NATURAL RESOURCE PARTNERS LP - Quarter Report: 2008 March (Form 10-Q)

 

 

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

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

NATURAL RESOURCE PARTNERS L.P.

Delaware (State or other jurisdiction of incorporation or organization)		35-2164875 (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, a non-accelerated filer or a smaller reporting company. See definition of “accelerated filer”, “large accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

þ Large Accelerated Filer                o Non-accelerated Filer (Do not check if a smaller reporting company)		o Accelerated Filer o Smaller Reporting Company

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 May 8, 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 March 31, 2008 and December 31, 2007			4
Consolidated Statements of Income For the Three Months Ended March 31, 2008 and 2007			5
Consolidated Statements of Cash Flows For the Three Months Ended March 31, 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			18
Related Party Transactions			20
Environmental			20
ITEM 3. Quantitative And Qualitative Disclosures About Market Risk			21
ITEM 4. Controls And Procedures			21
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings			22
ITEM 1A. Risk Factors			22
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds			22
ITEM 3. Defaults Upon Senior Securities			22
ITEM 4. Submission Of Matters to a Vote of Security Holders			22
ITEM 5. Other Information			22
ITEM 6. Exhibits			23
Signatures			24
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

		March 31,				December 31,
		2008				2007
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	54,320			$	58,341
Restricted cash			6,240				6,240
Accounts receivable, net of allowance for doubtful accounts			30,785				27,643
Accounts receivable – affiliate			1,582				1,005
Other			786				1,009
Total current assets			93,713				94,238
Land			24,343				24,343
Plant and equipment, net			63,163				61,441
Coal and other mineral rights, net			1,016,655				1,030,088
Intangible assets, net			105,674				106,222
Loan financing costs, net			2,993				3,098
Other assets, net			563				601
Total assets		$	1,307,104			$	1,320,031
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities		$	2,316			$	2,567
Accounts payable – affiliate			104				104
Current portion of long-term debt			17,234				17,234
Accrued incentive plan expenses – current portion			3,542				3,993
Property, franchise and other taxes payable			3,953				6,415
Accrued interest			3,356				6,276
Total current liabilities			30,505				36,589
Deferred revenue			38,699				36,286
Asset retirement obligations			39				39
Accrued incentive plan expenses			3,772				6,469
Long-term debt			495,864				496,057
Partners’ capital:
Common units			725,494				731,113
General partners’ interest			13,417				14,177
Accumulated other comprehensive loss			(686	)			(699	)
Total partners’ capital			738,225				744,591
Total liabilities and partners’ capital		$	1,307,104			$	1,320,031

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF INCOME

		Three Months Ended
		March 31,
		2008				2007
		(Unaudited)
Revenues:
Coal royalties		$	49,152			$	40,973
Aggregate royalties			3,362				1,745
Coal processing fees			1,897				918
Transportation fees			1,649				461
Oil and gas royalties			1,445				1,258
Property taxes			2,392				2,228
Minimums recognized as revenue			307				454
Override royalties			2,499				1,018
Other			1,352				1,152
Total revenues			64,055				50,207
Operating costs and expenses:
Depreciation, depletion and amortization			15,059				11,752
General and administrative			4,149				6,634
Property, franchise and other taxes			3,649				3,101
Transportation costs			121				43
Coal royalty and override payments			309				286
Total operating costs and expenses			23,287				21,816
Income from operations			40,768				28,391
Other income (expense)
Interest expense			(7,360	)			(7,327	)
Interest income			444				817
Net income		$	33,852			$	21,881
Net income attributable to:
General partner		$	5,215			$	2,819
Other holders of incentive distribution rights		$	2,784			$	1,283
Limited partners		$	25,853			$	17,779
Basic and diluted net income per limited partner unit		$	0.40			$	0.28
Weighted average number of units outstanding			64,891				63,295

