NRP 10-Q Quarterly Report June 30, 2011

NATURAL RESOURCE PARTNERS LP

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10-Q 1 h83154e10vq.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, 2011


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):

Large Accelerated Filer þ

Accelerated Filer o

Non-accelerated Filer o
(Do not check if a smaller reporting company)

Smaller Reporting Company o

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 5, 2011 there were 106,027,836 Common Units outstanding.

TABLE OF CONTENTS


	Page
PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010		4
Consolidated Statements of Income For the Three and Six Months Ended June 30, 2011 and 2010		5
Consolidated Statements of Cash Flows For the Six Months Ended June 30, 2011 and 2010		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		27
Environmental		28

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		29

ITEM 4. Controls and Procedures		30

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings		31

ITEM 1A. Risk Factors		31

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds		31

ITEM 3. Defaults Upon Senior Securities		31

ITEM 4. (Removed and Reserved)		31

ITEM 5. Other Information		31

ITEM 6. Exhibits		32

Signatures		33

EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

Forward-Looking Statements

Statements included in this Form 10-Q are forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

Such forward-looking statements include, among other things, statements regarding capital expenditures, acquisitions and dispositions, expected commencement dates of mining, projected quantities of future production by our lessees and projected demand for or supply of coal and aggregates that will affect sales levels, prices and royalties and other revenues realized by us.

These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

You should not put undue reliance on any forward-looking statements. Please read “Item 1A. Risk Factors” in our Form 10-K for the year ended December 31, 2010 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, except unit data)


	June 30,			December 31,
	2011			2010
	(Unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	145,705		$	95,506
Accounts receivable, net of allowance for doubtful accounts		31,728			26,195
Accounts receivable — affiliates		4,713			7,915
Other		438			910

Total current assets		182,584			130,526
Land		24,543			24,543
Plant and equipment, net		57,438			62,348
Coal and other mineral rights, net		1,367,532			1,281,636
Intangible assets, net		156,775			161,931
Loan financing costs, net		3,272			2,436
Other assets, net		556			616

Total assets	$	1,792,700		$	1,664,036


LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable and accrued liabilities	$	1,402		$	1,388
Accounts payable — affiliates		—			499
Obligation related to acquisitions		4,100			—
Current portion of long-term debt		30,801			31,518
Accrued incentive plan expenses — current portion		6,444			6,788
Property, franchise and other taxes payable		5,513			6,926
Accrued interest		11,679			9,811

Total current liabilities		59,939			56,930
Deferred revenue		122,707			109,509
Accrued incentive plan expenses		10,561			11,347
Long-term debt		793,961			661,070
Partners’ capital:
Common units outstanding (106,027,836)		787,560			806,529
General partner’s interest		13,750			14,132
Non-controlling interest		4,743			5,065
Accumulated other comprehensive loss		(521	)		(546	)

Total partners’ capital		805,532			825,180

Total liabilities and partners’ capital	$	1,792,700		$	1,664,036

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,
	2011			2010			2011			2010
	(Unaudited)						(Unaudited)
Revenues:
Coal royalties	$	69,788		$	57,832		$	135,153		$	104,993
Aggregate royalties		1,831			350			3,025			1,241
Coal processing fees		3,173			2,693			6,262			4,337
Transportation fees		3,745			4,043			7,843			6,818
Oil and gas royalties		1,996			2,087			4,988			3,186
Property taxes		3,577			2,782			6,589			5,433
Minimums recognized as revenue		1,841			3,418			2,348			6,792
Override royalties		3,492			3,157			6,535			6,124
Other		1,966			3,225			3,518			4,182

Total revenues		91,409			79,587			176,261			143,106
Operating costs and expenses:
Depreciation, depletion and amortization		16,166			16,485			30,488			27,853
General and administrative		6,439			6,794			16,635			13,342
Property, franchise and other taxes		3,306			3,498			7,003			7,232
Transportation costs		523			557			991			822
Coal royalty and override payments		159			301			467			993

Total operating costs and expenses		26,593			27,635			55,584			50,242

Income from operations		64,816			51,952			120,677			92,864
Other income (expense):
Interest expense		(12,429	)		(10,346	)		(23,016	)		(21,075	)
Interest income		16			4			24			12

Income before non-controlling interest	$	52,403		$	41,610		$	97,685		$	71,801
Less non-controlling interest		(51	)		—			(51	)		—

Net income	$	52,352		$	41,610		$	97,634		$	71,801

Net income attributable to:
General partner	$	1,047		$	573		$	1,953		$	917

Holders of incentive distribution rights	$	—		$	12,983		$	—		$	25,966

Limited partners	$	51,305		$	28,054		$	95,681		$	44,918


Basic and diluted net income per limited partner unit	$	0.48		$	0.38		$	0.90		$	0.63


Weighted average number of units outstanding		106,028			74,028			106,028			71,752

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,
	2011			2010
	(Unaudited)
Cash flows from operating activities:
Net income	$	97,634		$	71,801
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		30,488			27,853
Non-cash interest charge, net		268			291
Non-controlling interest		51			—
Change in operating assets and liabilities:
Accounts receivable		(2,331	)		(5,085	)
Other assets		532			119
Accounts payable and accrued liabilities		(485	)		98
Accrued interest		1,868			(322	)
Deferred revenue		13,198			20,641
Accrued incentive plan expenses		(1,130	)		(1,340	)
Property, franchise and other taxes payable		(1,413	)		(503	)

Net cash provided by operating activities		138,680			113,553

Cash flows from investing activities:
Acquisition of land, coal and other mineral rights		(99,368	)		(110,411	)
Acquisition or construction of plant and equipment		(325	)		(2,102	)
Disposition of assets		1,100			—

Net cash used in investing activities		(98,593	)		(112,513	)

