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

For the quarterly period ended September 30, 2010

OR

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

Commission file number: 001-31465

NATURAL RESOURCE PARTNERS L.P.

(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.)

601 Jefferson Street, Suite 3600
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)

(713) 751-7507
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant 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 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 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 November 5, 2010 there were 106,027,836 Common Units outstanding.

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009		4
Consolidated Statements of Income For the Three and Nine Months Ended September 30, 2010 and 2009		5
Consolidated Statements of Cash Flows For the Nine Months Ended September 30, 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		17
Results of Operations		21
Liquidity and Capital Resources		25
Related Party Transactions		27
Environmental		28
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		29
ITEM 4. Controls and Procedures		30
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings		31
ITEM 1A. Risk Factors		31
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds		31
ITEM 3. Defaults Upon Senior Securities		31
ITEM 4. (Removed and Reserved)		31
ITEM 5. Other Information		31
ITEM 6. Exhibits		32
Signatures		33
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

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 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.

3 

Part I. Financial Information

Item 1. Financial Statements

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS
(In thousands)

	September 30,			December 31,
	2010			2009
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	72,240		$	82,634
Accounts receivable, net of allowance for doubtful accounts		28,974			27,141
Accounts receivable — affiliates		7,850			4,342
Other		197			930
Total current assets		109,261			115,047
Land		24,343			24,343
Plant and equipment, net		63,701			64,351
Coal and other mineral rights, net		1,241,714			1,151,835
Intangible assets, net		160,751			164,554
Loan financing costs, net		2,550			2,891
Other assets, net		682			569
Total assets	$	1,603,002		$	1,523,590
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	2,486		$	914
Accounts payable — affiliates		178			179
Obligation related to acquisitions		—			2,969
Current portion of long-term debt		31,518			32,235
Accrued incentive plan expenses — current portion		5,734			4,627
Property, franchise and other taxes payable		5,603			6,164
Accrued interest		2,842			10,300
Total current liabilities		48,361			57,388
Deferred revenue		96,272			67,018
Accrued incentive plan expenses		8,689			7,371
Long-term debt		606,070			626,587
Partners’ capital:
Common units outstanding: (106,027,836 in 2010, 69,451,136 in 2009)		822,365			747,437
General partner’s interest		14,450			13,409
Holders of incentive distribution rights		—			4,977
Non-controlling interest		7,355			—
Accumulated other comprehensive loss		(560	)		(597	)
Total partners’ capital		843,610			765,226
Total liabilities and partners’ capital	$	1,603,002		$	1,523,590

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

4

NATURAL RESOURCE PARTNERS L.P.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(Unaudited)
Revenues:
Coal royalties	$	60,142		$	49,307		$	165,135		$	148,294
Aggregate royalties		1,606			1,700			2,847			4,697
Coal processing fees		2,343			1,508			6,680			5,808
Transportation fees		4,285			3,049			11,103			8,634
Oil and gas royalties		1,013			1,203			4,200			3,649
Property taxes		3,552			3,311			8,985			9,036
Minimums recognized as revenue		3,782			775			10,574			1,065
Override royalties		2,625			2,077			8,749			5,961
Other		1,404			1,032			5,586			3,038
Total revenues		80,752			63,962			223,859			190,182
Operating costs and expenses:
Depreciation, depletion and amortization		16,195			12,952			44,048			48,026
General and administrative		8,761			4,586			22,103			17,926
Property, franchise and other taxes		4,580			4,273			11,812			11,399
Transportation costs		614			403			1,436			1,144
Coal royalty and override payments		258			353			1,251			1,214
Total operating costs and expenses		30,408			22,567			80,650			79,709
Income from operations		50,344			41,395			143,209			110,473
Other income (expense):
Interest expense		(10,204	)		(10,762	)		(31,279	)		(29,516	)
Interest income		13			18			25			196
Income before non-controlling interest		40,153			30,651			111,955			81,153
Non-controlling interest		—			—			—			—
Net income	$	40,153		$	30,651		$	111,955		$	81,153
Net income attributable to:
General partner	$	803		$	513		$	1,720		$	1,052
Holders of incentive distribution rights	$	—		$	4,977		$	25,966		$	28,538
Limited partners	$	39,350		$	25,161		$	84,269		$	51,563
Basic and diluted net income per limited partner unit	$	0.51		$	0.36		$	1.14		$	0.77
Weighted average number of units outstanding		77,896			69,451			73,792			67,113

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

5

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

	Nine Months Ended
	September 30,
	2010			2009
	(Unaudited)
Cash flows from operating activities:
Net income	$	111,955		$	81,153
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		44,048			48,026
Non-cash interest charge, net		415			1,336
Change in operating assets and liabilities:
Accounts receivable		(5,341	)		(20	)
Other assets		620			579
Accounts payable and accrued liabilities		303			(143	)
Accrued interest		(7,458	)		(3,214	)
Deferred revenue		29,254			10,306
Accrued incentive plan expenses		2,425			2,408
Property, franchise and other taxes payable		(561	)		(1,632	)
Net cash provided by operating activities		175,660			138,799
Cash flows from investing activities:
Acquisition of land, coal and other mineral rights		(111,176	)		(114,986	)
Acquisition or construction of plant and equipment		(4,320	)		(1,157	)
Disposition of assets		808			—
Net cash used in investing activities		(114,688	)		(116,143	)
Cash flows from financing activities:
Proceeds from loans		85,000			325,000
Proceeds from issuance of units		110,436			—
Capital contribution by general partner		2,350			—
Deferred financing costs		—			(661	)
Repayment of loans		(106,234	)		(168,235	)
Retirement of obligation related to acquisitions		(9,169	)		(63,000	)
Costs associated with issuance of units		(152	)		(21	)
Fees associated with the elimination of the IDRs		(2,170	)		—
Distributions to partners		(151,427	)		(144,787	)
Net cash used in financing activities		(71,366	)		(51,704	)
Net decrease in cash and cash equivalents		(10,394	)		(29,048	)
Cash and cash equivalents at beginning of period		82,634			89,928
Cash and cash equivalents at end of period	$	72,240		$	60,880
Supplemental cash flow information:
Cash paid during the period for interest	$	38,292		$	31,316
Non-cash investing activities:
Mineral rights to be received	$	13,249		$	—
Liability associated with an acquisition		1,268			1,170
Equity issued for acquisitions		—			95,910
Non-controlling interest		(7,355	)		—
Non-cash financing activities:
Obligation related to purchase of reserves and infrastructure		6,200			74,022

