NRP 10-Q Quarterly Report June 30, 2010

NATURAL RESOURCE PARTNERS LP

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10-Q 1 h74502e10vq.htm FORM 10-Q e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2010


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		35-2164875
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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	o Smaller Reporting Company
		(Do not check if a 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 August 6, 2010 there were 74,027,836 Common Units outstanding.

TABLE OF CONTENTS


	Page
PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009		4
Consolidated Statements of Income For the Three and Six Months Ended June 30, 2010 and 2009		5
Consolidated Statements of Cash Flows For the Six Months Ended June 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		24
Related Party Transactions		26
Environmental		27

ITEM 3. Quantitative And Qualitative Disclosures About Market Risk		28

ITEM 4. Controls And Procedures		29

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings		30

ITEM 1A. Risk Factors		30

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds		30

ITEM 3. Defaults Upon Senior Securities		30

ITEM 4. (Removed and Reserved)		30

ITEM 5. Other Information		30

ITEM 6. Exhibits		31

Signatures		32

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.

Part I. Financial Information


Item 1.		Financial Statements

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS
(In thousands)


	June 30,			December 31,
	2010			2009
	(Unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	78,410		$	82,634
Accounts receivable, net of allowance for doubtful accounts		29,144			27,141
Accounts receivable — affiliates		7,424			4,342
Other		498			930

Total current assets		115,476			115,047
Land		24,343			24,343
Plant and equipment, net		62,295			64,351
Coal and other mineral rights, net		1,251,551			1,151,835
Intangible assets, net		165,072			164,554
Loan financing costs, net		2,663			2,891
Other assets, net		882			569

Total assets	$	1,622,282		$	1,523,590


LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable and accrued liabilities	$	944		$	914
Accounts payable — affiliates		247			179
Obligation related to acquisitions		6,200			2,969
Current portion of long-term debt		31,518			32,235
Accrued incentive plan expenses — current portion		4,209			4,627
Property, franchise and other taxes payable		5,661			6,164
Accrued interest		9,978			10,300

Total current liabilities		58,757			57,388
Deferred revenue		87,659			67,018
Accrued incentive plan expenses		6,449			7,371
Long-term debt		609,762			626,587
Partners’ capital:
Common units outstanding: (74,027,836 in 2010, 69,451,136 in 2009)		825,160			747,437
General partner’s interest		14,728			13,409
Holders of incentive distribution rights		12,983			4,977
Non-controlling interest		7,355			—
Accumulated other comprehensive loss		(571	)		(597	)

Total partners’ capital		859,655			765,226

Total liabilities and partners’ capital	$	1,622,282		$	1,523,590

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

NATURAL RESOURCE PARTNERS L.P.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(Unaudited)
Revenues:
Coal royalties	$	57,832		$	46,380		$	104,993		$	98,987
Aggregate royalties		350			1,347			1,241			2,997
Coal processing fees		2,693			2,400			4,337			4,300
Transportation fees		4,043			3,489			6,818			5,585
Oil and gas royalties		2,087			953			3,186			2,446
Property taxes		2,782			2,514			5,433			5,725
Minimums recognized as revenue		3,418			67			6,792			290
Override royalties		3,157			1,336			6,124			3,884
Other		3,225			1,001			4,182			2,006

Total revenues		79,587			59,487			143,106			126,220
Operating costs and expenses:
Depreciation, depletion and amortization		16,485			21,996			27,853			35,074
General and administrative		6,794			5,834			13,342			13,340
Property, franchise and other taxes		3,498			3,151			7,232			7,126
Transportation costs		557			473			822			741
Coal royalty and override payments		301			372			993			861

Total operating costs and expenses		27,635			31,826			50,242			57,142

Income from operations		51,952			27,661			92,864			69,078
Other income (expense):
Interest expense		(10,346	)		(10,675	)		(21,075	)		(18,754	)
Interest income		4			96			12			178

Income before non-controlling interest	$	41,610		$	17,082		$	71,801			50,502
Non-controlling interest		—			—			—			—