Cash flows from financing activities:
Proceeds from loans		335,000			81,000
Debt issuance costs		(1,052	)		—
Proceeds from issuance of units		—			110,436
Repayment of loans		(202,826	)		(98,542	)
Capital contribution		—			2,350
Payment of obligation related to acquisitions		(4,025	)		(2,969	)
Costs associated with equity transactions		(140	)		(152	)
Distributions to partners		(116,845	)		(97,387	)

Net cash provided by (used in) financing activities		10,112			(5,264	)

Net decrease in cash and cash equivalents		50,199			(4,224	)
Cash and cash equivalents at beginning of period		95,506			82,634

Cash and cash equivalents at end of period	$	145,705		$	78,410


Supplemental cash flow information:
Cash paid during the period for interest	$	20,859		$	21,070


Non-cash activities:
Mineral rights to be received	$	—		$	13,249
Non-controlling interest	$	373		$	(7,335	)
Obligation related to purchase of reserves and infrastructure	$	4,100		$	6,200

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 six months ended June 30, 2011 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 2010 Annual Report on Form 10-K in connection with the reading of these unaudited interim consolidated financial statements.

The Partnership engages principally in the business of owning, managing and leasing mineral properties in the United States. The Partnership owns coal reserves in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States, as well as lignite reserves in the Gulf Coast region. The Partnership also owns aggregate reserves in several states across the country. The Partnership does not operate any mines on its properties, but leases reserves to experienced operators under long-term leases that grant the operators the right to mine the Partnership’s reserves in exchange for royalty payments. Lessees are generally required to make payments based on the higher of a percentage of the gross sales price or a fixed royalty per ton, in addition to a minimum payment.

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. Recent Accounting Pronouncements

In June 2011, the FASB amended the presentation of comprehensive income. The amendments in this update give the Partnership the option to present the total comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. These amendments are effective for fiscal years and interim periods within those years, beginning on or after December 15, 2011. The Partnership has not determined which method of presentation it will elect.

In May 2011, the FASB amended fair value measurement and disclosure requirements. The amendments result in common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards (IFRSs). Some of the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. Other amendments change a particular principal or requirement for measuring fair value or for disclosing information about fair value measurements. The amendment likely to have the most impact on the Partnership relates to the fair value disclosure of the senior notes’ quantitative information about unobservable inputs used in fair value measurements, that is categorized within Level 3 of the fair value hierarchy. These amendments are effective for fiscal years and interim periods within those years, beginning on or after December 15, 2011. The Partnership does not expect this adoption to have a material impact on its financial position, results of operations or cash flows.

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. Significant Acquisitions

NBR Sand. In June 2011, the Partnership acquired an overriding royalty interest in approximately 711 acres of frac sand reserves near Tyler, TX for $16.5 million, of which $14.4 million was funded at closing and the remaining $2.1 million was paid in July 2011.

CALX Resources. In February 2011, the Partnership acquired approximately 500 acres of mineral and surface rights related to limestone reserves on the Tennessee River near Paducah, Kentucky for $16.0 million, of which $14.0 million has been paid at June 30, 2011 and the remaining $2.0 million will be paid as certain milestones are completed.

BRP LLC. In June 2010, the Partnership and International Paper Company (“IPC”) formed BRP to own and manage mineral assets previously owned by IPC. Some of these assets are currently subject to leases, and certain other assets are available for future development by the venture. In exchange for a $42.5 million contribution, NRP became the controlling member with the right to designate two of the three managers of BRP. NRP has a 51% income interest plus a preferential cumulative annual distribution prior to profit sharing. In exchange for the contribution of the producing properties and the properties not currently producing, IPC received $42.5 million in cash, a minority voting interest and a 49% income interest after the preferential cumulative annual distribution. The amount of the preference is fixed throughout the life of the venture but can be reduced by a portion of the proceeds received from sales of producing properties included in the initial acquisition. Identified tangible assets included in the transaction are oil and gas, coal, and aggregate reserves, as well the rights to other unidentified minerals which may include 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, 2011, the assets and liabilities of the venture are included in the consolidated balance sheet. The allocation of the purchase price was based on independent third party valuations. The following table summarizes the final allocation of the purchase price and preliminary estimated fair values of the assets acquired and liabilities assumed for the BRP transaction:


			Initial
	Final		Estimated
	Fair Value		Fair Value
	(In thousands)		(In thousands)
	(unaudited)

Coal and other mineral rights	$	45,329	$	45,759
Intangible assets	$	1,863	$	1,806

Capital contribution	$	42,500	$	42,500
Non-controlling interests	$	4,692	$	5,065

Approximately $38.3 million of the total $47.2 million asset fair value, as well as the value of the $4.7 million non-controlling interest, were estimated using an expected cash flows approach. The remaining assets fair value was determined using a market approach. See Note 8, “Fair Value”.

Operations of the venture are included from June 1, 2010, the effective date of acquisition. Total net income from startup through December 31, 2010 was $2.3 million and for the six months ended June 30, 2011 was $1.7 million. 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.

Transaction expenses related to the acquisition through December 31, 2010 were $2.5 million. For the six months ended June 30, 2011, transaction expenses were $0.4 million and are included in general and administrative expenses in the accompanying Consolidated Statements of Income.

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.

Colt. In September 2009, the Partnership signed a definitive agreement to acquire approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt, LLC, an affiliate of the Cline Group, through several separate transactions for a total purchase price of $255 million. As of June 30, 2011, the Partnership had acquired approximately 92.1 million tons of reserves for approximately $175 million, including $70.0 million paid during the first quarter 2011. Future closings anticipated through 2012 will be associated with completion of certain milestones related to the new mine.