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

6

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Organization

     The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 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 mineral properties in the United States. The Partnership owns coal reserves in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States, as well as lignite reserves in the Gulf Coast region. The Partnership also owns aggregate reserves in several states across the country. The Partnership does not operate any mines on its properties. The Partnership leases reserves through its subsidiaries to experienced operators under long-term leases that grant the operators the right to mine the Partnership’s 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. In most cases, the lessees are required to make minimum payments to the Partnership.

     In addition, the Partnership owns transportation and preparation equipment, 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

     Intangible Assets

     As of April 1, 2010, the Partnership adjusted the amortization of intangible assets to be based upon the greater of straight-line over the remaining estimated useful life or the unit-of-production. The Partnership determined that this refinement of the existing accounting policy more accurately reflects the future benefits of the assets. For the three and nine months ended September 30, 2010, the refinement resulted in an increase in amortization expense of $2.9 million and $5.9 million, or approximately $0.04 and $0.08 per unit, respectively. Although the Partnership anticipates this refinement to increase amortization expense in future periods, the amount of the increase will vary based upon actual production.

     Reclassification

     Certain reclassifications have been made to the prior year’s financial statements. Immaterial amounts relating to two 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 8. “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 amendment in preparing its disclosures, however the adoption of the standard did not have a material effect on such disclosures.

7

     On January 1, 2009, the Partnership adopted new standards for the accounting and reporting of non-controlling interests in a subsidiary. As discussed in Note 3, in connection with the business combination completed in June 2010, the Partnership acquired a controlling interest in a newly formed venture. All assets and liabilities of the venture are included in the consolidated balance sheet and the non-controlling interest in the venture is reflected as a component of equity; the revenues and expenses of the venture are reflected in consolidated results of operations with separate disclosure of the earnings or losses allocable to the non-controlling interest.

     In February 2010, the FASB amended the subsequent events standard, removing the requirement for an SEC filer to disclose the date it 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

     International Paper. In June 2010, the Partnership and International Paper Company (“IPC”) created a venture, BRP LLC, to own and manage mineral assets previously owned by IPC. Some of these assets are currently subject to leases, and certain other assets have not yet been developed but are available for future development by the venture. In exchange for a $42.5 million contribution, NRP became the controlling member with the right to designate two of the three managers of BRP. NRP has a 51% income interest plus a preferential cumulative annual distribution prior to profit sharing. In exchange for the contribution of the producing properties and the properties not currently producing, IPC received $42.5 million in cash, a minority voting interest and a 49% income interest after the preferential cumulative annual distribution. The amount of the preference is fixed throughout the life of the venture but can be reduced by a portion of the proceeds received from sales of producing properties included in the initial acquisition. Identified tangible assets included in the transaction are oil and gas, coal, and aggregate reserves, as well the rights to coal bed methane, geothermal, CO₂ sequestration, water rights, precious metals, industrial minerals and base metals. Certain properties, including oil and gas, coal and aggregates, as well as land leased for cell towers, are currently under lease and generating revenues.

     The transaction was accounted for as a business combination and, at September 30, 2010, the assets and liabilities of the venture are included in the consolidated balance sheet. Operations of the venture are included from June 1, 2010, the effective date of acquisition. The venture operating agreement provides that net income of the venture only be allocated to the non-controlling interests after the preferential cumulative annual distribution. As earnings for the period ended September 30, 2010 were less than the preference amount, no earnings are allocated to the non-controlling interest. The identification of all tangible and intangible assets acquired as well as the valuation process required for the allocation of the purchase price to those assets is not complete. Pending the final allocation of individual assets, all acquired assets of approximately $49.9 million are included in coal and other mineral rights in the accompanying Consolidated Balance Sheet.

     As the venture was formed for purposes of this transaction, there are no prior period operating results. Transaction expenses related to the acquisition were $2.2 million as of September 30, 2010 and are included in general and administrative expenses in the accompanying Consolidated Statements of Income.

     Rockmart Slate. In June 2010, the Partnership acquired approximately 100 acres of mineral and surface rights related to slate reserves in Rockmart, Georgia from a local operator for a purchase price of $6.7 million.

     Sierra Silica. In April 2010, the Partnership acquired the rights to silica reserves on approximately 1,000 acres of property in Northern California for $17.0 million.

     North American Limestone. In April 2010, the Partnership signed an agreement to build and own a fine grind processing facility for high calcium carbonate limestone located in Putnam County, Indiana. The Partnership will lease the facility to a local operator. The total cost for the facility is not to exceed $6.5 million. As of September 30, 2010 the Partnership had incurred approximately $5.6 million of costs associated with the construction of the facility.

