Natural Resource Partners (NRP) 10-Q 2006 Q2 Quarterly report

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, 2006

OR

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

Commission file number: 001-31465

NATURAL RESOURCE PARTNERS L.P.

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization) 35-2164875
(I.R.S. Employer
Identification No.)

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer

o Large Accelerated Filer                    þ Accelerated Filer                    o Non-accelerated Filer

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 3, 2006 there were outstanding 16,825,307 Common Units and 8,515,228 Subordinated Units.

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005		4
Consolidated Statements of Income For the Three and Six Months Ended June 30, 2006 and 2005		5
Consolidated Statements of Cash Flows For the Six Months Ended June 30, 2006 and 2005		6
Notes to Consolidated Financial Statements		7
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview		12
Results of Operations		15
Related Party Transactions		19
Liquidity and Capital Resources		20
Environmental		22
ITEM 3. Quantitative And Qualitative Disclosures About Market Risk		22
ITEM 4. Controls And Procedures		22
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings		24
ITEM 1A. Risk Factors		24
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds		24
ITEM 3. Defaults Upon Senior Securities		24
ITEM 4. Submission Of Matters to a Vote of Security Holders		24
ITEM 5. Other Information		24
ITEM 6. Exhibits		25
Signatures		26
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 1350
Certification of CFO Pursuant to Section 1350

2

Forward-Looking Statements

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

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

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

     You should not put undue reliance on any forward-looking statements. Please read “Item 1A Risk Factors” in this Form 10-Q and our Form 10-K for the year ended December 31, 2005 for important factors that could cause our actual results of operations or our actual financial condition to differ.

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Part I. Financial Information

Item 1. Financial Statements

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS
(In thousands, except for unit information)

	June 30,			December 31,
	2006			2005
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	52,620		$	47,691
Accounts receivable		22,051			21,946
Accounts receivable — affiliate		8			6
Other		590			833
Total current assets		75,269			70,476
Land		12,436			14,123
Plant and equipment, net		5,760			5,924
Coal and other mineral rights, net		626,858			590,459
Loan financing costs, net		2,266			2,431
Other assets, net		1,257			1,583
Total assets	$	723,846		$	684,996
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	659		$	677
Accounts payable — affiliate		86			88
Current portion of long-term debt		9,350			9,350
Accrued incentive plan expenses — current portion		4,763			1,105
Property, franchise and other taxes payable		3,833			4,138
Accrued interest		2,751			1,534
Total current liabilities		21,442			16,892
Deferred revenue		15,259			14,851
Accrued incentive plan expenses		3,247			5,395
Long-term debt		247,600			221,950
Partners’ capital:
Common units (outstanding: 16,825,307)		298,190			292,990
Subordinated units (outstanding: 8,515,228)		126,029			123,114
General partners’ interest		11,559			10,024
Holders of incentive distribution rights		1,296			582
Accumulated other comprehensive loss		(776	)		(802	)
Total partners’ capital		436,298			425,908
Total liabilities and partners’ capital	$	723,846		$	684,996

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

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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,
	2006			2005			2006			2005
	(Unaudited)
Revenues:
Coal royalties	$	36,527		$	37,957		$	75,637		$	70,487
Oil and gas royalties		928			610			2,647			1,070
Property taxes		1,546			1,547			3,295			2,981
Minimums recognized as revenue		250			481			621			934
Override royalties		181			209			484			824
Other		1,550			893			4,826			1,648
Total revenues		40,982			41,697			87,510			77,944
Operating costs and expenses:
Depreciation, depletion and amortization		7,236			8,625			15,089			16,504
General and administrative		3,420			3,162			7,535			6,474
Property, franchise and other taxes		2,099			1,954			4,344			3,784
Coal royalty and override payments		263			745			954			1,298
Total operating costs and expenses		13,018			14,486			27,922			28,060
Income from operations		27,964			27,211			59,588			49,884
Other income (expense)
Interest expense		(3,675	)		(2,570	)		(7,293	)		(5,027	)
Interest income		755			331			1,273			562
Net income	$	25,044		$	24,972		$	53,568		$	45,419
Net income attributable to: (1)
General partner	$	2,253		$	1,155		$	4,348		$	1,985
Other holders of incentive distribution rights	$	943		$	353		$	1,764		$	580
Limited partners	$	21,848		$	23,464		$	47,456		$	42,854
Basic and diluted net income per limited partner unit:
Common	$	.86		$	.92		$	1.87		$	1.69
Subordinated	$	.86		$	.92		$	1.87		$	1.69
Weighted average number of units outstanding:
Common		16,825			13,987			16,825			13,987
Subordinated		8,515			11,354			8,515			11,354

⁽¹⁾ Net Income is allocated among the limited partners, the general partner and holders of the incentive distribution rights (IDRs) based upon their pro rata share of distributions. The IDRs are allocated 65% to the general partner and the remaining 35% to affiliates of the general partner. The IDRs allocated to the general partner are included in the net income attributable to the general partner.