4. Plant and Equipment

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


	June 30,			December 31,
	2011			2010
	(In thousands)
	(Unaudited)

Asset held for sale	$	1,802		$	—
Plant construction in-process		—			6,279
Plant and equipment at cost		83,019			81,906
Less accumulated depreciation		(27,383	)		(25,837	)


Net book value	$	57,438		$	62,348

Under the provisions of one of the Partnership’s tipple leases, the lessee exercised its option to purchase the tipple and corresponding land for fair market value, which is greater than the carrying amount of the asset. In May 2011, the lessee paid a $1.0 million deposit that is nonrefundable and will be applied to the purchase price if the lessee proceeds. The Partnership believes it is very likely the lessee will proceed and has classified the net book value of the tipple and corresponding land, less the $1.0 million paid, as an asset held for sale.


	Six months ended
	June 30,
	2011		2010
	(In thousands)
	(Unaudited)

Total depreciation expense on plant and equipment	$	4,235	$	4,159

5. Coal and Other Mineral Rights

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


	June 30,			December 31,
	2011			2010
	(In thousands)
	(Unaudited)

Coal and other mineral rights	$	1,736,223		$	1,629,286
Less accumulated depletion and amortization		(368,691	)		(347,650	)


Net book value	$	1,367,532		$	1,281,636


	Six months ended
	June 30,
	2011		2010
	(In thousands)
	(Unaudited)

Total depletion and amortization expense on coal and other mineral rights	$	21,041	$	18,489

6. Intangible Assets

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


	June 30,			December 31,
	2011			2010
	(In thousands)
	(Unaudited)

Contract intangibles	$	180,291		$	180,233
Less accumulated amortization		(23,516	)		(18,302	)


Net book value	$	156,775		$	161,931


	Six months ended
	June 30,
	2011		2010
	(In thousands)
	(Unaudited)

Total amortization expense on intangible assets	$	5,212	$	5,203

The estimates of future expense for the periods indicated below are based on current mining plans, which are subject to revision in future periods.


	Estimated
	Amortization
	Expense
	(In thousands)
	(Unaudited)

Remainder of 2011	$	9,887
For year ended December 31, 2012		11,193
For year ended December 31, 2013		10,538
For year ended December 31, 2014		10,538
For year ended December 31, 2015		10,538

7. Long-Term Debt

Long-term debt consists of the following:


	June 30,			December 31,
	2011			2010
	(In thousands)
	(Unaudited)

$300 million floating rate revolving credit facility, due March 2012	$	—		$	94,000
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		32,317			37,650
8.38% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2013, maturing in March 2019		150,000			150,000
5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020		76,923			76,923
5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021		1,922			2,115
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023		33,600			36,900
4.73% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2023		75,000			—
5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2024		195,000			210,000
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
5.03% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026		175,000			—

Total debt		824,762			692,588
Less — current portion of long term debt		(30,801	)		(31,518	)

Long-term debt	$	793,961		$	661,070

Principal payments due in:


	Senior Notes		Credit Facility		Total
	(In thousands)
	(Unaudited)

Remainder of 2011	$	7,692	$	—	$	7,692
2012		30,801		—		30,801
2013		87,230		—		87,230
2014		77,136		—		77,136
2015		77,136		—		77,136
Thereafter		544,767		—		544,767

	$	824,762	$	—	$	824,762

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.

In the second quarter, the Partnership issued $250 million of senior unsecured notes and is committed to issue another $50 million of unsecured senior notes in October of this year. Proceeds from the senior notes were used to repay all of the outstanding borrowings under the revolving credit facility and the Partnership has used, or will use, the remaining proceeds for acquisitions.

A summary of the four tranches of senior notes are as follows:

Series

Amount

Interest Rate

Issue Date

Maturity

$75 million

4.73

April 20, 2011

December 1, 2023

$125 million

5.03

April 20, 2011

December 1, 2026

$50 million

5.03

June 15, 2011

December 1, 2026

$50 million

5.18

October 3, 2011

December 1, 2026

All tranches have semi-annual interest payments beginning December 1, 2011, and equal annual principal payments beginning December 1, 2014.

The Partnership made principal payments of $23.8 million on its senior notes during the six months ended June 30, 2011.

The Partnership has a $300 million revolving credit facility, and at June 30, 2011, the full amount 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.

At June 30, 2011 the Partnership did not have any outstanding balance on its revolving credit facility, while at December 31, 2010 the Partnership had $94.0 million outstanding on its revolving credit facility. The weighted average interest rates for the six months ended June 30, 2011 and the year ended December 31, 2010 were 1.83% and 1.42%, 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, 2011.

8. Fair Value

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 $843.8 million and $596.1 million at June 30, 2011 and December 31, 2010, respectively, for the senior notes. The carrying value of the Partnership’s senior notes was $824.8 million and $598.6 million at June 30, 2011 and December 31, 2010, 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,
	2011		2010		2011		2010
	(In thousands)
	(Unaudited)

Reimbursement for services	$	2,091	$	1,789	$	4,153	$	3,580

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. At June 30, 2011, Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest in the Partnership’s general partner, as well as 16,686,672 common units. Revenues from the Cline affiliates are as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
			(In thousands)
			(Unaudited)

Coal royalty revenues	$	5,250	$	7,475	$	14,429	$	12,782
Coal processing fees		492		313		1,193		441
Transportation fees		3,745		3,992		7,844		6,400
Minimums recognized as revenue		—		3,100		—		6,200
Override revenue		228		277		679		719

	$	9,715	$	15,157	$	24,145	$	26,542

At June 30, 2011, the Partnership had accounts receivable totaling $3.1 million from Cline affiliates, and had received $58.4 million in minimum royalty payments that have not been recouped by Cline affiliates, of which $12.0 million was received in the current year.

Quintana Capital Group GP, Ltd.