Net income	$	41,610		$	17,082		$	71,801		$	50,502

Net income attributable to:
General partner	$	573		$	98		$	917		$	539

Holders of incentive distribution rights	$	12,983		$	12,180		$	25,966		$	23,561

Limited partners	$	28,054		$	4,804		$	44,918		$	26,402


Basic and diluted net income per limited partner unit	$	0.38		$	0.07		$	0.63		$	0.40


Weighted average number of units outstanding		74,028			66,946			71,752			65,924

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)


	Six Months Ended
	June 30,
	2010			2009
	(Unaudited)
Cash flows from operating activities:
Net income	$	71,801		$	50,502
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		27,853			35,074
Non-cash interest charge, net		291			1,010
Change in operating assets and liabilities:
Accounts receivable		(5,085	)		1,865
Other assets		119			267
Accounts payable and accrued liabilities		98			(247	)
Accrued interest		(322	)		3,909
Deferred revenue		20,641			8,310
Accrued incentive plan expenses		(1,340	)		1,568
Property, franchise and other taxes payable		(503	)		(1,579	)

Net cash provided by operating activities		113,553			100,679

Cash flows from investing activities:
Acquisition of land, coal and other mineral rights		(110,411	)		(95,641	)
Acquisition or construction of plant and equipment		(2,102	)		(1,157	)

Net cash used in investing activities		(112,513	)		(96,798	)

Cash flows from financing activities:
Proceeds from loans		81,000			303,000
Proceeds from issuance of units		110,436			—
Capital contribution by general partner		2,350			—
Deferred financing costs		—			(661	)
Repayment of loans		(98,542	)		(160,542	)
Retirement of obligation related to acquisitions		(2,969	)		(60,000	)
Costs associated with issuance of units		(152	)		(21	)
Distributions to partners		(97,387	)		(94,090	)

Net cash used in financing activities		(5,264	)		(12,314	)

Net decrease in cash and cash equivalents		(4,224	)		(8,433	)
Cash and cash equivalents at beginning of period		82,634			89,928

Cash and cash equivalents at end of period	$	78,410		$	81,495


Supplemental cash flow information:
Cash paid during the period for interest	$	21,070		$	13,760

Non-cash investing activities:
Mineral rights to be received	$	13,249		$	—
Liability assumed in acquisitions		—			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			59,220

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

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Organization

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and six months ended June 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 significant 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 wholly owned subsidiary, NRP (Operating) LLC, (“NRP Operating”) and BRP LLC, a newly formed venture, 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 of sold, and in some cases, minimum payments.

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 the change more accurately reflects the future benefits of the assets. For the three months ended June 30, 2010, the change in amortization resulted in an increase in amortization expense of $2.8 million, or approximately $0.04 per unit. Although the Partnership anticipates this change 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 standard update in preparing its disclosures, and the adoption of the standard did not have a material effect on such disclosures.

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

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

3. Recent Acquisitions

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 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, IPC received $42.5 million in cash, a minority — protective — 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 assets subject to 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, CO ₂ 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 June 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 June 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 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 $1.2 million as of June 30, 2010 and are included in operating costs in the accompanying Consolidated Statement 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. As of June 30, 2010, the Partnership had funded $5.0 million of the acquisition.

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 June 30, 2010 the Partnership had funded approximately $2.0 million.

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. As of June 30, 2010

the Partnership had funded $3.0 million of the acquisition.

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

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

Colt. In September 2009, the Partnership signed a definitive agreement to acquire approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt LLC, an affiliate of the Cline Group, through eight separate transactions for a total purchase price of $255 million. In January 2010, the Partnership closed the second transaction for $40.0 million and acquired approximately 19.5 million tons of reserves. As of June 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’s construction.

