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

Commission file number: 001-31465

NATURAL RESOURCE PARTNERS L.P.

(Exact name of registrant as specified in its charter)

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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 Accelerated Filer		o Non-accelerated Filer (Do not check if a smaller reporting company)		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 6, 2010 there were 74,027,836 Common Units outstanding.

 

 

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009			4
Consolidated Statements of Income For the Three Months Ended March 31, 2010 and 2009			5
Consolidated Statements of Cash Flows For the Three Months Ended March 31, 2010 and 2009			6
Notes to Consolidated Financial Statements			7
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview			16
Results of Operations			20
Liquidity and Capital Resources			21
Related Party Transactions			23
Environmental			24
ITEM 3. Quantitative And Qualitative Disclosures About Market Risk			24
ITEM 4. Controls And Procedures			25
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings			26
ITEM 1A. Risk Factors			26
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds			26
ITEM 3. Defaults Upon Senior Securities			26
ITEM 4. (Removed and Reserved)			26
ITEM 5. Other Information			26
ITEM 6. Exhibits			27
Signatures			28
EX-31.1
EX-31.2
EX-32.1
EX-32.2

Forward-Looking Statements

     Statements included in this Form 10-Q are forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements 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 this Form 10-Q and in our Form 10-K/A for the year ended December 31, 2009 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)

		March 31,				December 31,
		2010				2009
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	62,856			$	82,634
Accounts receivable, net of allowance for doubtful accounts			28,268				27,141
Accounts receivable — affiliate			5,334				4,342
Other			771				930
Total current assets			97,229				115,047
Land			24,343				24,343
Plant and equipment, net			62,274				64,351
Coal and other mineral rights, net			1,193,908				1,151,835
Intangible assets, net			163,794				164,554
Loan financing costs, net			2,777				2,891
Other assets, net			508				569
Total assets		$	1,544,833			$	1,523,590
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities		$	681			$	914
Accounts payable — affiliates			179				179
Obligation related to acquisition			4,477				2,969
Current portion of long-term debt			32,235				32,235
Accrued incentive plan expenses — current portion			3,851				4,627
Property, franchise and other taxes payable			5,112				6,164
Accrued interest			3,164				10,300
Total current liabilities			49,699				57,388
Deferred revenue			80,031				67,018
Accrued incentive plan expenses			5,626				7,371
Long-term debt			657,395				626,587
Partners’ capital:
Common units outstanding: (69,451,136)			726,797				747,437
General partner’s interest			12,886				13,409
Holders of incentive distribution rights			12,983				4,977
Accumulated other comprehensive loss			(584	)			(597	)
Total partners’ capital			752,082				765,226
Total liabilities and partners’ capital		$	1,544,833			$	1,523,590

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
		March 31,
		2010				2009
		(Unaudited)
Revenues:
Coal royalties		$	47,161			$	52,607
Aggregate royalties			891				1,650
Coal processing fees			1,644				1,900
Transportation fees			2,775				2,096
Oil and gas royalties			1,099				1,493
Property taxes			2,651				3,211
Minimums recognized as revenue			3,374				223
Override royalties			2,967				2,548
Other			957				1,005
Total revenues			63,519				66,733
Operating costs and expenses:
Depreciation, depletion and amortization			11,368				13,078
General and administrative			6,548				7,506
Property, franchise and other taxes			3,734				3,975
Transportation costs			265				268
Coal royalty and override payments			692				489
Total operating costs and expenses			22,607				25,316
Income from operations			40,912				41,417
Other income (expense):
Interest expense			(10,729	)			(8,079	)
Interest income			8				82
Net income		$	30,191			$	33,420
Net income attributable to:
General partner		$	344			$	441
Holders of incentive distribution rights		$	12,983			$	11,381
Limited partners		$	16,864			$	21,598
Basic and diluted net income per limited partner unit		$	0.24			$	0.33
Weighted average number of units outstanding			69,451				64,891

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

		Three Months Ended
		March 31,
		2010				2009
		(Unaudited)
Cash flows from operating activities:
Net income		$	30,191			$	33,420
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			11,368				13,078
Non-cash interest charge, net			150				882
Change in operating assets and liabilities:
Accounts receivable			(2,119	)			(3,463	)
Other assets			220				267
Accounts payable and accrued liabilities			(233	)			(395	)
Accrued interest			(7,136	)			(3,145	)
Deferred revenue			13,013				5,512
Accrued incentive plan expenses			(2,521	)			(466	)
Property, franchise and other taxes payable			(1,052	)			(2,138	)
Net cash provided by operating activities			41,881				43,552
Cash flows from investing activities:
Acquisition of land, coal and other mineral rights			(46,150	)			(95,641	)
Acquisition or construction of plant and equipment			—				(1,157	)
Net cash used in investing activities			(46,150	)			(96,798	)
Cash flows from financing activities:
Proceeds from loans			46,000				303,000
Deferred financing costs			—				(661	)
Repayment of loans			(15,192	)			(151,192	)
Retirement of obligation related to acquisitions			(2,969	)			(40,000	)
Distributions to partners			(43,348	)			(46,720	)
Net cash (used in) provided by financing activities			(15,509	)			64,427
Net increase (decrease) in cash and cash equivalents			(19,778	)			11,181
Cash and cash equivalents at beginning of period			82,634				89,928
Cash and cash equivalents at end of period		$	62,856			$	101,109
Supplemental cash flow information:
Cash paid during the period for interest		$	17,700			$	10,280
Non-cash financing activities:
Obligation related to purchase of coal reserves and infrastructure		$	4,477			$	59,220

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, 2010 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 2009 Annual Report on Form 10-K/A 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. Significant Accounting Policies Update

     Reclassification

          Certain reclassifications have been made to the prior year’s financial statements. Immaterial amounts relating to the AzConAgg and Gatling Ohio acquisitions have been reclassified between various assets based upon more information.