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

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. The Partnership currently leases four facilities to Taggart. Revenues from Taggart are as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
	(In thousands)
	(Unaudited)

Coal processing revenues	$	2,419	$	1,811	$	4,625	$	2,534

At June 30, 2011, the Partnership had accounts receivable totaling $1.4 million from Taggart.

A fund controlled by Quintana Capital owns Kopper-Glo, a small coal mining company that is one of the Partnership’s lessees with operations in Tennessee. Revenues from Kopper-Glo are as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
	(In thousands)
	(Unaudited)

Coal royalty revenues	$	419	$	379	$	753	$	832

The Partnership also had accounts receivable totaling $0.2 million from Kopper-Glo at June 30, 2011.

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, 2011. The Partnership is not associated with any environmental contamination that may require remediation costs.

Acquisition

In conjunction with a definitive agreement, as of June 30, 2011, the Partnership may be obligated to purchase in excess of 100 million additional tons of coal reserves from Colt, LLC for an aggregate purchase price of $80.0 million over the next year as certain milestones are completed relating to construction of a new mine.

11. Major Lessees

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


	Three Months Ended										Six Months Ended
	June 30,										June 30,
	2011					2010					2011					2010
	(Dollars in thousands)
	(Unaudited)
	Revenues		Percent			Revenues		Percent			Revenues		Percent			Revenues		Percent
Alpha Natural Resources	$	29,701		32	%	$	21,652		27	%	$	54,292		31	%	$	38,941		27	%
The Cline Group	$	9,715		11	%	$	15,157		19	%	$	24,145		14	%	$	26,542		19	%

In the first half of 2011, the Partnership derived over 45% of its total revenue from the two companies listed above. As a result, the Partnership has a significant concentration of revenues with those lessees, although in most cases, with the exception of the Williamson mine operated by an affiliate of the Cline group, the exposure is spread out over a number of different mining operations and leases. Cline’s Williamson mine alone was responsible for approximately 9% of our total revenues for the first six months of 2011. As a result of the merger of Alpha Natural Resources and Massey Energy Company, all prior period revenues from Massey have been combined with those of Alpha for presentation purposes in this 10-Q.

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 during 2011 is as follows:


Outstanding grants at January 1, 2011	753,868
Grants during the year	279,078
Grants vested and paid during the year	(162,186	)
Forfeitures during the year	—

Outstanding grants at June 30, 2011	870,760

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 0.23% to 1.24% and 26.02% to 49.56%, respectively at June 30, 2011. The Partnership’s historical distribution rate of 6.73% and historical forfeiture rate of 2.85% were used in the calculation at June 30, 2011. The Partnership recorded expenses related to its plan to be reimbursed to its general partner of $1.1 million and $0.6 million and $5.5 million and $2.4 million for the three and six month periods ended June 30, 2011 and 2010, respectively. In connection with the Long-Term Incentive Plan, payments are typically made during the first half of the year. Payments of $5.7 million and $3.2 million were made during the six month periods ended June 30, 2011 and 2010, 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 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 unvested outstanding grants and related DERs at June 30, 2011, was $17.6 million.

13. Equity Transactions, including Distributions

On May 13, 2011, the Partnership paid a quarterly distribution $0.54 per unit to all holders of common units.

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

14. Subsequent Events

The following represents material events that have occurred subsequent to June 30, 2011 through the time of the Partnership’s filing with the Securities and Exchange Commission:

Distributions

On July 20, 2011, the Partnership declared a distribution of $0.54 per unit to be paid on August 12, 2011 to unitholders of record on August 5, 2011.

Acquisition

Royal Oil and Gas. In July 2011, the Partnership acquired approximately 44,000 acres of coal reserves and coal bed methane located in Pennsylvania and Illinois from Royal Oil and Gas Corporation for $8.0 million.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of the financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included elsewhere in this filing and the financial statements and footnotes included in the Natural Resource Partners L.P. Form 10-K , as filed on February 28, 2011.

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 lignite reserves in the Gulf Coast region. As of December 31, 2010, we owned or controlled approximately 2.3 billion tons of proven and probable coal reserves, and we also owned approximately 228 million tons of aggregate reserves in a number of states across the country. We do not operate any mines, but 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, which varies by lease, 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 22% of our first half 2011 revenues from other sources, as compared to 26% in the first half of 2010. Other sources of revenue include: coal processing and transportation fees; overriding royalties; wheelage payments; rentals; property tax revenue; and timber sales.

Our Current Liquidity Position

As of June 30, 2011, we had $300 million in available capacity under our credit facility and approximately $146 million in cash. With our credit facility maturing in March 2012, we have commenced discussions to amend and extend the term of the facility. In the second quarter of 2011, we issued $250 million of additional senior unsecured notes, and are committed to issue another $50 million of senior notes in October of this year. We used most of the proceeds from the senior notes to repay all of the outstanding borrowings under the revolving credit facility, and have used, or will use, the remaining proceeds for acquisitions. We believe that the combination of our capacity under our credit facility, our cash on hand and the pending issuance of an additional $50 million of senior notes gives us enough liquidity to meet our current capital needs.

In addition, other than a $35 million senior note that matures in 2013, 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 of our senior note obligations other than the one note, and our outstanding principal will be reduced as the minerals are depleted.

Current Results/Outlook for Second Half of 2011

For the six months ended June 30, 2011, our lessees produced 26.4 million tons of coal and aggregates, generating $138.2 million in royalty revenues from our properties, and our total revenues were $176.3 million. Prices for metallurgical coal remained at high levels, resulting in significantly improved results, especially from our Central Appalachian properties. During the first half of the year, we benefitted from our substantial exposure to metallurgical coal. However, the Oak Grove mine in Alabama suffered damage to its preparation plant due to a tornado, and is not expected to sell any coal in the third quarter. The Pinnacle mine in West Virginia has experienced a high level of carbon monoxide and remains closed until MSHA determines that the mine is safe. Both of these mines

are operated by Cliffs Natural Resources and we derived 13% of our metallurgical coal revenues during the first half of 2011 from these mines. As a result, we expect to receive a lower percentage of revenues from metallurgical coal sales in the second half of the year. In the first six months of 2011, we derived approximately 47% of our coal royalty revenues and 37% of the related production from metallurgical coal.