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

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

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

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

4. Plant and Equipment

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


	June 30,			December 31,
	2010			2009
	(In thousands)
	(Unaudited)
Plant construction in-process	$	2,102		$	—
Plant and equipment at cost		81,867			81,866
Less accumulated depreciation		(21,674	)		(17,515	)


Net book value	$	62,295		$	64,351


	Six months ended
	June 30,
	2010		2009
	(In thousands)
	(Unaudited)
Total depreciation expense on plant and equipment	$	4,159	$	4,085

5. Coal and Other Mineral Rights

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


	June 30,			December 31,
	2010			2009
	(In thousands)
	(Unaudited)
Coal and other mineral rights	$	1,579,189		$	1,460,984
Less accumulated depletion and amortization		(327,638	)		(309,149	)


Net book value	$	1,251,551		$	1,151,835


	Six months ended
	June 30,
	2010		2009
	(In thousands)
	(Unaudited)
Total depletion and amortization expense on coal and other mineral rights	$	18,489	$	29,443

Coal and other mineral rights includes $13.2 million for additional mineral rights to be contributed by International Paper Company resulting from the formation of a venture with the Partnership during the second quarter of 2010. These mineral rights will be 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 June 30, 2010 and December 31, 2009 are reflected in the table below:


	June 30,			December 31,
	2010			2009
	(In thousands)
	(Unaudited)
Above market contracts	$	178,427		$	172,706
Less accumulated amortization		(13,355	)		(8,152	)


Net book value	$	165,072		$	164,554


	Six months ended
	June 30,
	2010		2009
	(In thousands)
	(Unaudited)
Total amortization expense on intangible assets	$	5,203	$	1,546

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)
Remainder of 2010	$	7,972
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:


	June 30,			December 31,
	2010			2009
	(In thousands)
	(Unaudited)
$300 million floating rate revolving credit facility, due March 2012	$	35,000		$	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		84,615			84,615
5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021		2,115			2,307
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023		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		641,280			658,822
Less — current portion of long term debt		(31,518	)		(32,235	)

Long-term debt	$	609,762		$	626,587

Principal payments due in:


Remainder of 2010	$	7,692
2011		31,518
2012		65,801
2013		87,230
2014		56,175
Thereafter		392,864

	$	641,280

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 $24.5 million on its senior notes during the six months ended June 30, 2010.

The Partnership has a $300 million revolving credit facility, and at June 30, 2010, $265 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 $35.0 million and $28.0 million outstanding on its revolving credit facility at June 30, 2010 and December 31, 2009, respectively. The weighted average interest rate at June 30, 2010 and December 31, 2009 was 1.39% 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 June 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.

	•		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 $616.0 million and $627.5 million at June 30, 2010 and December 31, 2009, respectively, for the senior notes. The carrying value of the Partnership’s senior notes was $606.3 million and $630.8 million at June 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				Six Months Ended
	June 30,				June 30,
	(In thousands)
	(Unaudited)
	2010		2009		2010		2009
Reimbursement for services	$	1,789	$	1,703	$	3,580	$	3,429

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 and in the incentive distribution rights of the Partnership, as well as 13,510,072 common units. At June 30, 2010, the Partnership had accounts receivable totaling $6.6 million from Cline affiliates. Revenues from the Cline affiliates are as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	(In thousands)
	(Unaudited)
	2010		2009		2010		2009
Coal royalty revenues	$	7,475	$	6,592	$	12,782	$	10,550
Coal processing fees		313		—		441		—
Transportation fees		3,992		3,342		6,400		5,233
Minimums recognized as revenue		3,100		—		6,200		—
Override revenue		277		374		719		770

	$	15,157	$	10,308	$	26,542	$	16,553

In addition, the Partnership has also received $36.2 million in advance minimum royalty payments to date that have not been recouped by Cline affiliates.

Quintana Capital Group GP, Ltd.