     Recent Accounting Pronouncements

          In January 2010, the FASB amended fair value disclosure requirements. This amendment requires a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. See Note 9. “Fair Value Measurements” for the definition of Level 1 and Level 2 measurements. The amendment also requires a reporting entity to present separately information about purchases, sales, issuances, and settlements in the reconciliation for fair value measurements using significant unobservable inputs. This amendment is effective for fiscal years beginning after December 15, 2009 and interim periods within those fiscal years. The Partnership applied the effective provisions of this standard update in preparing its disclosures, and the adoption of the standard did not have a material effect on such disclosures.

          In June 2009, the FASB issued a new standard amending previous consolidation of variable interest entities guidance. This amended guidance requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it controlling financial interest in a variable interest entity. This amendment is effective for fiscal years beginning after November 15, 2009 and interim periods within those fiscal years. The Partnership does not expect this adoption to have a material impact on the financial statements.

          In February 2010, the FASB amended the subsequent events standard, removing the requirement for an SEC filer to disclose a date in issued and revised financial statements. The FASB added that revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of U.S. GAAP. The Partnership adopted this amendment for the quarter ended March 31, 2010. The adoption did not have a material impact on the Partnership’s disclosures.

          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. Recent Acquisitions

          Northgate-Thayer. In March 2010, the Partnership acquired approximately 100 acres of mineral and surface rights related to dolomite reserves in White County, Indiana from a local operator for a purchase price of $7.5 million. As of March 31, 2010 the Partnership had funded $3.0 million of the acquisition, and the remaining payments are expected to be paid over the next three months upon completion of certain development milestones.

          Massey-Override. In March 2010, the Partnership acquired from Massey Energy subsidiaries overriding royalty interests in coal reserves located in southern West Virginia and eastern Kentucky. Total consideration for this purchase was $3.0 million.

          AzConAgg. In December 2009, the Partnership acquired approximately 230 acres of mineral and surface rights related to sand and gravel reserves in southern Arizona from a local operator for $3.75 million.

          Colt. In September 2009, the Partnership signed a definitive agreement to acquire approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt LLC, an affiliate of the Cline Group, through eight separate transactions for a total purchase price of $255 million. In January 2010, the Partnership closed the second transaction for $40.0 million and acquired approximately 19.5 million tons of reserves. As of March 31, 2010, the Partnership had acquired approximately 22.8 million tons of reserves associated with the initial production from the mine for approximately $50 million. Future closings anticipated through 2012 will be associated with completion of certain milestones related to the new mine’s construction.

          Blue Star. In July 2009, the Partnership acquired approximately 121 acres of limestone reserves in Wise County, Texas from Blue Star Materials, LLC for a purchase price of $24 million.

          Gatling Ohio. In May 2009, the Partnership completed the purchase of the membership interests in two companies from Adena Minerals, LLC, an affiliate of the Cline Group. The companies own 51.5 million tons of coal reserves and infrastructure assets at Cline’s Yellowbush Mine located on the Ohio River in Meigs County, Ohio. The Partnership issued 4,560,000 common units to Adena Minerals in connection with this acquisition. In addition, the general partner of Natural Resource Partners granted Adena Minerals an additional nine percent interest in the general partner as well as additional incentive distribution rights.

          Massey- Jewell Smokeless. In March 2009, the Partnership acquired from Lauren Land Company, a subsidiary of Massey Energy, the remaining four-fifths interest in coal reserves located in Buchanan County, Virginia in which the Partnership previously held a one-fifth interest. Total consideration for this purchase was $12.5 million.

          Macoupin. In January 2009, the Partnership acquired approximately 82 million tons of coal reserves and infrastructure assets related to the Shay No. 1 mine in Macoupin County, Illinois for $143.7 million from Macoupin Energy, LLC, an affiliate of the Cline Group.

4. Plant and Equipment

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

		March 31,				December 31,
		2010				2009
		(In thousands)
		(Unaudited)
Plant and equipment at cost		$	81,866			$	81,866
Accumulated depreciation			(19,592	)			(17,515	)
Net book value		$	62,274			$	64,351

		Three months ended
		March 31,
		2010				2009
		(In thousands)
		(Unaudited)
Total depreciation expense on plant and equipment		$	2,077			$	1,887

5. Coal and Other Mineral Rights

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

		March 31,				December 31,
		2010				2009
		(In thousands)
		(Unaudited)
Coal and other mineral rights		$	1,511,587			$	1,460,984
Less accumulated depletion and amortization			(317,679	)			(309,149	)
Net book value		$	1,193,908			$	1,151,835

		Three months ended
		March 31,
		2010				2009
		(In thousands)
		(Unaudited)
Total depletion and amortization expense on coal and other mineral rights		$	8,530			$	10,600

6. Intangible Assets

          In 2009, the Partnership identified $65.1 million of above market contracts relating to the AzConAgg, Gatling Ohio and Macoupin acquisitions. Amounts recorded as intangible assets along with the balances and accumulated amortization at March 31, 2010 and December 31, 2009 are reflected in the table below:

		March 31,				December 31,
		2010				2009
		(In thousands)
		(Unaudited)
Above market contracts		$	172,706			$	172,706
Less accumulated amortization			(8,912	)			(8,152	)
Net book value		$	163,794			$	164,554

		For the three months ended
		March 31,
		2010				2009
		(In thousands)
		(Unaudited)
Total amortization expense on intangible assets		$	760			$	591