Even though coal royalty revenues from our Appalachian properties increased as a percentage of our total revenues for the first half of 2011, this percentage has generally been declining 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 is through the acquisition of reserves by us 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 us that can be distributed to our limited partners, the minimums are generally not revenue to us until recouped through production or at the end of the recoupment period. Thus, to the extent that the development takes longer than anticipated to begin production, it will impact the revenues that we receive in the future.

Operations at the Gatling, West Virginia mine were idled in April 2010 and had not been restarted as of the end of the second quarter. Gatling LLC, the Cline affiliate that operates the mine, has communicated to us that it is continuing to maintain the mine and is currently in discussions with American Electric Power (AEP) regarding modifications to its existing coal sales contract. Pursuant to its contractual obligations, Gatling continues to make its quarterly minimum payments with respect to this mine and has also communicated that it will continue to do so for the remainder of the lease term. The net book value of the assets relating to this operation was $129.6 million as of June 30, 2011. As of the date of this report, we have received $22.4 million in minimum royalties, and contractual quarterly minimums for the remainder of the primary term total $66.3 million. Considering all available information, we have completed an undiscounted cash flow analysis of the assets relating to this operation and determined the undiscounted cash flows exceed those assets’ carrying values. However, if the mine does not become operational in future periods or discussions with AEP or other potential purchasers of the coal are not successful, the estimated cash flows may change and we may determine that some of the assets associated with the mine have suffered impairment. This decision and an associated impairment charge could have a material adverse impact on our earnings in the period in which any impairment is recognized, but it would not impact our cash flows from operations or our distributable cash flow.

Political, Legal and Regulatory Environment

The political, legal and regulatory environment continues to be difficult for the coal industry. The Environmental Protection Agency, or EPA, has used its authority to create significant delays in the issuance of new permits and the modification of existing permits. The continued uncertainty regarding the permitting of coal mines in Appalachia has led to substantial delays and increased costs for coal operators.

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 2010 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 EPA is also using the existing Clean Air Act to regulate 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 , the EPA published a final rule 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. In December 2009, EPA determined that six greenhouse gases, including carbon dioxide and methane, endanger the public health and welfare of current and future generations. In the same 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”


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	(In thousands)
	(Unaudited)

Net cash provided by operating activities	$	91,646		$	71,672		$	138,680		$	113,553
Less scheduled principal payments		(8,633	)		(9,350	)		(23,826	)		(24,542	)
Less reserves for future principal payments		(7,700	)		(7,880	)		(15,759	)		(15,939	)
Add reserves used for scheduled principal payments		8,633			9,350			23,826			24,542

Distributable cash flow	$	83,946		$	63,792		$	122,921		$	97,614

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.

Royal Oil and Gas. In July 2011, we acquired approximately 44,000 acres of coal reserves and coal bed methane located in Pennsylvania and Illinois from Royal Oil and Gas Corporation for $8.0 million.

NBR Sand. In June 2011, we acquired an overriding royalty interest in approximately 711 acres of frac sand reserves near Tyler, TX for $16.5 million.

East Tennessee Materials. In March 2011, we acquired approximately 500 acres of mineral and surface rights related to limestone reserves in Cleveland, Tennessee near Chattanooga for $4.7 million.

CALX Resources. In February 2011, we acquired approximately 500 acres of mineral and surface rights related to limestone reserves on the Tennessee River near Paducah, Kentucky for $16.0 million, of which $14.0 million was paid as of the date of this filing and the remaining $2.0 million will be paid as certain milestones are completed.

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

methane, geothermal, 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.

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 lease the facility to a local operator. The total cost for the facility was $6.5 million.

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

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

Colt. In September 2009, we signed a definitive agreement to acquire approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt, LLC, an affiliate of the Cline Group, through several separate transactions for a total purchase price of $255 million. As of the date of this filing, we had acquired approximately 92.1 million tons of reserves for approximately $175 million. Future closings anticipated through 2012 will be associated with completion of certain milestones related to the new mine’s construction.

Results of Operations


	Three Months Ended
	June 30,					Increase			Percentage
	2011		2010			(Decrease)			Change
	(In thousands, except percent and per ton data)
	(Unaudited)

Coal:
Coal royalty revenues
Appalachia
Northern	$	5,180	$	4,924		$	256			5	%
Central		55,119		38,526			16,593			43	%
Southern		3,447		6,074			(2,627	)		(43	)%

Total Appalachia		63,746		49,524			14,222			29	%
Illinois Basin		4,771		6,819			(2,048	)		(30	)%
Northern Powder River Basin		1,120		1,489			(369	)		(25	)%
Gulf Coast		151		—			151			100	%

Total	$	69,788	$	57,832		$	11,956			21	%

Production (tons)
Appalachia
Northern		1,199		1,251			(52	)		(4	)%
Central		8,023		6,971			1,052			15	%
Southern		472		833			(361	)		(43	)%

Total Appalachia		9,694		9,055			639			7	%
Illinois Basin		1,268		1,751			(483	)		(28	)%
Northern Powder River Basin		425		961			(536	)		(56	)%
Gulf Coast		151		—			151			100	%