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

A fund controlled by Quintana Capital owns a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. The Partnership currently has a memorandum of understanding with Taggart Global pursuant to which the two companies have agreed to jointly pursue the development of coal handling and preparation plants. The Partnership owns and leases the plants to Taggart Global, which designs, builds and operates the plants. The lease payments are based on the sales price for the coal that is processed through the facilities. To date, the Partnership has acquired four facilities under this agreement with Taggart with a total cost of $46.6 million. Revenues from Taggart are as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	(In thousands)
	(Unaudited)
	2010		2009		2010		2009
Coal processing revenue	$	1,811	$	1,309	$	2,534	$	2,003

At June 30, 2010, the Partnership had accounts receivable totaling $0.8 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				Six Months Ended
	June 30,				June 30,
	(In thousands)
	(Unaudited)
	2010		2009		2010		2009
Coal royalty revenues	$	379	$	348	$	832	$	832

The Partnership also had accounts receivable totaling $0.1 million at June 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 June 30, 2010. The Partnership is not associated with any environmental contamination that may require remediation costs.

Acquisition

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

11. Major Lessee

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


	Three Months Ended										Six Months Ended
	June 30,										June 30,
	2010					2009					2010					2009
	(Dollars in thousands)
	(Unaudited)
	Revenues		Percent			Revenues		Percent			Revenues		Percent			Revenues		Percent
The Cline Group	$	15,157		19	%	$	10,308		17	%	$	26,542		19	%	$	16,553		13	%

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 six months of 2010 are as follows:


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

Outstanding grants at the end of the period	718,532

Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The liability fluctuates with the market value of the Partnership units and because of changes in estimated fair value determined each quarter using the Black-Scholes option valuation model. Risk free interest rates and volatility are reset at each calculation based on current rates corresponding to the remaining vesting term for each outstanding grant and ranged from 0.34% to 1.37% and 34.63% to 57.84%, respectively at June 30, 2010. The Partnership’s historical distribution rate of 6.67% was used in the calculation at June 30, 2010. Projected forfeitures were 2,472 and 3,160 at June 30, 2010 and 2009 based upon historical forfeitures. The Partnership recorded expenses related to its plan to be reimbursed to its general partner of $0.6 million and $1.5 million and $2.4 million and $4.4 million for the three and six month periods ended June 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 six month periods ended June 30, 2010 and 2009, respectively.

In connection with the phantom unit awards granted since February 2008, the CNG Committee also granted tandem Distribution Equivalent Rights, or DERs, which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units. The DERs are only applicable to the grants since 2008 that vest in 2012 through 2014 and, at the discretion of the CNG Committee, may be included with awards granted in the future. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting.

The unaccrued cost associated with the outstanding grants and related DERs at June 30, 2010 was $11.0 million.

13. Equity Offering and 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 May 14, 2010, the Partnership paid a quarterly distribution $0.54 per unit to all holders of common units.

14. Subsequent Events

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

Distributions

On July 21, 2010, the Partnership declared a second quarter 2010 distribution of $0.54 per unit. The distribution will be paid on August 13, 2010 to unitholders of record on August 5, 2010.


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, of which 54% are low sulfur coal. 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 a specified period of time (usually two to five years) if sufficient royalties are generated from production in those future periods. We do not recognize these minimum royalties as revenue until the applicable recoupment period has expired or they are recouped through production. Until recognized as revenue, these minimum royalties are recorded as deferred revenue, a liability on our balance sheet.

In addition to coal and aggregate royalty revenues, we generated approximately 26% of our first half 2010 revenues from other sources, as compared to 19% in the first half 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 immediate oil and gas revenues in the second quarter 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.

Our Current Liquidity Position

As of June 30, 2010, we had $265 million in available capacity under our existing credit facility, which does not mature until March 2012, as well as approximately $78 million in cash. On April 7, 2010, we completed an equity offering in which we received net proceeds of $110.2 million, excluding our general partner’s proportionate capital contribution. We used these proceeds to pay down all of the borrowings under our credit facility and to fund several small acquisitions.

Pursuant to the purchase and sale agreement signed in the Colt acquisition discussed below, we expect to fund an additional $205 million over the next two years, of which approximately $125 million is anticipated to be funded in the fourth quarter of 2010 as the operator achieves various development milestones. In connection with the Colt acquisition, the holders of our incentive distribution rights agreed to permanently forego approximately $7.35 million in distributions with respect to each of the third and fourth quarters of 2009. 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 six months ended June 30, 2010, our lessees produced 24.0 million tons of coal and aggregates, generating $106.2 million in royalty revenues from our properties, and our total revenues were $143.1 million. After a difficult coal market in 2009, the prices for both steam and metallurgical coal increased in the first half of 2010. Although we expect the market for metallurgical coal to flatten out over the remainder of 2010, because approximately 40% of our coal royalty revenues and 33% of the related production during the first half of 2010 were from metallurgical coal, we benefitted as the global economy recovered and the demand for steel increased.