     Northgate-Thayer. In March 2010, the Partnership acquired approximately 100 acres of mineral and surface rights related to dolomite limestone reserves in White County, Indiana from a local operator for a purchase price of $7.5 million.

8

     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 several separate transactions for a total purchase price of $255 million. As of September 30, 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.

     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.

     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:

	September 30,			December 31,
	2010			2009
	(In thousands)
	(Unaudited)
Plant construction in-process	$	5,588		$	—
Plant and equipment at cost		81,866			81,866
Less accumulated depreciation		(23,753	)		(17,515	)
Net book value	$	63,701		$	64,351

	Nine months ended
	September 30,
	2010		2009
	(In thousands)
	(Unaudited)
Total depreciation expense on plant and equipment	$	6,238	$	6,128

9

5. Coal and Other Mineral Rights

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

	September 30,			December 31,
	2010			2009
	(In thousands)
	(Unaudited)
Coal and other mineral rights	$	1,579,148		$	1,460,984
Less accumulated depletion and amortization		(337,434	)		(309,149	)
Net book value	$	1,241,714		$	1,151,835

	Nine months ended
	September 30,
	2010		2009
	(In thousands)
	(Unaudited)
Total depletion and amortization expense on coal and other mineral rights	$	28,285	$	39,521

     Coal and other mineral rights includes $13.2 million for additional mineral rights being contributed by International Paper Company resulting from the formation of a venture with the Partnership during the second quarter of 2010. These mineral rights are being contributed to the Partnership over the remainder of 2010 at no additional cost to the Partnership.

     Depletion expense for 2009 included a one-time expense of $8.2 million for a terminated lease due to a mine closure.

6. Intangible Assets

     In 2010, the Partnership identified $5.7 million of an above market contract relating to the Sierra Silica acquisition. In 2009, the Partnership identified $65.1 million of above market contracts, primarily relating to the Gatling Ohio and Macoupin acquisitions. Amounts recorded as intangible assets along with the balances and accumulated amortization at September 30, 2010 and December 31, 2009 are reflected in the table below:

	September 30,			December 31,
	2010			2009
	(In thousands)
	(Unaudited)
Above market contracts	$	178,427		$	172,706
Less accumulated amortization		(17,676	)		(8,152	)
Net book value	$	160,751		$	164,554

	Nine months ended
	September 30,
	2010		2009
	(In thousands)
	(Unaudited)
Total amortization expense on intangible assets	$	9,524	$	2,376

10

     As of April 1, 2010, the Partnership adjusted the amortization expense to be based upon the greater of the production and sales of reserves and the number of tons of coal transported using the transportation infrastructure or straight line over the remaining useful life. The estimates of future expense for the periods indicated below reflect this adjustment and are based on current mining plans, which are subject to revision in future periods.

           Estimated amortization expense:

	(In thousands)
	(Unaudited)
Remainder of 2010	$	3,839
For year ended December 31, 2011		15,945
For year ended December 31, 2012		15,945
For year ended December 31, 2013		15,945
For year ended December 31, 2014		15,945

7. Long-Term Debt

     Long-term debt consists of the following:

	September 30,			December 31,
	2010			2009
	(In thousands)
	(Unaudited)
$300 million floating rate revolving credit facility, due March 2012	$	39,000		$	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		37,650			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		76,923			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		36,900			40,200
5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, 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		637,588			658,822
Less — current portion of long term debt		(31,518	)		(32,235	)
Long-term debt	$	606,070		$	626,587

     Principal payments due in:

	Senior Notes		Credit Facility		Total
			(In thousands)
			(Unaudited)
Remainder of 2010	$	—	$	—	$	—
2011		31,518		—		31,518
2012		30,801		39,000		69,801
2013		87,230		—		87,230
2014		56,175		—		56,175
Thereafter		392,864		—		392,864
	$	598,588	$	39,000	$	637,588

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     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.

     The 8.38% and 8.92% 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 principal payments of $32.2 million on its senior notes during the nine months ended September 30, 2010.

     The Partnership has a $300 million revolving credit facility, and at September 30, 2010, $261 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, 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 or comparable terms.

     The Partnership had $39.0 million and $28.0 million outstanding on its revolving credit facility at September 30, 2010 and December 31, 2009, respectively. The weighted average interest rate at September 30, 2010 and December 31, 2009 was 1.41% 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 September 30, 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.

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• 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 $606.7 million and $627.5 million at September 30, 2010 and December 31, 2009, respectively, for the senior notes. The carrying value of the Partnership’s senior notes was $598.6 million and $630.8 million at September 30, 2010 and December 31, 2009, respectively. 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. 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 are as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
			(In thousands)
			(Unaudited)
Reimbursement for services	$	1,823	$	1,678	$	5,403	$	5,107

     The Partnership leases substantially all of two floors of an office building in Huntington, West Virginia from Western Pocahontas Properties and pays $0.5 million in lease payments each year through December 31, 2018.

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, as well as 21,017,441 common units. At September 30, 2010, the Partnership had accounts receivable totaling $7.3 million from Cline affiliates. Revenues from the Cline affiliates are as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In thousands)
	(Unaudited)
Coal royalty revenues	$	9,873	$	5,499	$	22,655	$	16,049
Coal processing fees		344		—		785		—
Transportation fees		4,271		2,758		10,671		7,991
Minimums recognized as revenue		3,100		—		9,300		—
Override revenue		718		834		1,437		1,604
	$	18,306	$	9,091	$	44,848	$	25,644

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     As of September 30, 2010, the Partnership had received $42.0 million in minimum royalty payments that have not been recouped by Cline affiliates, of which $17.8 million was received in the current year.