          Amortization expense 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, 2010		$	3,904
For year ended December 31, 2011			5,330
For year ended December 31, 2012			5,098
For year ended December 31, 2013			5,098
For year ended December 31, 2014			5,098

7. Long-Term Debt

     Long-term debt consists of the following:

		March 31,				December 31,
		2010				2009
		(In thousands)
		(Unaudited)
$300 million floating rate revolving credit facility, due March 2012		$	74,000			$	28,000
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			43,700				43,700
8.38% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2013, maturing in March 2019			150,000				150,000
5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020			84,615				84,615
5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021			2,115				2,307
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023			40,200				40,200
5.82% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2010, maturing in March 2024			210,000				225,000
8.92% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2014, maturing in March 2024			50,000				50,000
Total debt			689,630				658,822
Less — current portion of long term debt			(32,235	)			(32,235	)
Long-term debt		$	657,395			$	626,587

          Principal payments due in:

2010		$	17,042
2011			31,518
2012			104,801
2013			87,230
2014			56,175
Thereafter			392,864
		$	689,630

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

	•		Maintain a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four most recent quarters;
	•		not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and
	•		maintain the ratio of consolidated EBITDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.

          Two tranches of amortizing senior notes were issued in March 2009: $150 million that bear interest at 8.38%; and $50 million that bear interest at 8.92%. Both tranches of the notes have semi-annual interest payments. These senior notes also provide that in the event that the Partnership’s leverage ratio exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00.

          The Partnership made a principal payment of $15.0 million on its 5.82% senior notes during the quarter ended March 31, 2010.

          The Partnership has a $300 million revolving credit facility, and at March 31, 2010, $226 million was available under the facility. The Partnership incurs a commitment fee on the undrawn portion of the revolving credit facility at rates ranging from 0.10% to 0.30% per annum. Under an accordion feature in the credit facility, the Partnership may request its lenders to increase their aggregate

commitment to a maximum of $450 million on the same terms. However, under the current market conditions, the Partnership cannot be certain that its lenders will elect to participate in the accordion feature. To the extent the lenders decline to participate, the Partnership may elect to bring new lenders into the facility, but cannot make any assurance that the additional credit capacity will be available on existing terms.

          The Partnership had $74.0 million and $28.0 million outstanding on its revolving credit facility at March 31, 2010 and December 31, 2009, respectively. The weighted average interest rate at March 31, 2010 and December 31, 2009 was 1.37% and 2.07%, respectively.

          The revolving credit facility contains covenants requiring the Partnership 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.

The Partnership was in compliance with all terms under its long-term debt as of March 31, 2010.

8. Fair Value Measurements

          The Partnership discloses certain assets and liabilities using fair value as defined by FASB’s fair value authoritative guidance.

          FASB’s guidance describes three levels of inputs that may be used to measure fair value:

	•		Level 1 — Quoted prices in active markets for identical assets or liabilities.
	•		Level 2 — Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
	•		Level 3 — Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets and liabilities include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation.

          The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of the Partnership’s financial instruments included in accounts receivable and accounts payable approximates their fair value due to their short-term nature. The Partnership’s cash and cash equivalents include money market accounts and are considered a Level 1 measurement. The fair market value of the Partnership’s long-term debt was estimated to be $619.4 million and $627.5 million at March 31, 2010 and December 31, 2009, respectively, for the senior notes. The carrying value of the Partnership’s long-term debt was $615.6 million and $630.8 million at March 31, 2010 and December 31, 2009, respectively, for the senior notes. The fair value is estimated by management using comparable term risk-free treasury issues with a market rate component determined by current financial instruments with similar characteristics which is a Level 3 measurement. Since the Partnership’s credit facility is variable rate debt, its fair value approximates its carrying amount.

9. Net Income Per Unit Attributable to Limited Partners and Adoption of Two-Class Method

          Basic and diluted net income per unit attributable to limited partners are the same since the Partnership has no potentially dilutive securities outstanding.

          The holders of the IDRs elected to cap the distribution at Tier III for the quarters ending September 30, 2009 and December 31, 2009.

10. Related Party Transactions

     Reimbursements to Affiliates of our General Partner

          The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the 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 our general partner and its affiliates.

          The reimbursements to affiliates of the Partnership’s general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation totaled $1.8 million and $1.7 million for the three months ended March 31, 2010 and 2009, respectively. At March 31, 2010 the Partnership also had accounts payable to affiliates of $0.2 million.

     Transactions with Cline Affiliates

          Various companies controlled by Chris Cline lease coal reserves from the Partnership, and the Partnership provides coal transportation services to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest in the Partnership’s general partner and in the incentive distribution rights of the Partnership, as well as 13,510,072 common units. At March 31, 2010, the Partnership had accounts receivable totaling $4.9 million from Cline affiliates. For the three months ended March 31, 2010 and 2009, the Partnership had total revenue of $11.4 million and $6.2 million, respectively, from these companies. In addition, the Partnership has also received $30.9 million in advance minimum royalty payments that have not been recouped with Cline affiliates.

     Quintana Capital Group GP, Ltd.

          Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, the Partnership adopted a formal conflicts policy that establishes the opportunities that will be pursued by the Partnership and those that will be pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines set forth in NRP’s conflicts policy.

          A fund controlled by Quintana Capital owns a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. The Partnership currently has a memorandum of understanding with Taggart Global pursuant to which the two companies have agreed to jointly pursue the development of coal handling and preparation plants. The Partnership owns and leases the plants to Taggart Global, which designs, builds and operates 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 $46.6 million. For each of the three month periods ending March 31, 2010 and 2009, the Partnership received total revenue of $1.0 million from Taggart. At March 31, 2010, the Partnership had accounts receivable totaling $0.3 million from Taggart.