Total		11,538		11,767			(229	)		(2	)%

Average gross royalty per ton
Appalachia
Northern	$	4.32	$	3.94		$	0.38			10	%
Central		6.87		5.53			1.34			24	%
Southern		7.30		7.29			0.01			—
Total Appalachia		6.58		5.47			1.11			20	%
Illinois Basin		3.76		3.89			(0.13	)		(3	)%
Northern Powder River Basin		2.64		1.55			1.09			70	%
Gulf Coast		1.00		—			1.00			100	%
Combined average gross royalty per ton	$	6.05	$	4.91		$	1.14			23	%

Aggregates:
Royalty revenue	$	1,737	$	1,064		$	673			63	%
Aggregate royalty bonus	$	94	$	(714	)	$	808
Production		1,671		778			893			115	%
Average base royalty per ton	$	1.04	$	1.37		$	(0.33	)		(24	)%

Coal Royalty Revenues and Production . Coal royalty revenues comprised approximately 76% and 73% of our total revenue for each of the three month periods ended June 30, 2011 and 2010, 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 metallurgical coal prices being realized by our lessees, coal royalty revenues increased in the three month period ended June 30, 2011 compared to the same period of 2010. Production in the Central Appalachian region increased due to some mines operating for the entire quarter due to the completion of reconstruction of an associated preparation plant in late 2010, and some lessees having a higher proportion of their production on our properties. These production increases were in part offset in the Southern Appalachian region due to the temporary idling of the Oak Grove mine due to damage to a preparation plant caused by a tornado in late April 2011.

Illinois Basin . Production decreased due to reduced shipments from the Williamson property for the three months ended June 30, 2011 versus the three months ended June 30, 2010, caused primarily by the flooding on the Mississippi River. Our Macoupin property had increased sales as the mine continues to increase its production.

Northern Powder River Basin . Although coal royalty revenues increased on our Western Energy property, production decreased due to the normal variations that occur due to the checkerboard nature of ownership. The reduced production was partially offset by higher sales price realized by the lessee.

Aggregates Royalty Revenues and Production . Aggregate production and revenue both increased for the quarter ended June 30, 2011, primarily due to the volumes generated from acquisitions completed during 2010 and 2011, particularly the BRP properties. The revenue per ton decreased due to lower revenue per ton generated from some of the acquired leases.


	Six Months Ended
	June 30,					Increase			Percentage
	2011		2010			(Decrease)			Change
	(In thousands, except percent and per ton data)
	(Unaudited)

Coal:
Coal royalty revenues
Appalachia
Northern	$	9,861	$	9,340		$	521			6	%
Central		100,561		70,334			30,227			43	%
Southern		8,188		10,275			(2,087	)		(20	)%

Total Appalachia		118,610		89,949			28,661			32	%
Illinois Basin		13,831		11,029			2,802			25	%
Northern Powder River Basin		2,513		4,015			(1,502	)		(37	)%
Gulf Coast		199		—			199			100	%

Total	$	135,153	$	104,993		$	30,160			29	%

Production (tons)
Appalachia
Northern		2,374		2,498			(124	)		(5	)%
Central		15,350		13,367			1,983			15	%
Southern		1,120		1,534			(414	)		(27	)%

Total Appalachia		18,844		17,399			1,445			8	%
Illinois Basin		3,544		2,898			646			22	%
Northern Powder River Basin		905		2,272			(1,367	)		(60	)%
Gulf Coast		191		—			191			100	%

Total		23,484		22,569			915			4	%

Average gross royalty per ton
Appalachia
Northern	$	4.15	$	3.74		$	0.41			11	%
Central		6.55		5.26			1.29			25	%
Southern		7.31		6.70			0.61			9	%
Total Appalachia		6.29		5.17			1.12			22	%
Illinois Basin		3.90		3.81			0.09			2	%
Northern Powder River Basin		2.78		1.77			1.01			57	%
Gulf Coast		1.04		—			1.04			100	%
Combined average gross royalty per ton	$	5.76	$	4.65		$	1.11			24	%

Aggregates:
Royalty revenue	$	2,931	$	1,880		$	1,051			56	%
Aggregate royalty bonus	$	94	$	(639	)	$	733
Production		2,936		1,383			1,553			112	%
Average base royalty per ton	$	1.00	$	1.36		$	(0.36	)		(26	)%

Coal Royalty Revenues and Production . Coal royalty revenues comprised approximately 77% and 73% of our total revenue for each of the six month periods ended June 30, 2011 and 2010, 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 metallurgical coal prices being realized by our lessees, coal royalty revenues increased in the six month period ended June 30, 2011 compared to the same period of 2010. Production in the Central Appalachian region increased due to some mines operating for the entire first half due to the completion of reconstruction of an associated preparation plant completed late in 2010, and some lessees having a higher proportion of their production on our properties. These production increases were in part offset in the Southern Appalachian region due to the temporary idling of the Oak Grove mine due to damage to a preparation plant caused by a tornado in late April 2011, and some production moving off our property during the quarter.

Illinois Basin . Production increased due to improved shipments from the Macoupin property for the six months ended June 30, 2011 versus the same period in 2010, as the mine continues to increase its production. The increased shipments from Macoupin offset lower production and sales at the Williamson mine caused by the flooding on the Mississippi River.

Northern Powder River Basin . Coal royalty revenues and production decreased on our Western Energy property. Production decreased due to the normal variations that occur due to the checkerboard nature of ownership, but was partially offset by higher sales price realized by the lessee.

Aggregates Royalty Revenues and Production . Aggregate production and revenue both increased for the six months ended June 30, 2011, primarily due to the volumes generated from acquisitions completed during 2010 and early 2011, particularly the BRP properties. The revenue per ton decreased due to lower revenue per ton generated from some of the acquired leases.