     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. Revenues from Taggart are as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In thousands)
	(Unaudited)
Coal processing revenue	$	1,666	$	1,017	$	4,014	$	2,910

     At September 30, 2010, the Partnership had accounts receivable totaling $0.4 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. Revenues from Kopper-Glo are as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In thousands)
	(Unaudited)
Coal royalty revenues	$	363	$	392	$	1,195	$	1,223

     The Partnership also had accounts receivable totaling $0.1 million from Kopper-Glo at September 30, 2010.

10. 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 September 30, 2010. The Partnership is not associated with any environmental contamination that may require remediation costs.

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Acquisition

     In conjunction with a definitive agreement, as of September 30, 2010, 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. See Footnote 14 — Subsequent Events, for further information regarding an additional acquisition of reserves after September 30, 2010.

11. Major Lessee

     Revenues from lessees that exceeded ten percent of total revenues for the periods as presented below:

	Three Months Ended										Nine Months Ended
	September 30,										September 30,
	2010					2009					2010					2009
								(Dollars in thousands)
								(Unaudited)
	Revenues		Percent			Revenues		Percent			Revenues		Percent			Revenues		Percent
The Cline Group	$	18,306		23	%	$	9,091		14	%	$	44,848		20	%	$	25,644		13	%
Alpha Natural Resources	$	7,256		9	%	$	6,184		10	%	$	20,859		9	%	$	18,329		10	%

12. 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 nine months of 2010 are as follows:

Outstanding grants at January 1, 2010	653,598
Grants during the year	236,548
Grants vested and paid during the year	(133,782	)
Forfeitures during the year	(2,496	)
Outstanding grants at September 30, 2010	753,868

     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 0.19% to 0.68% and 29.96% to 53.76%, respectively at September 30, 2010. The Partnership’s historical distribution rate of 6.74% and historical forfeiture rate of 3.38% were used in the calculation at September 30, 2010. The Partnership recorded expenses related to its plan to be reimbursed to its general partner of $3.1 million and $0.3 million and $5.4 million and $4.8 million for the three and nine month periods ended September 30, 2010 and 2009, respectively. In connection with the Long-Term Incentive Plan, payments are typically made during the first half of the year. Payments of $3.2 million and $2.9 million were paid during the nine month periods ended September 30, 2010 and 2009, respectively.

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     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 September 30, 2010, was $11.8 million.

13. Equity Transactions, including Distributions

     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 received net proceeds of approximately $112.5 million from this offering, including the general partner’s proportionate capital contribution.

     On August 13, 2010, the Partnership paid a quarterly distribution $0.54 per unit to all holders of common units.

     On September 20, 2010, the Partnership eliminated all of the incentive distribution rights (IDRs) held by its general partner and affiliates of the general partner. As consideration for the elimination of the IDRs, the Partnership issued 32 million common units to the holders of the IDRs. There are now 106,027,836 common units outstanding and the general partner will retain its 2% interest in the Partnership.

14. Subsequent Events

     The following represents material events that have occurred subsequent to September 30, 2010 through the time of the Partnership’s filing with the Securities and Exchange Commission:

     Acquisitions

     On October 4, 2010, the Partnership closed the third acquisition of reserves from Colt, LLC, an affiliate of the Cline Group. The Partnership paid $55.0 million, funded through its credit facility, and acquired approximately 27.4 million tons of reserves.

     Distributions

     On October 22, 2010, the Partnership declared a distribution of $0.54 per unit to be paid on November 12, 2010 to unitholders of record on November 5, 2010.

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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 mineral properties in the United States. We own coal reserves in the three major U.S. coal-producing regions: Appalachia, the Illinois Basin and the Western United States, as well as significant lignite reserves in the Gulf Coast region. As of December 31, 2009, we owned or controlled approximately 2.1 billion tons of proven and probable coal reserves. As of December 31, 2009, we also owned approximately 130 million tons of aggregate reserves in Washington, Texas, Arizona and West Virginia, and in 2010 have acquired additional aggregate reserves in several states across the country. 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 generally 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 specified periods of time, which vary by lease, if sufficient royalties are generated from production in 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 25% of our revenues for the nine months ended September 30, 2010 from other sources, as compared to 20% for the same period of 2009. The most significant increase in these other sources of revenue occurred due to a substantial minimum royalty paid by Cline with respect to the Colt reserves that was non-recoupable and therefore recognized as revenue. In addition, we received some oil and gas revenues in the second and third quarters related to our BRP joint venture with International Paper. Other sources of revenue include: coal processing and transportation fees; overriding royalties; wheelage payments; rentals; property tax revenue; and timber.

     Elimination of Incentive Distribution Rights

     On September 20, 2010, we eliminated all of the incentive distribution rights (IDRs) held by our general partner and affiliates of the general partner. As consideration for the elimination of the IDRs, we issued 32 million common units to the holders of the IDRs. There are now 106,027,836 common units outstanding and the general partner will retain its 2% interest in the partnership. Prior to the transaction, the IDRs received approximately 24% of the quarterly distribution and 48% of any increase in the distribution. Through the elimination of the IDRs, our limited partner unitholders will benefit from our improved cost of capital through:

• our enhanced competitive position in the acquisition markets; and

• increased returns to limited partner unitholders from acquisition and growth projects.

