				513,291
Less — current portion of long term debt			(17,234	)			(17,234	)
Long-term debt		$	486,514			$	496,057

     The Partnership has a $300 million revolving credit facility that may be increased, at the Partnership’s option, up to a maximum of $450 million on the same terms. At June 30, 2008 and December 31, 2007, the Partnership had $48.0 million outstanding on its revolving credit facility. The weighted average interest rate at June 30, 2008 and December 31, 2007 was 3.64% and 6.06%,

respectively. 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, 2008.

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 units outstanding during the period. Net income is allocated in the same ratio as quarterly cash distributions are made. Further, under the terms of the partnership agreement, in periods in which distributions to the holders of incentive distribution rights are greater than their allocated income, additional net income must be allocated to the extent of any negative capital account balance. This allocation also reduces net income allocated to limited partners for purposes of computing earnings per unit. 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

Reimbursements to Affiliates of its 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 the partnership agreement, its general partner and its affiliates are reimbursed for expenses incurred on the Partnership’s behalf. All direct general and administrative expenses are charged to the Partnership 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 its general partner and its affiliates. Reimbursements to affiliates of the Partnership’s general partner reduce the 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 $1.4 million and $1.3 million and $2.7 million and $2.5 million for each of the three and six month periods ended June 30, 2008 and 2007, respectively.

Transactions with Cline Affiliates

     Williamson Energy, LLC, a company controlled by Chris Cline, leases coal reserves from the Partnership, and the Partnership provides coal transportation services to Williamson for a fee. Mr. Cline, through another affiliate, Adena Minerals, LLC, owns a 22% interest in the Partnership’s general partner and in the incentive distribution rights of the Partnership, as well as 8,910,072 common units. At June 30, 2008, the Partnership had accounts receivable totaling $4.2 million from Williamson. For the three and six month periods ended June 30, 2008 and 2007, the Partnership had total revenue of $7.5 million and $0.4 million and $9.3 million and $1.1 million, respectively, from Williamson. In addition, the Partnership has also received $5.3 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 coal transportation services to Gatling for a fee. At June 30, 2008, the Partnership had accounts receivable totaling $0.2 million from Gatling. For the three and six month periods ended June 30, 2008 and 2007, the Partnership had total revenue of $0.9 million and $0.9 million and $2.1 million and $1.1 million, respectively, from Gatling, LLC. In addition, the Partnership has also received $6.1 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’s 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.

     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 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, 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 four facilities under this agreement with Taggart with a total cost of $42.9 million. For the three and six month periods ended June 30, 2008 and 2007, the

Partnership received total revenue of $1.0 million and $0.7 million and $2.0 million and $1.2 million, respectively, from Taggart. At June 30, 2008, the Partnership had accounts receivable totaling $0.3 million from Taggart.

     In June 2007, QEP acquired a controlling interest in Kopper-Glo Fuel, Inc., a coal operating company that is one of the Partnership’s lessees. For the three and six month periods ended June 30, 2008 and 2007, the Partnership had total revenue of $0.3 million and $0.4 million and $0.5 million and $1.0 million, respectively, from Kopper-Glo, and at June 30, 2008, the Partnership had accounts receivable totaling $0.1 million from Kopper-Glo.

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 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, 2008. The Partnership is not associated with any environmental contamination that may require remediation costs.

10. Major Lessee

     Revenues from one lessee exceeded ten percent of total revenues for the periods indicated below:

		Three Months Ended																Six Months Ended
		June 30,																June 30,
		2008								2007								2008								2007
		Revenues				Percent				Revenues				Percent				Revenues				Percent				Revenues				Percent
Lessee A			9,158				12.1	%			4,931				9.7	%			16,356				11.7	%			10,670				10.5	%

11. 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, Nominating and Governance (“CNG”) 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 CNG 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 CNG Committee provides otherwise.

     A summary of activity in the outstanding grants for the first six months of 2008 are as follows:

Outstanding grants at the beginning of the period			507,466
Grants during the period			171,328
Grants vested and paid during the period			(105,230	)
Forfeitures during the period			—
Outstanding grants at the end of the period			573,564

     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 2.19% to 3.06% and 28.38% to 37.94%, respectively at June 30, 2008. The Partnership’s historic distribution rate of 5.65% was used in the calculation at June 30, 2008. The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $3.9 million and $2.4 million and $4.0 million and $4.2 million for the three and six months ended June 30, 2008 and 2007, respectively. In connection with the Long-Term Incentive Plan, payments are typically made during the first quarter of the year. Payments of $3.2 million and $5.8 million were paid during the six month periods ended June 30, 2008 and 2007, respectively.