Other Operating Results

In addition to coal and aggregate royalty revenues, we generated approximately 22% of our first half 2011 revenues from other sources, as compared to 26% for the same period of 2010. The most significant decrease in these other sources of revenue occurred due to a substantial minimum royalty paid by Cline with respect to the Colt reserves that was not recoupable in 2010 but became recoupable beginning in 2011. In addition, we received an oil and gas lease bonus as well as oil and gas revenues related to our BRP venture with International Paper. Other sources of revenue include: coal processing and transportation fees; overriding royalties; wheelage payments; rentals; property tax revenue; and timber sales.

Coal Processing and Transportation Revenues . We generated $3.2 million and $2.7 million in processing revenues for the quarters ended June 30, 2011 and 2010, respectively and $6.3 million and $4.3 million for the six months ended June 30, 2011 and 2010, respectively. We do not operate the preparation plants, but receive a fee for coal processed through them. Similar to our coal royalty structure, the throughput fees are based on a percentage of the ultimate sales price for the coal that is processed through the facilities and the higher coal prices resulted in improved revenues for these 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 $3.7 million and $4.0 million for the quarters ended June 30, 2011 and 2010, respectively and $7.8 million and $6.8 million for the six months ended June 30, 2011 and 2010, respectively.

Operating costs and expenses. Included in total expenses are:

	•		Depreciation, depletion and amortization of $16.2 million and $16.5 million for the quarters ended June 30, 2011 and 2010 and $30.5 million and $27.9 million for the six months ended June 30, 2011 and 2010. Depletion and amortization increased approximately $2.6 million for the six months ended June 30, 2011, and is primarily due to increased oil and gas depletion on our BRP properties.

	•		General and administrative expenses were $6.4 million and $6.8 million for the quarters ended June 30, 2011 and 2010 and $16.6 million and $13.3 million the six month periods ending June 30, 2011 and 2010, respectively. General and administrative expenses for the six months ended June 30, 2011 increased $3.3 million compared to the same period in 2010, primarily due to higher accruals under our long-term incentive plan attributable to increases in our unit price, as well as increased expenses for additional employees.

Interest Expense. Interest expense increased approximately $2 million for both the quarter ending June 30, 2011 and 2010 and the six months ended June 30, 2011 and 2010, respectively. This increase reflects the issuance of new senior notes at higher interest rates than our credit facility.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

We satisfy our working capital requirements with cash generated from operations. Since our initial public offering, we have financed our property acquisitions with available cash, borrowings under our revolving credit facility, and the issuance of our senior notes and additional units. While our ability to satisfy our debt service obligations and pay distributions to our unitholders depends in large part on our future operating performance, our ability to make acquisitions will depend on prevailing economic conditions in the financial markets as well as the coal and aggregate industries and other factors, some of which are beyond our control. Our capital expenditures, other than for acquisitions, have historically been minimal.

Our credit facility matures in March 2012, and we have commenced discussions to amend and extend the facility. Our credit ratios are within our debt covenants for both our credit facility and our outstanding senior notes. In addition, we are amortizing substantially all of our senior notes and have no immediate need to refinance. For a more complete discussion of factors that will affect our liquidity, please read “Item 1A. Risk Factors” in our Form 10-K for the year ended December 31, 2010. As of June 30, 2011, we had the full $300 million in available capacity under our credit facility. As of June 30, 2011, we also had approximately $145.7 million of cash.

Net cash provided by operations for the six months ended June 30, 2011 and 2010 was $138.7 million and $113.6 million, respectively. The most significant portion of our cash provided by operations is generated from coal royalty revenues.

Net cash used in investing activities for the six months June 30, 2011 and 2010 was $98.6 million and $112.5 million, respectively. Substantially all of our investing activities consisted of acquiring coal reserves, plant and equipment and other mineral rights.

Net cash flows provided by financing activities for the six months ended June 30, 2011 was $10.1 million. During the first six months of 2011, we had proceeds from loans of $335.0 million offset by repayment of debt of $202.8 million, retirement of obligations related to acquisitions of $4.0 million and distributions paid of $116.8 million. During the same period for 2010, net cash used in financing activities was $5.3 million, which included proceeds from loans of $81.0 million offset by debt repayments of $98.5 million, proceeds from issuance of units was $110.4 million, retirement of obligations related to acquisitions of $3.0 million and $97.4 million for distributions to partners.

Contractual Obligations and Commercial Commitments

Credit Facility. We have a $300 million revolving credit facility, and as of the date of this report we had the full amount 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.

During 2011, our borrowings and repayments under our credit facility were as follows:


	Quarters Ending
	March 31,		June 30,
	2011		2011
	(In thousands)
	(Unaudited)

Outstanding balance, beginning of period	$	94,000	$	179,000
Borrowings under credit facility		85,000		—
Less: Repayments under credit facility		—		179,000

Outstanding balance, ending period	$	179,000	$	—

Our obligations under the credit facility are unsecured but are guaranteed by our operating subsidiaries. We may prepay all loans at any time without penalty. Indebtedness under the revolving credit facility bears interest, at our option, at either:

	•		the higher of the federal funds rate plus an applicable margin ranging from 0% to 0.50% or the prime rate as announced by the agent bank; or

	•		at a rate equal to LIBOR plus an applicable margin ranging from 0.45% to 1.50%.

We incur a commitment fee on the unused portion of the revolving credit facility at a rate ranging from 0.10% to 0.30% per annum.

The credit agreement contains covenants requiring us to maintain:

•

a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) of 3.75 to 1.0 for the four most recent quarters; provided however, if during one of those quarters we have made an acquisition, then the ratio shall not exceed 4.0 to 1.0 for the quarter in which the acquisition occurred and (1) if the acquisition is in the first half of the quarter, the next two quarters or (2) if the acquisition is in the second half of the quarter, the next three quarters; and

•

a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of 4.0 to 1.0 for the four most recent quarters.