     While the transaction is expected to be dilutive to cash available for distribution in the near-term, we believe that the transaction is in the long-term best interest of the partnership.

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     Our Current Liquidity Position

     As of September 30, 2010, we had $261 million in available capacity under our existing credit facility, which does not mature until March 2012, as well as approximately $72 million in cash. On October 4, 2010, we acquired another 27.4 million tons of reserves from Colt, LLC in Illinois for $55 million, which we funded through our credit facility.

     Pursuant to the purchase and sale agreement signed in the Colt acquisition, we expect to fund an additional $150 million over the next two years, of which approximately $70 million is anticipated to be funded in the first quarter of 2011 as the operator achieves various development milestones. We anticipate funding the Colt acquisition, as well as any other acquisitions that we consummate, 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 addition, other than a $35 million senior note that matures in 2013 and our revolving credit facility, we amortize our long-term debt. Although our annual principal payments will increase significantly beginning in 2013, we have no need to access the capital markets to pay off or refinance any debt obligations other than the one note, and our existing debt will be reduced as the minerals are depleted.

     Current Results

     For the nine months ended September 30, 2010, our lessees produced 37.3 million tons of coal and aggregates, generating $168.0 million in royalty revenues from our properties, and our total revenues were $223.9 million. Prices for both steam and metallurgical coal remained at higher levels than we had forecasted for the third quarter of 2010. We expect the prices for metallurgical coal to remain constant over the remainder of 2010, and because approximately 39% of our coal royalty revenues and 33% of the related production during the first nine months of 2010 were from metallurgical coal, we expect to continue to benefit as the global economy recovers and the demand for steel remains high.

     Even though coal royalty revenues from our Appalachian properties represented 62% of our total revenues in the first nine months 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 and other mineral acquisitions. Our expansion into Illinois through our partnership with Cline is through the acquisition of reserves by NRP and the development of greenfield mines by Cline. These projects take several years to reach full production, and it is difficult for us to forecast the timing of completion of the projects. To protect against this risk, we are receiving significant minimum royalties with respect to each of the projects. Although minimums provide cash to NRP that can be distributed to our limited partners, the minimums are generally not revenue to NRP until recouped through production or at the end of the recoupment period. Thus, to the extent that the development takes longer than anticipated to begin production, it will impact the revenues that we receive in the future

     Operations at the Gatling, West Virginia mine had not been restarted as of the end of the third quarter. Cline, which operates the mine, has communicated to us that it does not intend to close the mine, is continuing to maintain the mine and is currently in discussions with AEP regarding modifications to its existing coal sales contract, as well as other potential purchasers of the coal. In prior periods, efforts by Cline to renegotiate the price for coal from this mine were successful. Cline continues to make its quarterly minimum payments with respect to this mine and has also communicated that it will do so until the mine is operational. If the mine does not become operational in future periods or discussions with potential purchasers of the coal are not successful, we may determine that some of the assets associated with the mine have suffered impairment. This decision and an associated impairment could have a material adverse impact on our earnings in the period in which any impairment is recognized, but it would not impact our cash flows from operations or our distributable cash flow.

     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-

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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 has led to even more scrutiny by MSHA of our lessees’ operations, as well as 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, including cap and trade legislation, that would regulate domestic carbon dioxide emissions, but no such bill has yet received sufficient Congressional support for passage into law. The purpose of the proposed legislation is to control and reduce emissions of greenhouse gases in the United States. Greenhouse gases are gases, including carbon dioxide and methane that some scientists have argued are contributing to warming of the Earth’s atmosphere and other climatic changes. Although it is not possible at this time to predict whether or when the Congress may act on climate change legislation, any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could have an adverse effect on demand for our coal.

     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. Several petitioners have challenged the EPA’s findings in the Washington D.C. Circuit Court of Appeals, and that litigation is ongoing.

     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.

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

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(Unaudited)
Net cash provided by operating activities	$	62,107		$	38,120		$	175,660		$	138,799
Less scheduled principal payments		(7,692	)		(7,693	)		(32,234	)		(17,235	)
Less reserves for future principal payments		(7,880	)		(8,059	)		(23,819	)		(24,177	)
Add reserves used for scheduled principal payments		7,692			7,693			32,234			17,235
Distributable cash flow	$	54,227		$	30,061		$	151,841		$	114,622

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.

     International Paper. In June 2010, we and International Paper Company created a venture, BRP LLC, to own and manage mineral assets previously owned by International Paper. Some of these assets are currently subject to leases, and certain other assets have not yet been developed but are available for future development by the venture. In exchange for a $42.5 million contribution we became the managing and controlling member with the right to designate two of the three managers of BRP. NRP has a 51% income interest plus a preferential cumulative annual distribution prior to profit sharing. In exchange for the contribution of the producing properties and the properties not currently producing, International Paper received $42.5 million in cash from BRP, a minority voting interest and a 49% income interest after the preferential cumulative annual distribution. The amount of the preference is fixed throughout the life of the venture but can be reduced by a portion of the proceeds received from sales of producing properties included in the initial acquisition. Identified tangible assets in the transaction include oil and gas, coal and aggregate reserves, as well the rights to coal bed methane, geothermal, CO₂ sequestration, water rights, precious metals, industrial minerals and base metals. Certain properties, including oil and gas, coal and aggregates, as well as land leased for cell towers, are currently under lease and generating revenues.

     Rockmart Slate. In June 2010, we acquired approximately 100 acres of mineral and surface rights related to slate reserves in Rockmart, Georgia from a local operator for a purchase price of $6.7 million.