     In connection with the phantom unit awards granted in February 2008, the CNG Committee also granted tandem Distribution Equivalent Rights, or DERs, which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units. The DERs are only applicable to the February 2008 awards that vest in 2012 and, at the discretion of the CNG Committee, may be included with awards granted in the future. The DERs are payable in cash upon vesting.

     The unaccrued cost associated with the outstanding grants and related DERs at June 30, 2008 was $6.8 million.

12. Distributions

     On May 14, 2008, the Partnership paid a cash distribution equal to $0.495 per unit to unitholders of record on May 1, 2008.

13. Subsequent Events

     On July 16, 2008, the Partnership declared a second quarter 2008 distribution of $0.515 per unit. The distribution will be paid on August 14, 2008 to unitholders of record on August 1, 2008.

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, 2007, we owned or controlled approximately 2.1 billion tons of proven and probable coal reserves in eleven states, and 59% 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 22% of our first half revenues from other sources, compared to 19% for the same period in 2007. 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; timber; overriding royalties; and wheelage payments.

     Current Results

     As of June 30, 2008, our reserves were subject to 191 leases with 66 lessees. For the six months ended June 30, 2008, our lessees produced 30.6 million tons of coal generating $109.2 million in coal royalty revenues from our properties, and our total revenues were $139.6 million.

     Global and domestic coal price trends accelerated during the second quarter of 2008, resulting in a substantial increase in our royalty per ton, especially in Appalachia. Even though a significant portion of our total revenue remains dependent upon Appalachian coal production and prices, which reached record levels in the second quarter, coal royalty revenues from our Appalachian properties represented 68% of our total revenues in both the first and second quarters of 2008. This percentage remained constant primarily because we saw significant improvement in both pricing and production from our Illinois Basin coal royalty properties and transportation assets. Although we don’t anticipate coal prices to continue to increase at the same pace, we expect our coal royalty revenue per ton to continue to increase over the next several quarters as more of our lessees’ sales contracts roll over into the favorable pricing environment.

     In addition, we benefitted from our significant exposure to metallurgical coal. Approximately 36% of our coal royalty revenues and 26% of the related production during 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 U.S. coal market, especially for Appalachian coal and to a more limited extent the Illinois Basin coal, is being dramatically impacted by events in China, Australia and South Africa that are impacting world coal supply. Combined with the legal and regulatory challenges to increasing production in the United States, we believe that coal prices will remain high for at least the next 12 months.

     Although coal prices have improved significantly, the political, legal and regulatory environment is becoming increasingly difficult for the coal industry. The 2007 judicial decisions by the Southern District of West Virginia regarding permits issued under Section 404 of the Clean Water Act in West Virginia, together with a similar lawsuit filed in Kentucky, have created substantial regulatory uncertainty. If these cases have adverse outcomes, it could have long-term negative implications for the future of all coal mining in Appalachia which would impact 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,
		2008				2007				2008				2007
		(Unaudited)
Net cash provided by operating activities		$	61,667			$	45,861			$	100,870			$	76,604
Less scheduled principal payments			(9,350	)			(9,350	)			(9,543	)			(9,350	)
Less reserves for future principal payments			(4,308	)			(2,400	)			(8,616	)			(4,800	)
Add reserves used for scheduled principal payments			9,350				9,400				9,543				9,400
Distributable cash flow		$	57,359			$	43,511			$	92,254			$	71,854

Acquisitions

     Although we are a growth-oriented company and have closed a number of acquisitions over the last several years, the pace of our acquisitions has slowed in 2008 due to the high expectations of potential sellers in today’s pricing environment and our unwillingness to pay extraordinary prices for reserves in today’s market. We continue to look at a number of opportunities, have significant liquidity and are prepared to move quickly when the market stabilizes. Our most recent acquisitions are briefly described below.