          A fund controlled by Quintana Capital owns Kopper-Glo, a small coal mining company that is one of the Partnership’s lessees with operations in Tennessee. For each of the three month periods ending March 31, 2010 and 2009, the Partnership had total revenue of $0.5 million from Kopper-Glo. The Partnership also had accounts receivable totaling $0.1 million at March 31, 2010.

     Office Building in Huntington, West Virginia

          In 2008, Western Pocahontas Properties completed construction of an office building in Huntington, West Virginia. On January 1, 2009, the Partnership began leasing substantially all of two floors of the building from Western Pocahontas Properties and pays $0.5 million in lease payments each year through December 31, 2018.

11. 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, 2010. The Partnership is not associated with any environmental contamination that may require remediation costs.

     Acquisition

          In conjunction with a definitive agreement, the Partnership may be obligated to purchase in excess of 171 million additional tons of coal reserves from Colt, LLC for an aggregate purchase price of $205.0 million over the next two years as certain milestones are completed relating to construction of a new mine.

12. Major Lessees

          Revenues from lessees that exceeded ten percent of total revenues for the periods are indicated below:

		Three Months Ended
		March 31,
		(Dollars in thousands)
		(Unaudited)
		2010								2009
		Revenues				Percent				Revenues				Percent
The Cline Group		$	11,385				18	%		$	6,245				9	%
Alpha Natural Resources			6,080				10	%			7,308				11	%

13. Incentive Plans

          GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the “Long-Term Incentive Plan”) for directors of GP Natural Resource Partners LLC and employees of its affiliates who perform services for the Partnership. The Compensation, 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 2010 are as follows:

Outstanding grants at the beginning of the period			653,598
Grants during the period			199,548
Grants vested and paid during the period			(133,782	)
Forfeitures during the period			(832	)
Outstanding grants at the end of the period			718,532

          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 0.34% to 2.01% and 35.04% to 57.22%, respectively at March 31, 2010. The Partnership’s historic distribution rate of 6.61% was used in the calculation at March 31, 2010. Projected forfeitures were 2,472 and 3,160 at March 31, 2010 and 2009 based upon historical forfeitures. The Partnership recorded expenses related to its plan to be reimbursed to its general partner of $1.8 million and $2.9 million for the three month periods ended March 31, 2010 and 2009, 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 $2.9 million were paid during the three month periods ended March 31, 2010 and 2009, respectively.

          In connection with the phantom unit awards granted since 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 grants since 2008 that vest in 2012 through 2014 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 but may be subject to forfeiture if the grantee ceases employment prior to vesting.

          The unaccrued cost associated with the outstanding grants and related DERs at March 31, 2010 was $14.3 million.

14. Distributions

          On February 12, 2010, the Partnership paid a quarterly distribution $0.54 per unit to all holders of common units.

15. Subsequent Events

          The following represents material events that have occurred subsequent to March 31, 2010 through the time of the Partnership’s filing with the Securities and Exchange Commission:

     Acquisitions

          On April 26, 2010, the Partnership acquired the rights to aggregates on a 1,000 acre property in Northern California from Sierra Silica Resources LLC for $17.0 million.

     Equity Offering

          On April 7, 2010, the Partnership closed an underwritten public offering of 4,576,700 common units at $25.17 per common unit. The Partnership used a portion of the net proceeds of approximately $112.5 million from this offering, including the Partnership’s general partner’s proportionate capital contribution, to repay all of the indebtedness outstanding under the Partnership’s credit facility and intend to use the remaining cash for general partnership purposes, including financing future acquisitions, such as subsequent closings under the transaction with Colt LLC and other acquisitions in the ordinary course of business.

     Distributions

          On April 22, 2010, the Partnership declared a first quarter 2010 distribution of $0.54 per unit. The distribution will be paid on May 14, 2010 to unitholders of record on May 5, 2010.

     Operations

          On April 9, the Partnership was notified by the Cline Group that it has temporarily idled certain sections of its Broad Run mine (which the Partnership refers to as its Gatling, West Virginia mine) and continues development work in other areas of the mine. Cline has indicated that it intends to restart the mine in the future, but an exact date is not known. Cline has communicated to the Partnership that it will continue to make its quarterly minimum payments with respect to this mine.

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/A, as filed on March 3, 2010.

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, 2009, we owned or controlled approximately 2.1 billion tons of proven and probable coal reserves, of which 54% are low sulfur coal. We also owned approximately 130 million tons of aggregate reserves in Washington, Texas, Arizona and West Virginia. We lease our reserves to experienced mine operators under long-term leases that grant the operators the right to mine and sell our reserves in exchange for royalty payments.

          Our revenue and profitability are dependent on our lessees’ ability to mine and market our 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. In contrast, our aggregate properties are typically mined by regional operators with significant experience and knowledge of the local markets. The aggregates are sold at current market prices, which historically have increased along with the producer price index for sand and gravel. Over the long term, both our coal and aggregate royalty revenues are affected by changes in the market for and the market price of the commodities.

          In our 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 or aggregates they sell, subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time (usually two to five years) if sufficient royalties are generated from production in those future periods. We do not recognize these minimum 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 and aggregate royalty revenues, we generated approximately 24% of our first quarter 2010 revenues from other sources, as compared to 21% in the first quarter of 2009. These other sources include: coal processing and transportation fees; overriding royalties; royalties on oil and gas; wheelage payments; rentals; property tax revenue; minimums received as revenue; and timber.