Even though coal royalty revenues from our Appalachian properties represented 63% of our total revenues in the first half 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 being done 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 not revenue to NRP. Thus, to the extent that the development takes longer than anticipated to begin production, it will impact the revenues that we receive.

On April 9, we were notified by the Cline Group that it has temporarily idled certain sections of its Gatling, West Virginia mine and planned to complete development work in other areas of the mine. Cline has indicated that it expects the mine to resume production in the future, but an exact date is not known. Cline has communicated to us that it will continue to make its quarterly minimum payments with respect to this mine.

Political, Legal and Regulatory Environment

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

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

In addition to the increased oversight of the EPA, the Mine Safety and Health Administration, or MSHA, has increased its involvement in the approval of plans and enforcement of safety issues in connection with mining. The recent mine disaster at Massey’s Upper Big Branch Mine 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.

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


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	(Unaudited)
	2010			2009			2010			2009
Net cash provided by operating activities	$	71,672		$	57,127		$	113,553		$	100,679
Less scheduled principal payments		(9,350	)		(9,350	)		(24,542	)		(9,542	)
Less reserves for future principal payments		(7,880	)		(8,059	)		(15,939	)		(16,118	)
Add reserves used for scheduled principal payments		9,350			9,350			24,542			9,542

Distributable cash flow	$	63,792		$	49,068		$	97,614		$	84,561

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 assets 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, CO ₂ 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. As of our filing date, we had funded the entire $6.7 million upon completion of certain development milestones in early August.

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 $3.0 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. As of our filing date, we have funded $4.5 million of the acquisition. The remaining payments are expected to be paid over the next three months upon completion of certain development milestones.

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

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

Colt. In September 2009, we signed a definitive agreement to acquire approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt LLC, an affiliate of the Cline Group, through eight separate transactions for a total purchase price of $255 million. In January 2010, we closed the second transaction for $40.0 million and acquired approximately 19.5 million tons of reserves. As of June 30, 2010, we had acquired approximately 22.8 million tons of reserves associated with the initial production from the mine. Future closings anticipated through 2012 will be associated with completion of certain milestones related to the new mine’s construction.

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

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

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

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

Results of Operations


	Three Months Ended					Increase			Percentage
	June 30,					(Decrease)			Change
	2010			2009
	(In thousands, except percent and per ton data)
	(Unaudited)
Coal:
Coal royalty revenues
Appalachia
Northern	$	4,924		$	2,890	$	2,034			70	%
Central		38,526			30,308		8,218			27	%
Southern		6,074			4,809		1,265			26	%

Total Appalachia		49,524			38,007		11,517			30	%
Illinois Basin		6,819			6,570		249			4	%
Northern Powder River Basin		1,489			1,803		(314	)		(17	%)

Total	$	57,832		$	46,380	$	11,452			25	%

Production (tons)
Appalachia
Northern		1,251			967		284			29	%
Central		6,971			6,989		(18	)		<(1	%)
Southern		833			798		35			4	%

Total Appalachia		9,055			8,754		301			3	%
Illinois Basin		1,751			1,956		(205	)		(10	%)
Northern Powder River Basin		961			1,074		(113	)		(11	%)

Total		11,767			11,784		(17	)		<(1	%)

Average gross royalty per ton
Appalachia
Northern	$	3.94		$	2.99	$	0.95			32	%
Central		5.53			4.34		1.19			27	%
Southern		7.29			6.03		1.26			21	%
Total Appalachia		5.47			4.34		1.13			26	%
Illinois Basin		3.89			3.36		0.53			16	%
Northern Powder River Basin		1.55			1.68		(0.13	)		(8	%)
Combined average gross royalty per ton		4.91			3.94		0.97			25	%