     Licking River Preparation Plant. On March 14, 2008, we signed an agreement for the construction of a coal preparation plant facility under our memorandum of understanding with Taggart Global USA, LLC. The cost for the facility, located in Eastern Kentucky, is estimated to be approximately $8.7 million, of which $4.6 million had been paid as of June 30, 2008 for construction costs incurred to date.

     Massey Energy. On December 31, 2007, we acquired an overriding royalty interest from Massey Energy for $6.6 million. The override relates to low-vol metallurgical coal reserves that are being produced from the Pinnacle Mine in West Virginia.

     National Resources. On December 17, 2007, we acquired approximately 17.5 million tons of high quality low-vol metallurgical coal reserves in Wyoming and McDowell Counties in West Virginia from National Resources, Inc., a subsidiary of Bluestone Coal. Total consideration for this purchase was $27.2 million.

     Cheyenne Resources. On August 16, 2007, we acquired a rail load-out facility and rail spur from Cheyenne Resources for $5.5 million. This facility is located in Perry County, Kentucky.

     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, West Virginia, is estimated to be approximately $16.2 million, of which $13.2 million had been paid as of June 30, 2008 for construction costs incurred to date.

     Mettiki. On April 2, 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 8,910,072 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 early 2009.

Results of Operations

		Three Months Ended								Increase				Percentage
		June 30,								(Decrease)				Change
		2008				2007
		(In thousands, except percent and per ton data)
		(Unaudited)
Coal:
Coal royalty revenues
Appalachia
Northern		$	4,902			$	4,353			$	549				13	%
Central			42,974				28,339				14,635				52	%
Southern			3,802				4,989				(1,187	)			(24	%)
Total Appalachia			51,678				37,681				13,997				37	%
Illinois Basin			5,923				1,365				4,558				334	%
Northern Powder River Basin			2,425				1,687				738				44	%
Total		$	60,026			$	40,733				19,293				47	%
Production (tons)
Appalachia
Northern			1,927				1,901				26				1	%
Central			9,629				8,855				774				9	%
Southern			930				1,297				(367	)			(28	%)
Total Appalachia			12,486				12,053				433				4	%
Illinois Basin			2,293				659				1,634				248	%
Northern Powder River Basin			1,314				861				453				53	%
Total			16,093				13,573				2,520				19	%
Average gross royalty per ton
Appalachia
Northern		$	2.54			$	2.29			$	0.25				11	%
Central			4.46				3.20				1.26				39	%
Southern			4.09				3.85				0.24				6	%
Total Appalachia			4.14				3.13				1.01				32	%
Illinois Basin			2.58				2.07				0.51				25	%
Northern Powder River Basin			1.85				1.96				(0.11	)			(6	%)
Combined average gross royalty per ton			3.73				3.00				0.73				24	%
Aggregates:
Royalty revenue		$	1,633			$	1,780			$	(147	)			8	%)
Aggregate royalty bonus		$	300			$	164			$	136				83	%
Production			1,238				1,531				(293	)			(19	%)
Average base royalty per ton		$	1.32			$	1.16			$	0.16				12	%

     Coal Royalty Revenues and Production. Coal royalty revenues comprised approximately 79% and 80% of our total revenue for the three month periods ended June 30, 2008 and 2007. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:

     Appalachia. Primarily due to higher prices being realized by our lessees, coal royalty revenues increased in the three month period ended June 30, 2008 compared to the same period of 2007, while production was only slightly higher. The Appalachian results by region are set forth below.

     Northern Appalachia. Coal royalty revenues increased primarily due to higher prices across all areas.

     Central Appalachia. Coal royalty revenues attributable to acquisitions completed since the end of the first half of 2007 were $1.6 million and production related to those acquisitions was 149,000 tons. Coal production on our other properties increased slightly but nearly all our lessees received higher prices resulting in higher per ton coal royalty revenue.

     Southern Appalachia. Our coal royalty revenues and production in Southern Appalachia decreased for the quarter ended June 30, 2008 compared to the same period in 2007 due to decreased shipments from our Oak Grove property and the lessee on our Twin Pines/Drummond property moving to adjacent property. These decreases were slightly offset due to the higher prices received by nearly all our lessees.

     Illinois Basin. Coal royalty revenues and production increased primarily due to the improved production on our Williamson property and a lessee moving back onto our property on the Cummings/Hocking Wolford property.