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

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NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

	Six months ended
	June 30,
	2006			2005
	(Unaudited)
Cash flows from operating activities:
Net income	$	53,568		$	45,419
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		15,089			16,504
Non-cash interest charge		191			125
Gain from sale of assets		(2,634	)		—
Change in operating assets and liabilities:
Accounts receivable		(107	)		(3,369	)
Other assets		243			601
Accounts payable		(20	)		(124	)
Accrued interest		1,217			169
Deferred revenue		408			(2,331	)
Accrued incentive plan expenses		1,510			1,224
Property, franchise and other taxes payable		(305	)		(770	)
Net cash provided by operating activities		69,160			57,448
Cash flows from investing activities:
Acquisition of land, plant and equipment, coal and other mineral rights		(51,438	)		(21,544	)
Proceeds from sale of assets		4,761			—
Net cash used in investing activities		(46,677	)		(21,544	)
Cash flows from financing activities:
Proceeds from loans		50,000			18,000
Repayment of loans		(24,350	)		(9,350	)
Distributions to partners		(43,204	)		(35,897	)
Net cash used in financing activities		(17,554	)		(27,247	)
Net increase in cash and cash equivalents		4,929			8,657
Cash and cash equivalents at beginning of period		47,691			42,103
Cash and cash equivalents at end of period	$	52,620		$	50,760
Supplemental cash flow information:
Cash paid during the period for interest	$	5,861		$	4,712

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

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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, 2006 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 2005 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 and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. The Partnership does not operate any mines. The Partnership leases coal reserves through its wholly owned subsidiary, NRP (Operating) LLC, (“NRP Operating”), to experienced mine operators under long-term leases that grant the operators the right to mine the Partnership’s coal reserves in exchange for royalty payments. The Partnership’s lessees are generally required to make payments to the Partnership based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, in addition to a minimum payment.

     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. Summary of Significant Accounting Policies

Reclassification

     Certain reclassifications have been made to the prior year’s financial statements to conform to current year classifications.

Share-Based Payment

     The Partnership adopted Statement of Financial Accounting Standards No. 123R “Share-Based Payment,”effective January 1, 2006 using the modified prospective approach. Prior to 2006, awards under our Long Term Incentive Plan have been accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R provides that grants must be accounted for using the fair value method which requires us to estimate the fair value of the grant and charge the estimated fair value to expense over the service or vesting period of the grant. In addition, FAS 123R requires that we include estimated forfeitures in our periodic computation of the fair value of the liability and that the fair value be recalculated at each reporting date over the service or vesting period of the grant. FAS 123R required us to recognize the cumulative effect of the accounting change at the date of adoption based on the difference between the fair value of the unvested awards and the intrinsic value previously recorded. Included in operating costs and expenses was a one time charge of $661,000 which represents the cumulative effect of adopting FAS 123R as of January 1, 2006. This adjustment had the impact of reducing net income per unit for the six month period ended June 30, 2006 by $0.02. Application of FAS 123R to prior periods did not materially impact amounts previously presented.

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3. Plant and Equipment

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

	June 30,		December 31,
	2006		2005
	(In thousands)
	(Unaudited)
Plant and equipment at cost	$	6,019	$	6,019
Accumulated depreciation		259		95
Net book value	$	5,760	$	5,924

	Six months ended
	June 30,
	2006		2005
	(In thousands)
	(Unaudited)
Total depreciation expense on plant and equipment	$	164	$	—

4. Coal and Other Mineral Rights

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

	June 30,			December 31,
	2006			2005
	(In thousands)
	(Unaudited)
Coal and other mineral rights	$	784,896		$	734,242
Less accumulated depletion and amortization		(158,038	)		(143,783	)
Net book value	$	626,858		$	590,459

	Six months ended
	June 30,
	2006		2005
	(In thousands)
	(Unaudited)
Total depletion and amortization expense on coal interests	$	14,599	$	16,020

8

5. Long-Term Debt

     Long-term debt consists of the following:

	June 30,			December 31,
	2006			2005
	(In thousands)
	(Unaudited)
$175 million floating rate revolving credit facility, due October 2010	$	10,000		$	25,000
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023		50,100			53,400
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018		61,850			67,900
5.55% senior notes, with semi-annual interest payments in June and December, maturing June 2013		35,000			35,000
5.05% senior notes, with semi-annual interest payments in January and July, with scheduled principal payments beginning July 2008, maturing in July 2020		100,000			50,000
Total debt		256,950			231,300
Less — current portion of long term debt		(9,350	)		(9,350	)
Long-term debt	$	247,600		$	221,950

     At June 30, 2006, the Partnership had an outstanding balance of $10.0 million on its revolving credit facility, and the weighted average interest rate on the outstanding balance was 5.97%. The Partnership incurs a commitment fee on the revolving credit facility at rates ranging from 0.15% to 0.40% per annum.