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Three Months Ended
		March 31,
		2008				2007
		(Unaudited)
Cash flows from operating activities:
Net income		$	33,852			$	21,881
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			15,059				11,752
Non-cash interest charge			118				94
Change in operating assets and liabilities:
Accounts receivable			(3,719	)			(4,072	)
Other assets			261				221
Accounts payable and accrued liabilities			(251	)			198
Accrued interest			(2,920	)			(434	)
Deferred revenue			2,413				3,901
Accrued incentive plan expenses			(3,148	)			(3,195	)
Property, franchise and other taxes payable			(2,462	)			397
Net cash provided by operating activities			39,203				30,743
Cash flows from investing activities:
Acquisition of land, coal and other mineral rights			—				(13,972	)
Acquisition or construction of plant and equipment			(2,800	)			—
Current payable assumed in a business combination			—				1,154
Cash placed in restricted accounts			—				(6,242	)
Net cash used in investing activities			(2,800	)			(19,060	)
Cash flows from financing activities:
Proceeds from loans			—				237,000
Deferred financing costs			—				(1,107	)
Repayment of loans			(193	)			(226,192	)
Distributions to partners			(40,231	)			(34,126	)
Contribution by general partner			—				2,315
Net cash used in financing activities			(40,424	)			(22,110	)
Net decrease in cash and cash equivalents			(4,021	)			(10,427	)
Cash and cash equivalents at beginning of period			58,341				66,044
Cash and cash equivalents at end of period		$	54,320			$	55,617
Supplemental cash flow information:
Cash paid during the period for interest		$	10,158			$	7,648
Non-cash investing activities:
Equity issued in business combinations		$	—			$	343,622
Liability assumed in business combination			—				1,950

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 months ended March 31, 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:

		March 31,				December 31,
		2008				2007
		(In thousands)
		(Unaudited)
Construction in process		$	14,039			$	11,238
Plant and equipment at cost			54,758				54,758
Accumulated depreciation			(5,634	)			(4,555	)
Net book value		$	63,163			$	61,441

		Three months ended
		March 31,
		2008				2007
		(In thousands)
		(Unaudited)
Total depreciation expense on plant and equipment		$	1,079			$	936

4. Coal and Other Mineral Rights

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

		March 31,				December 31,
		2008				2007
		(In thousands)
		(Unaudited)
Coal and other mineral rights		$	1,247,814			$	1,247,814
Less accumulated depletion and amortization			(231,159	)			(217,726	)
Net book value		$	1,016,655			$	1,030,088

		Three months ended
		March 31,
		2008				2007
		(In thousands)
		(Unaudited)
Total depletion and amortization expense on coal and other mineral interests		$	13,433			$	10,523

5. Intangible Assets

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

		March 31, 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			$	1,474			$	82,276			$	1,045
Above market coal leases			25,281				409				25,281				290
		$	107,577			$	1,883			$	107,557			$	1,335

     Amortization expense related to these contract intangibles was $548,000 and $134,000 for the three-month month periods ended March 31, 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		$	4,094
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:

		March 31,				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			55,800				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			46,800				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			513,098				513,291
Less – current portion of long term debt			(17,234	)			(17,234	)
Long-term debt		$	495,864			$	496,057

     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.

     At March 31, 2008 and December 31, 2007, the Partnership had $48.0 million outstanding on its revolving credit facility. The weighted average interest rate at March 31, 2008 and December 31, 2007 was 4.24% 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 March 31, 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 common and subordinated 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 reduced 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 $1.3 million for each of the three month periods ended March 31, 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 March 31, 2008, the Partnership had accounts receivable totaling $0.4 million from Williamson. For the three month periods ended March 31, 2008 and 2007, the Partnership had total revenue of $1.9 million and $0.7 million, respectively, from Williamson. In addition, the Partnership also received $5.2 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 March 31, 2008, the Partnership had accounts receivable totaling $0.5 million from Gatling. For the three month periods ended March 31, 2008 and 2007, the Partnership had total revenue of $1.2 million and $0.4 million, respectively, from Gatling, LLC. In addition, the Partnership also received $4.7 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 $38.3 million. For the three month periods ended March 31, 2008 and 2007, the Partnership received total revenue of $1.1 million and $0.5 million, respectively, from Taggart. At March 31, 2008, the Partnership had accounts receivable totaling $0.7 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 month periods ended March 31, 2008 and 2007, the Partnership had total revenue of $0.3 million and $0.6 million, respectively, from Kopper-Glo, and at March 31, 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 March 31, 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
		March 31,
		2008								2007
		Revenues				Percent				Revenues				Percent
		Dollars in thousands
		(Unaudited)
Lessee A			7,198				11	%			5,739				11	%

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 three 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 1.47% to 2.06% and 27.65% to 35.14%, respectively at March 31, 2008. The Partnership’s historic distribution rate of 5.41% was used in the calculation at March 31, 2008. The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $0.2 million and $2.4 million for the three months ended March 31, 2008 and 2007, respectively. In connection with the Long-Term Incentive Plans, cash payments of $3.2 million and $5.6 million were paid during the three month periods ended March 31, 2008 and 2007, respectively. The unaccrued cost associated with the outstanding grants at March 31, 2008 was $6.3 million.

     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 have a four year vesting period and are payable in cash.

12. Distributions

     On February 14, 2008, the Partnership paid a cash distribution equal to $0.485 per unit to unitholders of record on February 1, 2008.