     Northern Powder River Basin. Coal royalty revenues and production increased on our Western Energy property primarily due to the normal variations that occur due to the checkerboard nature of ownership. The higher per ton rate in the second quarter of 2007 was due to a cumulative price adjustment, which is received from time to time by our lessee.

     Aggregates Royalty Revenues, Reserves and Production. Aggregate production decreased slightly, but due to improved prices being received by the lessee, royalty revenue increased slightly.

Results of Operations

		Six Months Ended								Increase				Percentage
		June 30,								(Decrease)				Change
		2008				2007
		(In thousands, except percent and per ton data)
		(Unaudited)
Coal:
Coal royalty revenues
Appalachia
Northern		$	8,405			$	7,123			$	1,282				18	%
Central			77,271				58,586				18,685				32	%
Southern			9,300				9,028				272				3	%
Total Appalachia			94,976				74,737				20,239				27	%
Illinois Basin			8,556				2,479				6,077				245	%
Northern Powder River Basin			5,646				4,490				1,156				26	%
Total		$	109,178			$	81,706			$	27,472				34	%
Production (tons)
Appalachia
Northern			3,264				3,235				29				1	%
Central			18,571				18,095				476				3	%
Southern			2,224				2,330				(106	)			(5	%)
Total Appalachia			24,059				23,660				399				2	%
Illinois Basin			3,458				1,161				2,297				198	%
Northern Powder River Basin			3,045				2,261				784				35	%
Total			30,562				27,082				3,480				13	%
Average gross royalty per ton
Appalachia
Northern		$	2.58			$	2.20			$	0.38				17	%
Central			4.16				3.24				0.92				28	%
Southern			4.18				3.87				0.31				8	%
Total Appalachia			3.95				3.16				0.79				25	%
Illinois Basin			2.47				2.14				0.33				15	%
Northern Powder River Basin			1.85				1.99				(0.14	)			(7	%)
Combined average gross royalty per ton			3.57				3.02				0.55				18	%
Aggregates:
Royalty revenue		$	3,051			$	3,361			$	(310	)			(9	%)
Aggregate royalty bonus		$	2,244			$	328			$	1,916				584	%
Production			2,392				2,872				(480	)			(17	%)
Average base royalty per ton		$	1.28			$	1.17			$	0.11				9	%

     Coal Royalty Revenues and Production. Coal royalty revenues comprised approximately 78% and 81% of our total revenue for the six month periods ended June 30, 2008 and 2007. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:

     Appalachia. Primarily due to higher prices being realized by our lessees and in part because of acquisitions completed since the first quarter of 2007, coal royalty revenues increased in the six month period ended June 30, 2008 compared to the same period of 2007, while production increased only slightly. The Appalachian results by region are set forth below.

     Northern Appalachia. Coal royalty revenues increased primarily due to the lessee from the Mettiki acquisition made in the second quarter of 2007 operating on our property for the entire six month period in 2008 versus three months in 2007. This increase was partially offset by lower production on our AFC properties, where a greater proportion of the production for the six month period ended June 30, 2008 was on adjacent property.

     Central Appalachia. Coal royalty revenues attributable to acquisitions completed since the end of the first half of 2007 were $2.7 million and production related to those acquisitions was 290,000 tons. Coal production on our other properties increased slightly, but the higher prices received by our lessees resulted in substantially higher coal royalty revenue per ton.

     Southern Appalachia. Our coal royalty revenues in Southern Appalachia increased for the six months ended June 30, 2008 compared to the same period in 2007, but production decreased slightly. The production decreases occurred on our Oak Grove property, which had lower shipments, and our Twin Pines/Drummond property, where the lessee moved to adjacent property. The production decreases were more than offset by the higher prices received by our lessees.

     Illinois Basin. Coal royalty revenues and production increased primarily due to the improved production on our Williamson property and a lessee moving back onto our Cummings/Hocking Wolford property.

     Northern Powder River Basin. Coal royalty revenues and production increased on our Western Energy property primarily due to the normal variations that occur due to the checkerboard nature of ownership. The per ton revenue is lower for the six months ended June 30, 2008 compared to the same period in 2007. The higher per ton rate in the first six months of 2007 was due to a cumulative price adjustment, which is received from time to time by our lessee.