     The Partnership was in compliance with all terms under its long-term debt as of June 30, 2006.

6. Net Income Per Unit Attributable to Limited Partners

     Net income per unit attributable to limited partners is based on the weighted-average number of common and subordinated units outstanding during the period and is allocated in the same ratio as quarterly cash distributions are made. Net income per unit attributable to limited partners is computed by dividing net income attributable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, by the weighted-average number of limited partnership units outstanding. Basic and diluted net income per unit attributable to limited partners are the same since the Partnership has no potentially dilutive securities outstanding.

7. Related Party Transactions

     Quintana Minerals Corporation, a company controlled by Corbin J. Robertson, Jr., Chairman and CEO of GP Natural Resource Partners LLC, provided certain administrative services to the Partnership and charged it for direct costs related to the administrative services. Total expenses charged to the Partnership under this arrangement were $0.2 million and $0.1 million for the three month periods ended June 30, 2006 and 2005, respectively, and $0.4 million for each of the six month periods ended June 30, 2006 and 2005. These costs are reflected in general and administrative expenses in the accompanying statements of income. At June 30, 2006, the Partnership also had accounts payable to affiliates of $0.1 million, which includes general and administrative expense payable to Quintana Minerals Corporation.

     Western Pocahontas Properties Limited Partnership provides certain administrative services for the Partnership. Total expenses charged to the Partnership under this arrangement were $0.8 million and $0.7 million for the three month periods ended June 30, 2006 and 2005, respectively, and $1.6 million and $1.3 million for the six month periods ended June 30, 2006 and 2005, respectively. These costs are reflected in general and administrative expenses in the accompanying statements of income.

8. Commitments and Contingencies

Legal

     The Partnership is involved, from time to time, in various other 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.

9

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 coal 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, 2006. The Partnership is not associated with any environmental contamination that may require remediation costs.

9. Major Lessees

     Coal royalty revenues from major lessees that exceeded ten percent of total revenues for the periods indicated below are as follows:

	Three months ended										Six months ended
	June 30,										June 30,
	2006					2005					2006					2005
	Revenues		Percent			Revenues		Percent			Revenues		Percent			Revenues		Percent
	Dollars in thousands										Dollars in thousands
	(Unaudited)										(Unaudited)
Lessee A	$	3,612		9	%	$	4,869		11	%	$	7,425		8	%	$	8,927		11	%
Lessee B		5,530		13	%		5,241		13	%		11,371		13	%		10,027		13	%
Lessee C		2,766		7	%		4,046		13	%		5,512		6	%		8,859		11	%
Lessee D		3,101		8	%		4,881		13	%		7,160		8	%		8,207		11	%

10. Incentive Plans

     GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the “Long-Term Incentive Plan”) for employees and directors of GP Natural Resource Partners LLC and its affiliates who perform services for the Partnership. The compensation 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 determined by taking the average closing price over the last 20 trading days prior to the vesting date. The compensation 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 compensation committee provides otherwise.

10

     A summary of activity in the outstanding grants of the Partnership for the first six months of 2006 are as follows:

Outstanding grants at the beginning of the period	211,931
Grants during the period	61,166
Grants vested during the period	(13,947	)
Forfeitures during the period	—
Outstanding grants at the end of the period	259,150

     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 4.97% to 5.10% and 22.43% to 25.85%, respectively at June 30, 2006. The Partnership’s historic dividend rate of 5.23% was used in the calculation at June 30, 2006. The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $0.9 million and $1.0 million for the three months ended June 30, 2006 and 2005, respectively, and $2.2 million and $2.0 million for the six month periods ended June 30, 2006 and 2005, respectively, including $661,000 in the first quarter of 2006 related to the cumulative effect of the change in accounting method discussed above. In connection with the Long-Term Incentive Plans, cash payments of $0.8 million were paid during each of the six month periods ended June 30, 2006 and 2005. The unaccrued cost associated with the outstanding grants at June 30, 2006 was $7.4 million.

11. Distributions

     On May 12, 2006, the Partnership paid a cash distribution equal to $0.79 per unit, or $3.16 on an annualized basis, to unitholders of record on May 1, 2006.

12. Subsequent Events

Distributions

     On July 19, 2006, the Partnership announced a $0.03 per unit increase in its quarterly distribution to $0.82 per unit, or $3.28 per unit on an annualized basis. The distribution is payable on August 14, 2006 to unitholders of record on August 1, 2006.