     Sierra Silica. In April 2010, we acquired the rights to silica reserves 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 to build and own for the construction of a fine grind processing facility for high calcium carbonate limestone located in Putnam County, Indiana. We will lease the facility to a local operator. The total cost for the facility is not to exceed $6.5 million. As of our filing date, we have funded approximately $5.6 million of the acquisition.

     Northgate-Thayer. In March 2010, we acquired approximately 100 acres of mineral and surface rights related to dolomite limestone reserves in White County, Indiana from a local operator for a purchase price of $7.5 million.

     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 several separate transactions for a total purchase price of $255 million. In October 2010, we closed a transaction for $55.0 million and acquired approximately 27.4 million tons of reserves. As of our filing date, we had acquired approximately 50.2 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.

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     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.

     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.

     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 we 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				Increase			Percentage
	September 30,				(Decrease)			Change
	2010		2009
	(In thousands, except percent and per ton data)
	(Unaudited)
Coal:
Coal royalty revenues
Appalachia
Northern	$	4,883	$	3,998	$	885			22	%
Central		38,418		33,688		4,730			14	%
Southern		5,530		4,849		681			14	%
Total Appalachia		48,831		42,535		6,296			15	%
Illinois Basin		9,278		5,413		3,865			71	%
Northern Powder River Basin		2,033		1,359		674			50	%
Total	$	60,142	$	49,307	$	10,835			22	%
Production (tons)
Appalachia
Northern		1,177		1,238		(61	)		(5	%)
Central		7,051		6,984		67			1	%
Southern		763		799		(36	)		(5	%)
Total Appalachia		8,991		9,021		(30	)		—
Illinois Basin		2,389		1,723		666			39	%
Northern Powder River Basin		987		539		448			83	%
Total		12,367		11,283		1,084			10	%
Average gross royalty per ton
Appalachia
Northern	$	4.15	$	3.23	$	0.92			28	%
Central		5.45		4.82		0.63			13	%
Southern		7.25		6.07		1.18			19	%
Total Appalachia		5.43		4.72		0.71			15	%
Illinois Basin		3.88		3.14		0.74			24	%
Northern Powder River Basin		2.06		2.52		(0.46	)		(18	%)
Combined average gross royalty per ton		4.86		4.37		0.49			11	%
Aggregates:
Royalty revenue	$	1,606	$	1,400	$	206			15	%
Aggregate royalty bonus	$	—	$	300	$	(300	)		(100	%)
Production		973		1,148		(175	)		(15	%)
Average base royalty per ton	$	1.65	$	1.22	$	0.43			35	%

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     Coal Royalty Revenues and Production. Coal royalty revenues comprised approximately 74% and 77% of our total revenue for each of the three month periods ended September 30, 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 higher prices being realized by our lessees, improved royalty rates on one of the larger leases, and a higher proportion of the production being sold as metallurgical coal by our lessees in the Central and Southern Appalachian regions, coal royalty revenues increased in the three month period ended September 30, 2010 compared to the same period of 2009. Production in each of the Appalachian regions was nearly constant. Increased production at some mines and other mines moving onto our property offset production curtailments related to a fire at a preparation plant, the temporary idling of a longwall mine, and other mines moving onto adjacent property.

     Illinois Basin. Production increased due to improved shipments from the Williamson property and our Macoupin property beginning to ship some of its production. The production increase and higher average revenue per ton combined to generate an increase in coal royalty revenue.

     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, partially offset by a sales price adjustment that occurred in 2009.

     Aggregates Royalty Revenues and Production. Aggregate revenues include royalties from current production as well as an estimate of a royalty bonus from one lessee that is determined annually based on the profitability of the lessee. Quarter over quarter, production declined on our DuPont, Washington property due to market conditions, offset somewhat by production on some of our recently acquired properties. While royalty revenue increased only slightly, the average royalty per ton increased 32% due to higher royalty rates being realized on our newly acquired properties.

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	Nine Months Ended					Increase			Percentage
	September 30,					(Decrease)			Change
	2010			2009
	(In thousands, except percent and per ton data)
	(Unaudited)
Coal:
Coal royalty revenues
Appalachia
Northern	$	14,224		$	9,931	$	4,293			43	%
Central		108,751			101,874		6,877			7	%
Southern		15,805			14,755		1,050			7	%
Total Appalachia		138,780			126,560		12,220			10	%
Illinois Basin		20,307			16,234		4,073			25	%
Northern Powder River Basin		6,048			5,500		548			10	%
Total		165,135		$	148,294	$	16,841			11	%
Production (tons)
Appalachia
Northern		3,676			3,304		372			11	%
Central		20,417			21,962		(1,545	)		(7	%)
Southern		2,297			2,438		(141	)		(6	%)
Total Appalachia		26,390			27,704		(1,314	)		(5	%)
Illinois Basin		5,287			5,005		282			6	%
Northern Powder River Basin		3,259			2,840		419			15	%
Total		34,936			35,549		(613	)		(2	%)
Average gross royalty per ton
Appalachia
Northern	$	3.87		$	3.01	$	0.86			29	%
Central		5.33			4.64		0.69			15	%
Southern		6.88			6.05		0.83			14	%
Total Appalachia		5.26			4.57		0.69			15	%
Illinois Basin		3.84			3.24		0.60			19	%
Northern Powder River Basin		1.86			1.94		(0.08	)		(4	%)
Combined average gross royalty per ton		4.73			4.17		0.56			13	%
Aggregates:
Royalty revenue	$	3,486		$	3,377	$	109			3	%
Aggregate royalty bonus	$	(639	)	$	1,320	$	(1,959	)		(148	%)
Production		2,356			2,629		(273	)		(10	%)
Average base royalty per ton	$	1.48		$	1.28	$	0.20			16	%