     Aggregates Royalty Revenues, Reserves and Production. Aggregate production and royalties were down slightly for the six months ended June 30, 2008 compared to the same period of 2007. In the first half of 2008, we received a bonus royalty payment that was $1.6 million higher than expected from our lessee based on their 2007 net profits. The lower production was partially offset by higher prices being received by our lessee.

Other Operating Results

     Coal Processing and Transportation Revenues. We generated $1.8 million and $3.7 million in processing revenues for the quarter and six months ended June 30, 2008 compared with $1.1 million and $2.0 million for the same periods in 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. Coal processed through the facility decreased 22% and 1% for the three and six month periods of 2008, compared to the same periods of 2007, while revenue increased due to the increase in sales prices.

     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 receive a fixed rate per ton for coal transported over these facilities. We operate coal handling and transportation infrastructure and have subcontracted out that responsibility to third parties. We generated transportation fees from these assets of approximately $3.4 million and $5.0 million for the quarter and six months ended June 30, 2008, compared to $0.8 million and $1.3 million for the same periods of 2007. Production increased 497% for the second quarter and 380% for the first half of 2008 compared to the same periods in 2007, as we reported a full six months of transportation revenue in 2008 and production ramped up on our Williamson property.

     Oil and Gas Royalties. We generated $1.9 million and $1.3 million for the quarter ended June 30, 2008 and 2007, respectively and for the six months ended June 30, 2008, we generated $3.4 million compared to $2.5 million for the same period in 2007. These increases in revenue are primarily due to higher prices.

     Override revenues. Override revenues were $2.0 million and $1.0 million for the quarters ending June 30, 2008 and 2007, respectively and $4.5 million and $2.0 million for the six months ended June 30, 2008 and 2007, respectively. These increases were due primarily to override royalty acquisitions during 2007 and additional production on an existing override.

     Other revenues. Other revenues, primarily comprised of rent and wheelage, generated $1.3 million for the quarter and $2.7 million for the six months ended June 30, 2008, compared to $1.2 million for the quarter and $2.3 million for the six months ended June 30, 2007.

     Operating costs and expenses. Included in total expenses are:

•

Depreciation, depletion and amortization of $16.7 million and $12.5 million for the quarters ended June 30, 2008 and 2007 and $31.8 million and $24.3 million for the six months ended June 30, 2008 and 2007, respectively. Depletion increased as a result

of higher total production for 2008 and a greater portion of the production on the new properties that we acquired in 2007 and at the end of 2006, which are being depleted at much higher rates than our older properties.

	•		General and administrative expenses of $6.9 million and $11.0 million for the quarter and six month periods ended June 30, 2008 compared to $5.6 million and $12.2 million for the same periods during 2007. The change in general and administrative expense is primarily due to accruals under our long-term incentive plan attributable to fluctuations in our unit price.
	•		Property, franchise and other taxes have increased approximately $0.6 million for the quarter and $1.1 million year to date. The significant increase in 2008 was primarily due to increases in West Virginia taxes on additional properties we have acquired. A substantial portion of our property taxes is reimbursed to us by our lessees and is reflected as property tax revenue on our statement of income.

     Interest Expense. Interest expense was virtually flat quarter to quarter and year to year. We replaced $225 million of our credit facility with senior notes at the end of March 2007 at a more favorable interest rate than those on our credit facility at that time which helped offset the increase in total debt outstanding.

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 with available cash, borrowings under our revolving credit facility, and the issuance of our senior notes and additional 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, 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 cash flow we generate from our operations, please read “Item 1A. Risk Factors.” in our Form 10-K for the year ended December 31, 2007. Our capital expenditures, other than for acquisitions, have historically been minimal.

     Net cash provided by operations for the six months ended June 30, 2008 and 2007 was $100.9 million and $76.6 million, respectively. Substantially all of our cash provided by operations since inception has been generated from coal royalty revenues.

     Net cash used in investing activities for the six months ended June 30, 2008 and 2007 was $7.5 million and $38.9 million, respectively. For the six months ended June 30, 2008 and 2007, substantially all of our investing activities consisted of acquiring coal reserves, plant and equipment and other mineral rights.