     Our Current Liquidity Position

          As of March 31, 2010, we had $226 million in available capacity under our existing credit facility, which does not mature until March 2012, as well as approximately $62.9 million in cash. On April 7, 2010, we completed an equity offering in which we received net proceeds of $110.2 million excluding our general partner’s proportionate capital contribution. We used these proceeds to pay down all of our borrowings under our credit facility, and intend to use the remaining cash for general partnership purposes and to fund acquisitions, including three aggregates acquisitions that we announced in April and the Colt acquisition discussed below.

          Pursuant to the purchase and sale agreement signed in connection with the Colt acquisition, we expect to fund an additional $205 million over the next two years, of which approximately $125 million is anticipated to be funded over the remainder 2010, as the operator achieves various development milestones. We anticipate funding these acquisitions through the use of the available capacity under our credit facility and through the issuance of debt and/or equity in the capital markets. We believe that we have enough liquidity to meet our current capital needs.

          In connection with the Colt acquisition, the holders of our incentive distribution rights agreed to forego approximately $7.35 million in distributions with respect to each of the third and fourth quarters of 2009. In addition, because we amortize substantially all of our long-term debt, we have no need to pay off or refinance any debt obligations other than our regularly scheduled principal payments.

     Current Results

          As of March 31, 2010, our coal and aggregate reserves were subject to 215 leases with 77 lessees. For the three months ended March 31, 2010, our lessees produced 11.4 million tons of coal and aggregates, generating $48.1 million in royalty revenues from our properties, and our total revenues were $63.5 million.

          After a difficult coal market in 2009, we began to see signs of improvement in the first quarter of 2010. Although our total revenues and coal royalty revenues declined slightly as compared to the fourth quarter of 2009, coal prices, particularly for metallurgical coal increased during the quarter as demand also improved. Because approximately 39% of our coal royalty revenues and 33% of the related production during the first quarter of 2010 were from metallurgical coal, we are in position to benefit as the global economy recovers and the demand for steel increases. We anticipate that metallurgical coal prices should continue to increase over 2010 and expect that during 2010 we will experience gradual improvements similar to the changes we saw in the latter part of 2009.

          Even though coal royalty revenues from our Appalachian properties represented 64% of our total revenues in the first quarter of 2010, this percentage has continued to decline as we are diligently working to diversify our holdings by expanding our presence in the Illinois Basin and through additional aggregates acquisitions. Through our relationship with the Cline Group, we expect our Illinois Basin assets to contribute even more significantly to our total revenues in 2010.

     Political, Legal and Regulatory Environment

          The political, legal and regulatory environment is becoming increasingly difficult for the coal industry. In June 2009, the White House Council on Environmental Quality announced a Memorandum of Understanding among the Environmental Protection Agency, or “EPA”, Department of Interior, and the U.S. Army Corps of Engineers concerning the permitting and regulation of coal mines in Appalachia. While the Council described this memorandum as an “unprecedented step[s] to reduce environmental impacts of mountaintop coal mining,” the memorandum broadly applies to all forms of coal mining in Appalachia. The memorandum contemplates both short-term and long-term changes to the process for permitting and regulating coal mines in Appalachia.

          These new processes, as yet undefined by EPA, impact only six Appalachian states. In connection with this initiative, the EPA has used its authority to create significant delays in the issuance of new permits and the modification of existing permits. The all-encompassing nature of the changes suggests that implementation of the memorandum will generate continued uncertainty regarding the permitting of coal mines in Appalachia for some time and inevitably will lead, at a minimum, to substantial delays and increased costs.

          In addition to the increased oversight of the EPA, the Mine Safety and Health Administration, or MSHA, has increased its involvement in the approval of plans and enforcement of safety issues in connection with mining. The recent mine disaster at Massey’s Upper Big Branch Mine will likely lead to even more scrutiny by MSHA of our lessees’ operations, as well as possible additional mine safety legislation being considered by Congress. MSHA’s involvement has increased the cost of mining due to more frequent citations and much higher fines imposed on our lessees as well as the overall cost of regulatory compliance. Combined with the difficult economic environment and the higher costs of mining in general, MSHA’s recent increased participation in the mine development process could significantly delay the opening of new mines.

          The United States Congress has been considering multiple bills that would regulate domestic carbon dioxide emissions, but no such bill has yet received sufficient Congressional support for passage into law. The existing Clean Air Act is also a possible mechanism for regulating greenhouse gases. In April 2007, the U.S. Supreme Court rendered its decision in Massachusetts v. EPA, finding that the EPA has authority under the Clean Air Act to regulate carbon dioxide emissions from automobiles and can decide against regulation only if the EPA determines that carbon dioxide does not significantly contribute to climate change and does not endanger public health or the environment. In response to Massachusetts v. EPA, in July 2008, the EPA issued a notice of proposed rulemaking requesting public comment on the regulation of greenhouse gases, or “GHGs”. On October 27, 2009 EPA announced how it will establish thresholds for phasing-in and regulating greenhouse gas emissions under various provisions of the Clean Air Act. Three days later, on October 30, 2009, EPA published a final rule in the Federal Register that requires the reporting of greenhouse gas emissions from all sectors of the American economy, although reporting of emissions from underground coal mines and coal suppliers as originally proposed has been deferred pending further review. On December 15, 2009, EPA published a formal determination that six greenhouse gases, including carbon dioxide and methane, endanger both the public health and welfare of current and future generations. In the same Federal Register rulemaking, EPA found that emission of greenhouse gases from new motor vehicles and their engines contribute to greenhouse gas pollution. Although Massachusetts v. EPA did not involve the EPA’s authority to regulate

greenhouse gas emissions from stationary sources, such as coal-fueled power plants, the decision is likely to impact regulation of stationary sources.