Senior Notes. NRP Operating LLC issued the senior notes listed below under a note purchase agreement as supplemented from time to time. 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 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.

In the second quarter of 2011, we issued $250 million of additional senior unsecured notes and are committed to issue another $50 million of senior unsecured notes in October 2011. Proceeds from the senior notes were used to repay all of the outstanding balance under the revolving credit facility, and we have used, or will use, the remaining proceeds for acquisitions.

A summary of the four tranches of senior notes is as follows:

Series

Amount

Interest Rate

Issue Date

Maturity

$75 million

4.73

April 20, 2011

December 1, 2023

$125 million

5.03

April 20, 2011

December 1, 2026

$50 million

5.03

June 15, 2011

December 1, 2026

$50 million

5.18

October 3, 2011

December 1, 2026

All tranches have semi-annual interest payments beginning December 1, 2011, and equal annual principal payments beginning December 1, 2014.

Long-Term Debt

As of the date of this filing, our debt consisted of:

	•		$35.0 million of 5.55% senior notes due 2013;

	•		$32.3 million of 4.91% senior notes due 2018;

	•		$150.0 million of 8.38% senior notes due 2019;

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

	•		$1.9 million of 5.31% utility local improvement obligation due 2021;

	•		$33.6 million of 5.55% senior notes due 2023;

	•		$75.0 million of 4.73% senior notes due 2023;

	•		$195.0 million of 5.82% senior notes due 2024;

	•		$50.0 million of 8.92% senior notes due 2024; and

	•		$175.0 million of 5.03% senior notes due 2026.

Other than the 5.55% senior notes due 2013, which have only semi-annual interest payments, all of our senior notes require annual principal payments in addition to semi-annual interest payments. The scheduled principal payments on the 8.38% senior notes due 2019 do not begin until March 2013, the scheduled principal payments on the 8.92% senior notes due 2024 do not begin until March 2014, and the scheduled principal payments on the 4.73% and 5.03% senior notes do not begin until December 2014. We also make annual principal and interest payments on the utility local improvement obligation.

Shelf Registration Statement

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.

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,
	2011		2010		2011		2010
	(In thousands)
	(Unaudited)

Reimbursement for services	$	2,091	$	1,789	$	4,153	$	3,580

For additional information, please read “Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement” in our annual report filed on Form 10-K for the year ended December 31, 2010.

We lease substantially all of two floors of an office building in Huntington, West Virginia from Western Pocahontas at market rates. The terms of the lease were approved by our Conflicts Committee. We pay $0.5 million each year in lease payments.

Transactions with Cline Affiliates

Various companies controlled by Chris Cline lease coal reserves from NRP, and we provide coal transportation services to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest in NRP’s general partner, as well as 16,686,672 common units. Revenues from Cline affiliates are as follows:


	Three Months End				Six Months End
	June 30,				June 30,
	2011		2010		2011		2010
	(In thousands)
	(Unaudited)

Coal royalty revenues	$	5,250	$	7,475	$	14,429	$	12,782
Coal processing fees		492		313		1,193		441
Transportation fees		3,745		3,992		7,844		6,400
Minimums recognized as revenue		—		3,100		—		6,200
Override revenue		228		277		679		719

	$	9,715	$	15,157	$	24,145	$	26,542

At June 30, 2011, we had accounts receivable totaling $3.1 million from Cline affiliates. As of June 30, 2011, we have received $58.4 million in minimum royalty payments to date that have not been recouped by Cline affiliates, of which $12.0 million was received in the current year.

Quintana Capital Group GP, Ltd.

Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd., which controls several private equity funds focused on investments in the energy business. In connection with the formation of Quintana Capital, 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 own and lease preparation plants to Taggart Global, which designed, built and operates the plants. The lease payments are based on the sales price for the coal that is processed through the facilities. We currently lease four facilities to Taggart. Revenues from Taggart are as follows:


	Three Months End				Six Months End
	June 30,				June 30,
	2011		2010		2011		2010
	(In thousands)
	(Unaudited)

Coal processing revenue	$	2,419	$	1,811	$	4,625	$	2,534

At June 30, 2011, we had accounts receivable totaling $1.4 million from Taggart.

In June 2007, a fund controlled by Quintana Capital acquired Kopper-Glo, a small coal mining company that is one of our lessees with operations in Tennessee. Revenues from Kopper-Glo are as follows:


	Three Months End				Six Months End
	June 30,				June 30,
	2011		2010		2011		2010
	(In thousands)
	(Unaudited)

Coal royalty revenue	$	419	$	379	$	753	$	832

We also had accounts receivable totaling $0.2 million from Kopper-Glo at June 30, 2011.

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, 2011. 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. 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, 2011, we did not have any 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 for the year ended December 31, 2010.

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


4.1	—	Form of Series J Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 15, 2011).

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*	—	The following financial information from the quarterly report on Form 10-Q of Natural Resource Partners L.P. for the quarter ended June 30, 2011, formatted in XBRL (eXtensible Business Reporting Language):
		(i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to Consolidated Financial Statements, tagged as blocks of text.


*		Submitted herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.


	NATURAL RESOURCE PARTNERS L.P.
	By:	NRP (GP) LP, its general partner
	By:	GP NATURAL RESOURCE PARTNERS LLC, its general partner

Date: August 5, 2011	By:	/s/ Corbin J. Robertson, Jr.
		Corbin J. Robertson, Jr., Chairman of the Board and Chief Executive Officer (Principal Executive Officer)

Date: August 5, 2011	By:	/s/ Dwight L. Dunlap
		Dwight L. Dunlap, Chief Financial Officer and Treasurer (Principal Financial Officer)


Date: August 5, 2011	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

Exhibits

EX-31.1 EX-31.2 EX-32.1 EX-32.2

NRP 10-Q Quarter ended June 30, 2011

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Exhibits