     Net cash used for financing activities for the six months ended June 30, 2008 and 2007 was $91.3 million and $49.2 million, respectively. In 2007, all of the loan proceeds from our credit facility were used to fund our acquisitions. We issued $225 million in senior notes in 2007 and used those proceeds to pay down our credit facility. Cash distributions to our partners were $81.8 million and $70.5 million for the six months ended June 30, 2008 and 2007, respectively. In the first half of 2007, as a part of the Dingess-Rum and Mettiki acquisitions we received $2.6 million in cash contributions from our general partner to maintain its 2% interest.

Long-Term Debt

     At June 30, 2008, our debt consisted of:

	•		$48.0 million of our $300 million floating rate revolving credit facility, due March 2012;
	•		$35 million of 5.55% senior notes due 2013;
	•		$49.8 million of 4.91% senior notes due 2018;
	•		$100 million of 5.05% senior notes due 2020;
	•		$2.5 million of 5.31% utility local improvement obligation due 2021;
	•		$43.5 million of 5.55% senior notes due 2023; and
	•		$225 million of 5.82% senior notes due 2024.

     Other than the 5.55% senior notes due 2013, which have semi-annual interest payments, all of our senior notes require annual principal payments in addition to semi-annual interest payments. The scheduled principal payments on the 5.05% senior notes due 2020 did not begin until July 2008, and the principal payments on the 5.82% senior notes due 2024 do not begin until March 2010. We also make annual principal and interest payments on the utility local improvement obligation.

     Credit Facility. We have a $300 million revolving credit facility that may be increased, at our option, up to a maximum of $450 million on 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.

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 $1.4 million and $1.3 million and $2.7 million and $2.5 million for each of the three and six month periods ended June 30, 2008 and 2007, respectively.

Transactions with Cline Affiliates

     Williamson Energy, LLC, a company controlled by Chris Cline, leases coal reserves from us, and we provide coal transportation services to Williamson for a fee. Mr. Cline, through another affiliate, Adena Minerals, LLC, owns a 22% interest in our general partner and the incentive distribution rights of NRP, as well as 8,910,072 common units. At June 30, 2008, we had accounts receivable totaling $4.2 million from Williamson. For the three and six month periods ended June 30, 2008 and 2007, we had total revenue of $7.5 million and $0.4 million and $9.3 million and $1.1 million, respectively, from Williamson. In addition, we have received advance minimum royalties of $5.3 million that have not been recouped.

     Gatling, LLC, a company also controlled by Chris Cline, leases coal reserves from us and we provide coal transportation services to Gatling for a fee. At June 30, 2008, we had accounts receivable totaling $0.2 million from Gatling. For the three and six month periods ended June 30, 2008 and 2007, we had total revenue of $0.9 million and $0.9 million and $2.1 million and $1.1 million, respectively, from Gatling, LLC. In addition, we have received advance minimum royalty payments of $6.1 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 four facilities under this agreement with Taggart for a total cost of $42.9 million. For the three and six months ended June 30, 2008 and 2007, we received total revenue of $1.0 million and $0.7 million and $2.0 million and $1.2 million, respectively, from Taggart. At June 30, 2008, we had accounts receivable totaling $0.3 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, 2008 and 2007, we had total revenue of $0.3 million and $0.4 million and $0.5 million and $1.0 million, respectively, from Kopper-Glo, and at June 30, 2008, 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, 2008. 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 properties, 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, 2008, we had $48.0 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 providing reasonable assurance that (a) the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and (b) such information is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding 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, 2007.

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.

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.

				NATURAL RESOURCE PARTNERS L.P. By: NRP (GP) LP, its general partner By: GP NATURAL RESOURCE         PARTNERS LLC, its general partner
Date: August 11, 2008
				By:		/s/ Corbin J. Robertson, Jr.
						Corbin J. Robertson, Jr.,
						Chairman of the Board and Chief Executive Officer
						(Principal Executive Officer)
Date: August 11, 2008
				By:		/s/ Dwight L. Dunlap
						Dwight L. Dunlap,
						Chief Financial Officer and Treasurer
						(Principal Financial Officer)
Date: August 11, 2008
				By:		/s/ Kenneth Hudson
						Kenneth Hudson
						Controller
						(Principal Accounting Officer)

Index to 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.