Aggregates:
Royalty revenue	$	1,064		$	1,047	$	17			2	%
Aggregate royalty bonus	$	(714	)	$	300	$	(1,014	)		(338	%)
Production		778			791		(13	)		(2	%)
Average base royalty per ton	$	1.37		$	1.32	$	0.05			4	%

Coal Royalty Revenues and Production . Coal royalty revenues comprised approximately 73% and 78% of our total revenue for each of the three month periods ended June 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 June 30, 2010 compared to the same period of 2009. Production in the Central and Southern 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. In Northern Appalachia, a new mine continues to show production improvements.

Illinois Basin . Production decreased primarily due to a longwall move on the Williamson property contributing to lower shipments. The production decrease was offset due to higher royalty per ton being realized, resulting in increased coal royalty revenues.

Northern Powder River Basin . Coal royalty revenues and production decreased on our Western Energy property due to the normal variations that occur due to the checkerboard nature of ownership and minor royalty adjustments for earlier periods.

Aggregates Royalty Revenues and Production . Aggregate revenues include royalties from current production as well as an estimate of a royalty bonus which is determined annually based on the profitability of the lessee. Year over year aggregate production and royalty revenues were nearly the same. 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.


	Six Months Ended					Increase			Percentage
	June 30,					(Decrease)			Change
	2010			2009
	(In thousands, except percent and per ton data)
	(Unaudited)
Coal:
Coal royalty revenues
Appalachia
Northern	$	9,340		$	5,933	$	3,407			57	%
Central		70,334			68,186		2,148			3	%
Southern		10,275			9,906		369			4	%

Total Appalachia		89,949			84,025		5,924			7	%
Illinois Basin		11,029			10,821		208			2	%
Northern Powder River Basin		4,015			4,141		(126	)		(3	%)

Total	$	104,993		$	98,987	$	6,006			6	%

Production (tons)
Appalachia
Northern		2,498			2,066		432			21	%
Central		13,367			14,978		(1,611	)		(11	%)
Southern		1,534			1,639		(105	)		(6	%)

Total Appalachia		17,399			18,683		(1,284	)		(7	%)
Illinois Basin		2,898			3,282		(384	)		(12	%)
Northern Powder River Basin		2,272			2,301		(29	)		(1	%)

Total		22,569			24,266		(1,697	)		(7	%)

Average gross royalty per ton
Appalachia
Northern	$	3.74		$	2.87	$	0.87			30	%
Central		5.26			4.55		0.71			16	%
Southern		6.70			6.04		0.66			11	%
Total Appalachia		5.17			4.50		0.67			15	%
Illinois Basin		3.81			3.30		0.51			15	%
Northern Powder River Basin		1.77			1.80		(0.03	)		(2	%)
Combined average gross royalty per ton		4.65			4.08		0.57			14	%

Aggregates:
Royalty revenue	$	1,880		$	1,977	$	(97	)		(5	%)
Aggregate royalty bonus		(639	)	$	1,020		(1,659	)		(163	%)
Production		1,383			1,481		(98	)		(7	%)
Average base royalty per ton	$	1.36		$	1.33	$	0.03			2	%

Coal Royalty Revenues and Production . Coal royalty revenues comprised approximately 73% and 78% of our total revenue for each of the six month periods ended June 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 six month period ended June 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 decreased primarily due to a longwall move on the Williamson property. The production decrease was more than offset due to higher royalty per ton being realized, resulting 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.

Other Operating Results

In addition to coal and aggregate royalty revenues, we generated approximately 26% of our first half revenues from other sources, as compared to 19% in the first half 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 immediate oil and gas revenues in the second quarter 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 $2.7 million and $2.4 million in processing revenues for the quarters ended June 30, 2010 and 2009, respectively and $4.3 million for both of the six month periods ended June 30, 2010 and 2009. We do not operate the preparation plants, but receive a fee for coal processed through them. Similar to our coal royalty structure, the throughput fees are based on a percentage of the ultimate sales price for the coal that is processed through the facilities.