     Coal Royalty Revenues and Production. Coal royalty revenues comprised approximately 74% and 78% of our total revenue for each of the nine month periods ended September 30, 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 higher prices being realized by our lessees, improved royalty rates on one of the larger leases and a higher proportion of the production being sold as metallurgical coal by our lessees in all of the Appalachian regions, coal royalty revenues increased in the nine month period ended September 30, 2010 compared to the same period of 2009. The factors causing higher coal royalty revenue more than offset the lower production in the Central and Southern Appalachian regions. This lower production was due to a number of factors, including temporary idling of mines, production curtailments related to a fire at a preparation plant and some mines moving to adjacent properties.

     Illinois Basin. Production increased primarily due to the mine starting production on our Macoupin property. The production increase, combined with a higher royalty per ton being realized, resulted in an increase in coal royalty revenues.

     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.

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     Aggregates Royalty Revenues and Production. Aggregate revenues include royalties from current production as well as an estimate of a royalty bonus from one lessee that is determined annually based on the profitability of the lessee. Year over year, production declined on our DuPont, Washington property due to market conditions, offset somewhat by production on some of our recently acquired properties. While royalty revenue increased only slightly, the average royalty per ton increased 16% due to higher royalty rates being realized on our newly acquired properties. The royalty bonus reflects an adjustment to the estimated accrual based upon the actual bonus received in the second quarter related to 2009. The bonus accrual is based upon the lessee’s historical performance and the actual bonus paid with respect to 2009 was significantly less than prior years due to the downturn in the economy.

     Other Operating Results

     In addition to coal and aggregate royalty revenues, we generated approximately 25% of our nine months ended September 30, 2010 revenues from other sources, as compared to 20% for the same period of 2009. The most significant increase in these other sources of revenue occurred due to a substantial minimum royalty paid by Cline with respect to the Colt reserves that is non-recoupable and therefore recognized as revenue. In addition, we received an oil and gas lease bonus as well as oil and gas revenues related to our BRP joint venture with International Paper. Other sources of revenue include: coal processing and transportation fees; overriding royalties; wheelage payments; rentals; property tax revenue; and timber. Included in other income was a $1.9 million payment from the State of West Virginia for the granting of an easement on our surface property.

     Coal Processing and Transportation Revenues. We generated $2.3 million and $1.5 million in processing revenues for the quarters ended September 30, 2010 and 2009, respectively and $6.7 million and $5.8 million for the nine month periods ended September 30, 2010 and 2009, respectively. 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 $4.3 million and $3.0 million for the quarters ended September 30, 2010 and 2009 and $11.1 million and $8.6 million for the nine months ended September 30, 2010 and 2009, respectively.

     Operating costs and expenses. Included in total expenses are:

• Depreciation, depletion and amortization of $16.2 million and $13.0 million for the quarters ended September 30, 2010 and 2009, and $44.0 million and $48.0 million for the nine month periods ended September 30, 2010 and 2009, respectively. In the second quarter of 2009, we recorded a one-time expense of $8.2 million for a terminated lease due to a mine closure. Excluding this one-time expense, depletion increased approximately $4.2 million for the nine months ended September 30, 2010. This increase is primarily due to a refinement in the estimate on our contract amortization of approximately $2.9 million during the three months ended September 30, 2010 and $5.9 million for the nine months period ended September 30, 2010, partially offset by slightly lower production for the year to date period.

• General and administrative expenses were $8.8 million and $4.6 million for the quarters ended September 30, 2010 and 2009, and $22.1 million and $17.9 for the nine month periods ended September 30, 2010 and 2009, respectively. The increases in general and administrative expense is primarily due to accruals under our long-term incentive plan attributable to fluctuations in our unit price and $2.2 million of transaction costs associated with the business combination with International Paper Company.

     Interest Expense. Interest expense was higher for the first nine months of 2010 when compared to the first nine months of 2009 due to the issuance of senior notes in 2009 at higher interest rates.

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Liquidity and Capital Resources

Cash Flows and Capital Expenditures

     We satisfy our working capital requirements with cash generated from operations. We finance 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 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 nine months ended September 30, 2010 and 2009 was $175.7 million and $138.8 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 nine months ended September 30, 2010 and 2009 was $114.7 million and $116.1 million, respectively. 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 nine months ended September 30, 2010 was $71.4 million. During the first nine months of 2010, we had proceeds from loans of $85.0 million offset by repayment of debt of $106.2 million and retirements of $9.2 million in obligations related to the purchase of coal reserves and infrastructure. We received proceeds from the issuance of units of $110.4 million, paid fees associated with the elimination of the IDRs of $2.2 million and paid distributions of $151.4 million. During the same period for 2009, net cash used in financing activities was $51.7 million, which included proceeds from loans of $325.0 million, principal repayments of $168.2 million, retirement of obligations related to acquisitions of $63.0 million and $144.8 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 September 30, 2010 increased $29.3 million since December 31, 2009 to $96.3 million primarily as a result of minimums paid by the Cline Group related to their operations that have not been recouped through production. These minimums may reduce future cash flows when lessees recoup against production royalties.