          On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. The purpose of ACESA is to control and reduce emissions of GHGs in the United States. GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as coal.

          The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law. The President has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could have an adverse effect on demand for our coal.

     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 Three Months Ended
		March 31,
		(Unaudited)
		2010				2009
Net cash provided by operating activities		$	41,881			$	43,552
Less scheduled principal payments			(15,192	)			(192	)
Less reserves for future principal payments			(8,059	)			(8,059	)
Add reserves used for scheduled principal payments			15,192				192
Distributable cash flow		$	33,822			$	35,493

Recent 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.

          Sierra Silica. In April 2010, we acquired the rights to aggregates on a 1,000 acre property in Northern California from Sierra Silica Resources LLC for $17.0 million.

          North American Limestone. In April 2010, we signed an agreement for the construction of a fine grind processing facility for high calcium carbonate limestone located in Putnam County, Indiana. The total cost for the facility is not to exceed $6.5 million. Upon signing the agreement we funded approximately $1.0 million.

          Northgate-Thayer. In March 2010, we acquired approximately 100 acres of mineral and surface rights related to dolomite reserves in White County, Indiana from a local operator for a purchase price of $7.5 million. As of March 31, 2010 we had funded $3.0 million of the acquisition. The remaining payments are expected to be paid over the next three months upon completion of certain development milestones.

          Massey-Override. In March 2010, we acquired from Massey Energy subsidiaries overriding royalty interests in coal reserves located in southern West Virginia and eastern Kentucky. Total consideration for this purchase was $3.0 million.

          AzConAgg. In December 2009, we acquired approximately 230 acres of mineral and surface rights related to sand and gravel reserves in southern Arizona from a local operator for $3.75 million.

          Colt. In September 2009, we signed a definitive agreement to acquire approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt LLC, an affiliate of the Cline Group, through eight separate transactions for a total purchase price of $255 million. In January 2010, we closed the second transaction for $40.0 million and acquired approximately 19.5 million tons of reserves. As of March 31, 2010, we had acquired approximately 22.8 million tons of reserves associated with the initial production from the mine. Future closings anticipated through 2012 will be associated with completion of certain milestones related to the new mine’s construction.

          Blue Star. In July 2009, we acquired approximately 121 acres of limestone reserves in Wise County, Texas from Blue Star Materials, LLC for a purchase price of $24 million funded with cash and borrowings under the Partnership’s credit facility.

          Gatling Ohio. In May 2009, we completed the purchase of the membership interests in two companies from Adena Minerals, LLC, an affiliate of the Cline Group. The companies own 51.5 million tons of coal reserves and infrastructure assets at Cline’s Yellowbush Mine located on the Ohio River in Meigs County, Ohio. We issued 4,560,000 common units to Adena Minerals in connection with this acquisition. In addition, the general partner of Natural Resource Partners granted Adena Minerals an additional nine percent interest in the general partner as well as additional incentive distribution rights.

          Massey- Jewell Smokeless. In March 2009, we acquired from Lauren Land Company, a subsidiary of Massey Energy, the remaining four-fifths interest in coal reserves located in Buchanan County, Virginia in which the Partnership previously held a one-fifth interest. Total consideration for this purchase was $12.5 million.

          Macoupin. In January 2009, we acquired approximately 82 million tons of coal reserves and infrastructure assets related to the Shay No. 1 mine in Macoupin County, Illinois for $143.7 million from Macoupin Energy, LLC, an affiliate of the Cline Group.

Results of Operations

		Three Months Ended
		March 31,								Increase				Percentage
		2010				2009				(Decrease)				Change
		(In thousands, except percent and per ton data)
		(Unaudited)
Coal:
Coal royalty revenues
Appalachia
Northern		$	4,417			$	3,043			$	1,374				45	%
Central			31,808				37,878				(6,070	)			(16	%)
Southern			4,200				5,097				(897	)			(18	%)
Total Appalachia			40,425				46,018				(5,593	)			(12	%)
Illinois Basin			4,210				4,251				(41	)			(1	%)
Northern Powder River Basin			2,526				2,338				188				8	%
Total		$	47,161			$	52,607			$	(5,446	)			(10	%)
Production (tons)
Appalachia
Northern			1,247				1,099				148				13	%
Central			6,396				7,989				(1,593	)			(20	%)
Southern			701				841				(140	)			(17	%)
Total Appalachia			8,344				9,929				(1,585	)			(16	%)
Illinois Basin			1,147				1,326				(179	)			(13	%)
Northern Powder River Basin			1,311				1,227				84				7	%
Total			10,802				12,482				(1,680	)			(13	%)
Average gross royalty per ton
Appalachia
Northern		$	3.54			$	2.77			$	0.77				28	%
Central			4.97				4.74				0.23				5	%
Southern			5.99				6.06				(0.07	)			(1	%)
Total Appalachia			4.84				4.63				0.21				5	%
Illinois Basin			3.67				3.21				0.46				14	%
Northern Powder River Basin			1.93				1.91				0.02				1	%
Combined average gross royalty per ton			4.37				4.21				0.16				4	%
Aggregates:
Royalty revenue		$	816			$	930			$	(114	)			(12	%)
Aggregate royalty bonus		$	75			$	720			$	(645	)			(90	%)
Production			605				690				(85	)			(12	%)
Average base royalty per ton		$	1.35			$	1.35			$	—				—

          Coal Royalty Revenues and Production. Coal royalty revenues comprised approximately 74% and 79% of our total revenue for each of the three month periods ended March 31, 2010 and 2009, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:

          Appalachia. Primarily due to lower production by our lessees in the Central and Southern Appalachian regions, coal royalty revenues decreased in the three month period ended March 31, 2010 compared to the same period of 2009. The lower production was due to a number of factors, including temporary idling of mines, a difficult regulatory environment, increasingly difficult geologic conditions, reserve depletion, production curtailments related to a fire at a preparation plant and some mines moving to adjacent properties. This decline in production was in part offset by a higher royalty per ton in the Northern and Central Appalachian regions. While there are signs that the market conditions are starting to improve, particularly for metallurgical coal, we expect that our lessees in Appalachia will continue to experience these difficulties.