In addition to our preparation plants, we own coal handling and transportation infrastructure in West Virginia, Ohio and Illinois. In contrast to our typical royalty structure, we receive a fixed rate per ton for coal transported over these facilities. For the assets other than our loadout facility at the Shay No. 1 mine in Illinois, we operate coal handling and transportation infrastructure and have subcontracted out that responsibility to third parties. We generated transportation fees from these assets of approximately $4.0 million and $3.5 million for the quarters ended June 30, 2010 and 2009 and $6.8 million and $5.6 million for the six months ended June 30, 2010 and 2009, respectively.

Operating costs and expenses. Included in total expenses are:

	•		Depreciation, depletion and amortization of $16.5 million and $22.0 million for the quarters ended June 30, 2010 and 2009, and $27.9 million and $35.1 million for the six month periods ended June 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 $1.0 million for the six months ended June 30, 2010. This is primarily due to production coming from leases with lower depletion rates, partially offset by a change in estimate on our contract amortization of approximately $2.8 million during the second quarter of 2010.

	•		General and administrative expenses were $6.8 million and $5.8 million for the quarters ended June 30, 2010 and 2009, and $13.3 million for both of the six month periods ended June 30, 2010 and 2009. The increase quarter over quarter in general and administrative expense is primarily due to accruals under our long-term incentive plan attributable to fluctuations in our unit price.

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

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 six months ended June 30, 2010 and 2009 was $113.6 million and $100.7 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 six months ended June 30, 2010 and 2009 was $112.5 million and $96.8 million, respectively. For the six months ended June 30, 2010 and 2009, substantially all of our investing activities consisted of acquiring coal reserves, plant and equipment and other mineral rights.

Net cash flows used in financing for the six months ended June 30, 2010 was $5.3 million. During the first six months of 2010, we had proceeds from loans of $81.0 million offset by repayment of debt of $98.5 million and retirement of a $3.0 million obligation related to the purchase of coal reserves and infrastructure. During the second quarter we received proceeds from the issuance of units of $110.4 million. We also paid distributions of $97.4 million. During the same period for 2009, net cash used in financing activities was $12.3 million, which included proceeds from loans of $303.0 million, principal repayments of $160.5 million, retirement of an obligation related to an acquisition of $60.0 million and $94.1 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 June 30, 2010 increased $20.6 million to $87.7 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 June 30, 2010, our debt consisted of:

	•		$35 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;

	•		$84.6 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 and our revolving credit facility, all of our senior notes require annual principal payments in addition to semi-annual interest payments. The principal payments on the 5.82% senior notes due 2024 began March 2010, the principal payments of the 8.38% senior notes due in 2019 do not begin until March 2013 and the principal payments of the 8.92% senior notes do not begin until March 2014. We also make annual principal and interest payments on the utility local improvement obligation.

Credit Facility. We have a $300 million revolving credit facility, and at June 30, 2010 we had approximately $265 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 Offering

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.

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				Six Months Ended
	June 30,				June 30,
	(In thousands)
	(Unaudited)
	2010		2009		2010		2009
Reimbursement for services	$	1,789	$	1,703	$	3,580	$	3,429

For additional information, please read “Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement.”

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 and in the incentive distribution rights of NRP, as well as 13,510,072 common units. At June 30, 2010, we had accounts receivable totaling $6.6 million from Cline affiliates. Revenues from Cline affiliates are as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	(In thousands)
	(Unaudited)
	2010		2009		2010		2009
Coal royalty revenues	$	7,475	$	6,592	$	12,782	$	10,550
Coal processing fees		313		—		441		—
Transportation fees		3,992		3,342		6,400		5,233
Minimums recognized as revenue		3,100		—		6,200		—
Override revenue		277		374		719		770

	$	15,157	$	10,308	$	26,542	$	16,553

In addition, we have received $36.2 million in advance minimum royalty payments to date that have not been recouped.

Quintana Capital Group GP, Ltd.