Long-Term Debt

     At September 30, 2010, our debt consisted of:

• $39 million of our $300 million floating rate revolving credit facility, due March 2012;

• $35 million of 5.55% senior notes due 2013;

• $37.7 million of 4.91% senior notes due 2018;

• $150 million of 8.38% senior notes due 2019;

• $76.9 million of 5.05% senior notes due 2020;

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

• $36.9 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.

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     Credit Facility. We have a $300 million revolving credit facility, and as of our filing date we had approximately $206 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, 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 or comparable 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

• 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 in March 2019 and $50 million of 8.92% notes maturing in 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 Transactions

     In addition to our credit facility, we maintain 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 used the remaining cash for acquisitions.

     On September 20, 2010, we eliminated all of the incentive distribution rights (IDRs) held by our general partner and affiliates of the general partner. As consideration for the elimination of the IDRs, we issued 32 million common units to the holders of the IDRs. There are now 106,027,836 common units outstanding and the general partner will retain its 2% interest in NRP.

26

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 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, 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 are as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
			(In thousands)
			(Unaudited)
Reimbursement for services	$	1,823	$	1,678	$	5,403	$	5,107

     For additional information, please read “Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement” in our annual report filed on Form 10K/A for the year ended December 31, 2009.

     We lease substantially all of two floors of an office building in Huntington, West Virginia 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.

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, as well as 21,017,441 common units. At September 30, 2010, we had accounts receivable totaling $7.3 million from Cline affiliates. Revenues from Cline affiliates are as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
			(In thousands)
			(Unaudited)
Coal royalty revenues	$	9,873	$	5,499	$	22,655	$	16,049
Coal processing fees		344		—		785		—
Transportation fees		4,271		2,758		10,671		7,991
Minimums recognized as revenue		3,100		—		9,300		—
Override revenue		718		834		1,437		1,604
	$	18,306	$	9,091	$	44,848	$	25,644

     As of September 30, 2010, we have received $42.0 million in minimum royalty payments to date that have not been recouped by Cline affiliates of which $17.8 million was received in the current year.

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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. Revenues from Taggart are as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
			(In thousands)
			(Unaudited)
Coal processing revenue	$	1,666	$	1,017	$	4,014	$	2,910

     At September 30, 2010, we had accounts receivable totaling $0.4 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. Revenues from Kopper-Glo are as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
			(In thousands)
			(Unaudited)
Coal royalty revenue	$	363	$	392	$	1,195	$	1,223

     We also had accounts receivable totaling $0.1 million from Kopper-Glo at September 30, 2010.

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 September 30, 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.

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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. 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. As of our filing date, we had $94 million outstanding in variable interest rate debt.

29

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.

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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.

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Item 6. Exhibits

3.1	—	Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of September 20, 2010 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed September 21, 2010).
3.2	—	Fourth Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of September 20, 2010 (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K filed September 21, 2010).
10.1	—	Amendment No. 2 to Purchase and Sale Agreement, dated as of October 4, 2010, by and between WPP LLC and Colt, LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed October 5, 2010).
10.2	—	Contribution Agreement, dated as of September 20, 2010, by and among Natural Resource Partners L.P., NRP (GP) LP, Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and NRP Investment L.P. (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed September 21, 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.
99.1	—	Description of certain provisions of the Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P. (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed September 21, 2010)
101*	—	The following financial information from the quarterly report on Form 10-Q of Natural Resource Partners L.P. for the quarter ended September 30, 2010, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to Consolidated Financial Statements, tagged as blocks of text.

* Submitted herewith.

32

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: November 5, 2010

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

Date: November 5, 2010

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

Date: November 5, 2010

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

33

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

I, Corbin J. Robertson, Jr., certify that:

1)	I have reviewed this report on Form 10-Q of Natural Resource Partners L.P.
2)	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3)	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4)	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5) The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions);

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:
 

/s/ Corbin J. Robertson, Jr.  

Corbin J. Robertson, Jr. 

Chief Executive Officer 

Date: November 5, 2010

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

I, Dwight L. Dunlap, certify that:

1)	I have reviewed this report on Form 10-Q of Natural Resource Partners L.P.
2)	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3)	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4)	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5) The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions);

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:
 

/s/ Dwight L. Dunlap  

Dwight L. Dunlap 

Chief Financial Officer and Treasurer 

Date: November 5, 2010

EX-32.1

Exhibit 32.1

CERTIFICATION OF
CHIEF EXECUTIVE OFFICER
OF GP NATURAL RESOURCE PARTNERS LLC
PURSUANT TO 18 U.S.C. § 1350

     In connection with the accompanying report on Form 10-Q for the quarter ended September 30, 2010 filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Corbin J. Robertson, Jr., Chief Executive Officer and Chairman of the Board of GP Natural Resource Partners LLC, the general partner of the general partner of Natural Resource Partners L.P. (the “Company”), hereby certify, to my knowledge, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Corbin J. Robertson, Jr.
Name:	Corbin J. Robertson, Jr.
Date:  November 5, 2010

EX-32.2

Exhibit 32.2

CERTIFICATION OF
CHIEF FINANCIAL OFFICER
OF GP NATURAL RESOURCE PARTNERS LLC
PURSUANT TO 18 U.S.C. § 1350

     In connection with the accompanying report on Form 10-Q for the quarter ended September 30, 2010 filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Dwight L. Dunlap, Chief Financial Officer and Treasurer of GP Natural Resource Partners LLC, the general partner of the general partner of Natural Resource Partners L.P. (the “Company”), hereby certify, to my knowledge, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Dwight L. Dunlap
Name:	Dwight L. Dunlap
Date:  November 5, 2010