          Illinois Basin. Production decreased primarily due to a mine moving off our property and lower shipments from our Williamson property. The production decrease was nearly offset due to higher royalty per ton being realized, keeping coal royalty revenues nearly constant.

          Northern Powder River Basin. Coal royalty revenues and production increased on our Western Energy property due to the normal variations that occur due to the checkerboard nature of ownership.

          Aggregates Royalty Revenues and Production. Aggregate production decreased during the first quarter resulting in lower royalty revenue. The lower production is mainly attributed to lower demand in the region.

     Other Operating Results

          Coal Processing and Transportation Revenues. We generated $1.6 million and $1.9 million in processing revenues for the three month periods ended March 31, 2010 and 2009. We do not operate the preparation plants, but receive a fee for coal processed through them. Similar to our coal royalty structure, the throughput fees are based on a percentage of the ultimate sales price for the coal that is processed through the facilities

          In addition to our preparation plants, we own coal handling and transportation infrastructure in West Virginia, Ohio and Illinois. In contrast to our typical royalty structure, we receive a fixed rate per ton for coal transported over these facilities. For the assets other than our loadout facility at the Shay No. 1 mine in Illinois, 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 $2.8 million and $2.1 million for the quarters ended March 31, 2010 and 2009, respectively.

          Additional Revenues. In addition to coal royalties, aggregate royalties, coal processing and transportation revenues, we generated approximately 17% and 13% of our first quarter revenues from other sources in both 2010 and 2009, respectively. These other sources include: oil and gas royalties, property taxes, minimums recognized, overriding royalties, timber, rentals and wheelage.

          Operating costs and expenses. Included in total expenses are:

•

Depreciation, depletion and amortization of $11.4 million and $13.1 million for the three month periods ended March 31, 2010 and 2009, respectively. This decrease was primarily due to lower production.

•

General and administrative expenses of $6.5 million and $7.5 million for the three month periods ended March 31, 2010 and 2009, respectively. 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.

          Interest Expense. Interest expense was higher for the first quarter of 2010 when compared to the first quarter of 2009 due to additional debt incurred to fund acquisitions and higher interest rates.

Liquidity and Capital Resources

     Cash Flows and Capital Expenditures

          We satisfy our working capital requirements with cash generated from operations. Since our initial public offering, we have financed our property acquisitions with available cash, borrowings under our revolving credit facility, and the issuance of our senior notes and additional units. While our ability to satisfy our debt service obligations and pay distributions to our unitholders depends in large part on our future operating performance, our ability to make acquisitions will depend on prevailing economic conditions in the financial markets as well as the coal industry 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 this Form 10-Q and in our Form 10-K/A for the year ended December 31, 2009. Our capital expenditures, other than for acquisitions, have historically been minimal.

          Net cash provided by operations for the three months ended March 31, 2010 and 2009 was $41.9 million and $43.6 million, respectively. Approximately 70% to 80% of our cash provided by operations has historically been generated from coal royalty revenues.

          Net cash used in investing activities for the three months ended March 31, 2010 and 2009 was $46.2 million and $96.8 million, respectively. For the three months ended March 31, 2010 and 2009, substantially all of our investing activities consisted of acquiring coal reserves, plant and equipment and other mineral rights.

          Net cash flows used in financing for the three months ended March 31, 2010 was $15.5 million. During the first three months of 2010, we had proceeds from loans of $46.0 million offset by repayment of debt of $15.2 million and retirement of a $3.0 million obligation related to the purchase of coal reserves and infrastructure. We also paid distributions of $43.3 million. During the same period for 2009, net cash provided in financing activities was $64.4 million, which included proceeds from loans of $303.0 million, principal repayments of $151.2 million, retirement of obligation related to acquisitions of $40.0 million and $46.7 million for distributions to partners.

          Most of our lessees are required to make minimum annual or quarterly payments, which are generally recoupable against future production royalties. These minimum payments increase cash flows in the period received, but may not increase revenues until recouped against production royalties or the contractual recoupment period expires. Total deferred revenue as of March 31, 2010 was $80.0 million, which may reduce future cash flows when lessees recoup against production royalties.

     Long-Term Debt

          At March 31, 2010, our debt consisted of:

•

$74 million of our $300 million floating rate revolving credit facility, due March 2012;

•

$35 million of 5.55% senior notes due 2013;

•

$43.7 million of 4.91% senior notes due 2018;

•

$150 million of 8.38% senior notes due 2019;

•

$84.6 million of 5.05% senior notes due 2020;

•

$2.1 million of 5.31% utility local improvement obligation due 2021;

•

$40.2 million of 5.55% senior notes due 2023;

•

$210 million of 5.82% senior notes due 2024; and

•

$50 million of 8.92% 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 principal payments on the 5.82% senior notes due 2024 began March 2010, the principal payments of the 8.38% senior notes due in 2019 do not begin until March 2013 and the principal payments of the 8.92% senior notes do not begin until March 2014. We also make annual principal and interest payments on the utility local improvement obligation.