13. Subsequent Events

     On April 16, 2008, the Partnership declared a first quarter 2008 distribution of $0.495 per unit. The distribution will be paid on May 14, 2008 to unitholders of record on May 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 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 23% of our first quarter revenues from other sources, compared to 18% 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 March 31, 2008, our reserves were subject to 191 leases with 66 lessees. For the quarter ended March 31, 2008, our lessees produced 14.5 million tons of coal generating $49.2 million in coal royalty revenues from our properties, and our total revenues were $64.1 million.

     Although we have recently acquired a large amount of reserves in the Illinois Basin and diversified into aggregates and coal transportation and processing infrastructure, a significant portion of our total revenue remains dependent upon Appalachian coal production and prices. Coal royalty revenues from our Appalachian properties represented 68% of our total revenues for the three months ended March 31, 2008. Approximately 37% of our coal royalty revenues and 28% of the related production during the quarter 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 robust in both the domestic and export markets. Coal prices for both steam and metallurgical coal in Appalachia began to move in a positive direction during the fourth quarter of 2007, and the price movement accelerated into 2008. 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. Many observers believe that the growing world demand for coal may lead to an increasingly favorable pricing structure for all U.S. coal.

     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
		March 31,
		2008				2007
		(Unaudited)
Net cash provided by operating activities		$	39,203			$	30,743
Less scheduled principal payments			(193	)			(193	)
Less reserves for future principal payments			(4,308	)			(2,400	)
Add reserves used for scheduled principal payments			193				193
Distributable cash flow		$	34,895			$	28,343

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.

     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 $0.9 million had been paid as of March 31, 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 $12.4 million had been paid as of March 31, 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 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 late 2008 or early 2009. 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.

Results of Operations

		Three Months Ended								Increase				Percentage
		March 31,								(Decrease)				Change
		2008				2007
		(In thousands, except percent and per ton data)
						(Unaudited)
Coal:
Coal royalty revenues
Appalachia
Northern		$	3,503			$	2,771			$	732				26	%
Central			34,297				30,246				4,051				13	%
Southern			5,498				4,039				1,459				36	%
Total Appalachia			43,298				37,056				6,242				17	%
Illinois Basin			2,633				1,114				1,519				136	%
Northern Powder River Basin			3,221				2,803				418				15	%
Total		$	49,152			$	40,973			$	8,179				20	%
Production (tons)
Appalachia
Northern			1,337				1,334				3				<1	%
Central			8,942				9,240				(298	)			(3	%)
Southern			1,294				1,033				261				25	%
Total Appalachia			11,573				11,607				(34	)			(<1	%)
Illinois Basin			1,165				502				663				132	%
Northern Powder River Basin			1,731				1,401				330				24	%
Total			14,469				13,510				959				7	%
Average gross royalty per ton
Appalachia
Northern		$	2.62			$	2.08			$	0.54				26	%
Central			3.84				3.27				0.57				17	%
Southern			4.25				3.91				0.34				9	%
Total Appalachia			3.74				3.19				0.55				17	%
Illinois Basin			2.26				2.22				0.04				2	%
Northern Powder River Basin			1.86				2.00				(0.14	)			(7	%)
Combined average gross royalty per ton			3.40				3.03				0.37				12	%
Aggregates:
Royalty revenue		$	1,418			$	1,581			$	(163	)			(10	%)
Aggregate royalty bonus		$	1,944			$	164			$	1,780				1085	%
Production			1,154				1,341				(187	)			(14	%)
Average base royalty per ton		$	1.23			$	1.18			$	0.05				4	%

     Coal Royalty Revenues and Production. Coal royalty revenues comprised approximately 77% and 82% of our total revenue for the three month periods ended March 31, 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 three month period ended March 31, 2008 compared to the same period of 2007, while production stayed nearly constant. The Appalachian results by region are set forth below.

     Northern Appalachia. Coal royalty revenues increased primarily due to acquisitions and a new mine with higher per ton coal royalty revenue. Coal royalty revenues attributable to acquisitions were $1.6 million and production was 668,000 tons. These increases were partially offset by lower production on our AFC properties, where a greater proportion of the production for the quarter ended March 31, 2008, was on adjacent property.

     Central Appalachia. Coal royalty revenues attributable to acquisitions completed since the end of the first quarter of 2007 were $1.1 million and production was 142,000 tons. Coal production on our other properties decreased 440,000 tons but this decrease was more than offset by higher prices being received by our lessees resulting in higher per ton coal royalty revenue.