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

A fund controlled by Quintana Capital owns a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. We currently have a memorandum of understanding with Taggart Global pursuant to which the two companies have agreed to jointly pursue the development of coal handling and preparation plants. We will own and lease the plants to Taggart Global, which will design, build and operate the plants. The lease payments are based on the sales price for the coal that is processed through the facilities. To date, we have acquired four facilities under this agreement with Taggart with a total cost of $46.6 million. Revenues from Taggart are as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	(In thousands)
	(Unaudited)
	2010		2009		2010		2009
Coal processing revenue	$	1,811	$	1,309	$	2,534	$	2,003

At June 30, 2010, we had accounts receivable totaling $0.8 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				Six Months Ended
	June 30,				June 30,
	(In thousands)
	(Unaudited)
	2010		2009		2010		2009
Coal royalty revenue	$	379	$	348	$	832	$	832

We also had accounts receivable totaling $0.1 million from Kopper-Glo at June 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 June 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.


Item 3.		Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk, which includes adverse changes in commodity prices and interest rates as discussed below:

Commodity Price Risk

We are dependent upon the effective marketing and efficient mining of our coal reserves by our lessees. Our lessees sell coal under various long-term and short-term contracts as well as on the spot market. A large portion of these sales are under long-term contracts. As evidenced by the current market, a substantial or extended decline in coal prices could materially and adversely affect us in two ways. First, lower prices may reduce the quantity of coal that may be economically produced from our properties. This, in turn, could reduce our coal royalty revenues and the value of our coal reserves. Second, even if production is not reduced, the royalties we receive on each ton of coal sold may be reduced. Additionally, volatility in coal prices could make it difficult to estimate with precision the value of our coal reserves and any coal reserves that we may consider for acquisition.

Interest Rate Risk

Our exposure to changes in interest rates results from our borrowings under our revolving credit facility, which are subject to variable interest rates based upon LIBOR. At June 30, 2010, we had $35.0 million outstanding in variable interest rate debt.


Item 4.		Controls and Procedures

NRP carried out an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of NRP management, including the Chief Executive Officer and Chief Financial Officer of the general partner of the general partner of NRP. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and procedures are effective in providing reasonable assurance that (a) the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and (b) such information is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

No changes were made to our internal control over financial reporting during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information


Item 1.		Legal Proceedings

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes these claims will not have a material effect on our financial position, liquidity or operations.


Item 1A.		Risk Factors

During the period covered by this report, there were no material changes from the risk factors previously disclosed in Natural Resource Partners L.P.’s Form 10-K/A for the year ended December 31, 2009.


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

None.


Item 3.		Defaults Upon Senior Securities

None.


Item 4.		(Removed and Reserved)


Item 5.		Other Information

None.


Item 6.		Exhibits


10.1*	—	First Amendment to Amended and Restated Credit Agreement, dated May 11, 2010, by and among NRP (Operating) LLC and the banks and other financial institutions listed on the signature pages thereto, including Citibank, N.A., as Administrative Agent.

10.2*	—	Amendment No. 1 to Purchase and Sale Agreement, dated as of July 29, 2010, by and between WPP LLC and Colt, LLC.

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.

101*	—	Interactive Data File.


*		Submitted herewith.

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: By:	NRP (GP) LP, its general partner GP NATURAL RESOURCE PARTNERS LLC, its general partner
Date: August 6, 2010	By:	/s/ Corbin J. Robertson, Jr.
		Corbin J. Robertson, Jr.,
		Chairman of the Board and Chief Executive Officer (Principal Executive Officer)


Date: August 6, 2010	By:	/s/ Dwight L. Dunlap
		Dwight L. Dunlap,
		Chief Financial Officer and Treasurer (Principal Financial Officer)


Date: August 6, 2010	By:	/s/ Kenneth Hudson
		Kenneth Hudson
		Controller (Principal Accounting Officer)

TABLE OF CONTENTS

Part I. Financial Information Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 4. (removed and Reserved)Item 5. Other Information Item 6. Exhibits

NRP 10-Q Quarter ended June 30, 2010