          Credit Facility. We have a $300 million revolving credit facility, and at March 31, 2010 we had approximately $226 million available to us under the facility. Under an accordion feature in the credit facility, we may request our lenders to increase their aggregate commitment to a maximum of $450 million on the same terms. However, under current market conditions, we cannot be certain that our lenders will elect to participate in the accordion feature. To the extent the lenders decline to participate, we may elect to bring new lenders into the facility, but cannot make any assurance that the additional credit capacity will be available to us on existing 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 governing the facility 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

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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 1.00.

          In March 2009, we issued $150 million of 8.38% notes maturing March 25, 2019 and $50 million of 8.92% notes maturing March 2024. These senior notes provide that in the event that our leverage ratio exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00.

     Shelf Registration Statement/Equity Offering

          In addition to our credit facility, on February 27, 2009 we filed an automatically effective shelf registration statement on Form S-3 with the SEC that is available for registered offerings of common units and debt securities. The amounts, prices and timing of the issuance and sale of any equity or debt securities will depend on market conditions, our capital requirements and compliance with our credit facility and senior notes.

          On April 7, 2010, we closed an underwritten public offering of 4,576,700 common units at $25.17 per common unit. We used a portion of the net proceeds of approximately $112.5 million from this offering, including our general partner’s proportionate capital contribution, to repay all of the indebtedness outstanding under our credit facility and intend to use the remaining cash for general partnership purposes, including funding future acquisitions, including closings under the transaction with Colt LLC and other acquisitions in the ordinary course of business.

     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

     Partnership Agreement

          Our general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with our partnership agreement, we reimburse our general partner and its affiliates 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. Cost reimbursements due our general partner may be substantial and will reduce our cash available for distribution to unitholders. The reimbursements to our general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation totaled $1.8 million and $1.7 million for the three months ended March 31, 2010 and 2009, respectively. For additional information, please read “Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement.”

     Transactions with Cline Affiliates

          Various companies controlled by Chris Cline lease coal reserves from NRP, and we provide coal transportation services to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest in NRP’s general partner and in the incentive distribution rights of NRP, as well as 13,510,072 common units. At March 31, 2010, we had accounts receivable totaling $4.9 million from Cline affiliates. For the three months ended March 31, 2010 and 2009, we had total revenue of $11.4 million and $6.2 million, respectively, from these companies. In addition, we have received $30.9 million in advance minimum royalty payments that have not been recouped.

     Quintana Capital Group GP, Ltd.

          Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, we adopted a formal conflicts policy that establishes the opportunities that will be pursued by NRP and those that will be pursued by Quintana Capital. The governance documents of Quintana Capital’s affiliated investment funds reflect the guidelines set forth in NRP’s conflicts policy.

          A fund controlled by Quintana Capital owns a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. We currently have 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. We 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, we have acquired four facilities under this agreement with Taggart with a total cost of $46.6 million. For each of the three month periods ending March 31, 2010 and 2009, we received total revenue of $1.0 million from Taggart. At March 31, 2010, we had accounts receivable totaling $0.3 million from Taggart.

          In June 2007, a fund controlled by Quintana Capital acquired Kopper-Glo, a small coal mining company that is one of our lessees with operations in Tennessee. For each of the three month periods ending March 31, 2010 and 2009, we had total revenue of $0.5 million from Kopper-Glo. We also had accounts receivable totaling $0.1 million from Kopper-Glo at March 31, 2010.

     Office Building in Huntington, West Virginia

          In 2008, Western Pocahontas Properties Limited Partnership completed construction of an office building in Huntington, West Virginia. On January 1, 2009, we began leasing substantially all of two floors of the building from Western Pocahontas at market rates. The terms of the lease were approved by our Conflicts Committee. We pay $0.5 million each year in lease payments.

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, 2010. 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. As evidenced by the current market, a substantial or extended decline in coal prices could materially and adversely affect us in two ways. First, lower prices may reduce the quantity of coal that may be economically produced from our properties. This, in turn, could reduce our coal royalty revenues and the value of our coal reserves. Second, even if production is not reduced, the royalties we receive on each ton of coal sold may be reduced. Additionally, volatility in coal prices could make it difficult to estimate with precision the value of our coal reserves and any coal reserves that we may consider for acquisition.

Interest Rate Risk

          Our exposure to changes in interest rates results from our borrowings under our revolving credit facility, which are subject to variable interest rates based upon LIBOR. At March 31, 2010, we had $74.0 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

          We are 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, our management believes these claims will not have a material effect on our financial position, liquidity or operations.

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/A for the year ended December 31, 2009.

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

          None.

Item 3. Defaults Upon Senior Securities

          None.

Item 4. (Removed and Reserved)

Item 5. Other Information

          None.

Item 6. Exhibits

1.1		—		Underwriting Agreement, dated as of April 1, 2010, by and among Natural Resource Partners L.P., GP Natural Resource Partners LLC and NRP (GP) LP, and UBS Securities LLC and Barclays Capital Inc., as representatives of the underwriters set forth in Schedule 1 to the Underwriting Agreement (incorporated by reference to Exhibit 1.1 to Current Report on Form 8-K filed on April 5, 2010).
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 6, 2010		By:		/s/ Corbin J. Robertson, Jr.   Corbin J. Robertson, Jr.,
				Chairman of the Board and
				Chief Executive Officer
				(Principal Executive Officer)
Date: May 6, 2010		By:		/s/ Dwight L. Dunlap   Dwight L. Dunlap,
				Chief Financial Officer and
				Treasurer
				(Principal Financial Officer)
Date: May 6, 2010		By:		/s/ Kenneth Hudson   Kenneth Hudson
				Controller
				(Principal Accounting Officer)