     Southern Appalachia. Our coal royalty revenues and production in Southern Appalachia increased for the quarter ended March 31, 2008 compared to the same period in 2007 due to a lessee on our BLC property having a greater proportion of their production on our property and increased shipments for our Oak Grove property. These increases were slightly offset on our Twin Pines/Drummond property as production moved partially to adjacent property. In general, all of our lessees experienced improved pricing.

     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 per ton revenue is lower for the quarter ended March 31, 2008 compared to the same quarter in 2007. The higher per ton rate in the first 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 royalties were up $1.7 million for the three months ended March 31, 2008 compared to the first quarter of 2007. In the first quarter 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. Production was virtually flat for the two periods.

Other Operating Results

     Coal Transportation and Processing Revenues. For the quarter ended March 31, 2008, we generated $1.9 million in processing revenues compared with $0.9 million for the same period 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. Production increased 55% for the first quarter of 2008 compared to the same period of 2007.

     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 approximately $1.6 million and $0.5 million in transportation fees from these assets for the first quarter of 2008 and 2007, respectively. Production increased 262% for the first quarter of 2008 compared to the same period in 2007, as we reported a full quarter of transportation revenue in 2008.

     Oil and Gas Royalties. We generated $1.4 million and $1.3 million from oil and gas royalties for the first quarter of 2008 and 2007, respectively.

     Override revenues. For the quarter ending March 31, 2008, override revenues were $2.5 million compared to $1.0 million for the first quarter of 2007. The increase of $1.5 million is 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 $1.4 million and $1.2 million for the three months ended March 31, 2008 and 2007, respectively.

     Operating costs and expenses. Included in total expenses are:

	•		Depreciation, depletion and amortization of $15.1 million and $11.8 million for the quarters ended March 31, 2008 and 2007, respectively. While depreciation is approximately the same for both years, depletion fluctuates based on the depletion rates where coal is mined. The new properties that we acquired in 2007 and at the end of 2006 are being depleted at much higher rates than our older properties, resulting in the significant increases.
	•		General and administrative expenses of $4.1 million and $6.6 million for the quarters ended March 31, 2008 and 2007,

respectively. The decrease in general and administrative expenses is primarily attributable to decreases in our unit price, which reduces our accruals under our long-term incentive plan.

•

Property, franchise and other taxes of $3.6 million for the first quarter of 2008 compared to $3.1 million for the same period of 2007. 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 $7.4 million and $7.3 million for the quarters ended March 31, 2008 and 2007, respectively. Although the level of debt has increased approximately $38 million since the first quarter of 2007, the interest rates on our revolving credit facility are lower. We also 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.

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 three months ended March 31, 2008 and 2007 was $39.2 million and $30.7 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 three months ended March 31, 2008 and 2007 was $2.8 million and $19.1 million, respectively. For the three months ended March 31, 2007, substantially all of our investing activities consisted of acquiring coal reserves and other mineral rights. For the first quarter of 2008, $2.8 million was used for additional payments on coal infrastructure still under construction.

     Net cash used for financing activities for the three months ended March 31, 2008 and 2007 was $40.4 million and $22.1 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 we used those proceeds to pay down our credit facility. Cash distributions to our partners were $40.2 million and $34.1 million for the three months ended March 31, 2008 and 2007, respectively. In the first quarter of 2007, as a part of the Dingess-Rum and Mettiki acquisitions we received $2.3 million in cash contributions from our general partner to maintain its 2% interest.

Long-Term Debt

     At March 31, 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;
	•		$55.8 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;
	•		$46.8 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 only 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 do 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 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.

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 for each of the three month periods ended March 31, 2008 and 2007.

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 March 31, 2008, we had accounts receivable totaling $0.4 million from Williamson. For the three month periods ended March 31, 2008 and 2007, we had total revenue of $1.9 million and $0.7 million, respectively, from Williamson. In addition, we received advance minimum royalties of $5.2 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 March 31, 2008, we had accounts receivable totaling $0.5 million from Gatling. For the three month periods ended March 31, 2008 and 2007, we had total revenue of $1.2 million and $0.4 million, respectively, from Gatling, LLC. In addition, we received advance minimum royalty payments of $4.7 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 $38.3 million. For the three months ended March 31, 2008 and 2007, we received total revenue of $1.1 million and $0.5 million, respectively, from Taggart. At March 31, 2008, we had accounts receivable totaling $0.7 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 month periods ended March 31, 2008 and 2007, we had total revenue of $0.3 million and $0.6 million, respectively, from Kopper-Glo, and at March 31, 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 March 31, 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 March 31, 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

4.1		—		Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated April 7, 2008 (incorporated by reference to Exhibit 4.1 to the Current Reports on Form 8-K filed on April 8, 2008).
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: May 8, 2008

Date: May 8, 2008

Date: May 8, 2008