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

     The following discussion of the financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included elsewhere in this filing and the financial statements and footnotes included in the Natural Resource Partners L.P.Form 10-K, as filed on February 27, 2006.

Executive Overview

     We engage principally in the business of owning and managing coal properties in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States. As of December 31, 2005, we owned or controlled approximately two billion tons of proven and probable coal reserves in eleven states and we are now the only company with coal reserves that run the entire length of the Appalachian coal chain. For the six months ended June 30, 2006, approximately 56% of the coal produced from our properties came from underground mines and approximately 44% came from surface mines.

     We lease coal reserves under long-term leases that grant the operators the right to mine our coal reserves in exchange for royalty payments. As of June 30, 2006, our reserves were subject to 178 leases with 67 lessees. For the six months ended June 30, 2006, our lessees produced 27.4 million tons of coal generating $75.6 million in coal royalty revenues from our properties and our total revenue was $87.5 million. Most of our coal is produced by large companies, many of which are publicly traded, with professional and sophisticated sales departments. A significant portion of our coal is sold by our lessees under coal supply contracts that have terms of one year or more. However, over the long term, our coal royalty revenues are affected by changes in the market price of coal.

     Our revenue and profitability are dependent on our lessees’ ability to mine and market our coal reserves. Generally, our lessees make payments to us based on the greater of a percentage of the gross sales price or a fixed price per ton of coal they sell, subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time (usually three to five years) if sufficient royalties are generated from coal production in future periods. We do not recognize these minimum coal royalties as revenue until the applicable recoupment period has expired or they are recouped through production. Until recognized as revenue, these minimum royalties are recorded as deferred revenue, a liability on our balance sheet.

     As of December 31, 2005, approximately 57% of our reserves were low sulfur coal, including compliance coal, which constitutes approximately 35% of our total reserves. In 2005 and the first half of 2006, we continued to diversify geographically by significantly expanding our presence in the high-sulfur regions of the Illinois Basin and Northern Appalachia, which we see as being the next regions that will experience increased coal production. We expect the Williamson Development property in Illinois to be one of our largest producing leases once it has reached full production, which we anticipate in 2007. As utilities add scrubbers to existing power plants in response to more stringent environmental rules, we expect to see an increased demand for mid- to high-sulfur coal. We believe that our recent acquisitions are an important step in our strategy to continue to diversify our assets, and that we are well-positioned to take advantage of future expansion opportunities in these regions.

     As a result of the escalating coal prices over the last few years, we have received substantially higher royalties from our leases, and our coal royalty revenue per ton has increased dramatically during that period. Over the past six months, we have seen some indications coal prices are softening and some have declined slightly following a mild winter and increased stockpiles at the utilities. We believe that although any weakness in pricing is temporary, in the near term prices will not return to the record high levels we have experienced over the last two years. As a result, we expect that our coal royalty revenue per ton will increase at a much slower rate, if at all, over the next few years and that over the long-term a larger percentage of our future revenue growth will come from acquisitions of new reserves.

     For the six months ended June 30, 2006, approximately 28% of our coal royalty revenues and 22% of the related production were from metallurgical coal, which was sold to steel companies in the eastern United States, South America, Europe and Asia. Prices of metallurgical coal have been substantially higher over the last two years and we expect them to remain at historically high levels in 2006 as well. Metallurgical coal, because of its unique chemical characteristics, is usually priced higher than steam coal. The current pricing environment for U.S. metallurgical coal is strong in both the domestic and seaborne export markets.

     In addition to coal royalty revenues, we generated approximately 6% and 3% of our revenues for the six months ended June 30, 2006 and 2005, respectively, from rentals; royalties on oil and gas and coalbed methane leases; timber; overriding royalty arrangements; and wheelage payments, which are toll payments for the right to transport third-party coal over or through our property.

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     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 critical 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.

     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,
	2006			2005			2006			2005
	(Unaudited)
Cash flow from operations	$	32,510		$	31,378		$	69,160		$	57,448
Less scheduled principal payments		(9,350	)		(9,350	)		(9,350	)		(9,350	)
Less reserves for future principal payments		(2,350	)		(2,350	)		(4,700	)		(4,700	)
Add reserves used for scheduled principal payments		9,400			9,400			9,400			9,400
Distributable cash flow	$	30,210		$	29,078		$	64,510		$	52,798

Acquisitions

     2006 Acquisitions

     Williamson Development. On January 20, 2006, we closed the second phase of the Williamson Development acquisition for $35 million. We funded this acquisition with senior notes and we expect to close the third and final phase in the third quarter of 2006.

     James River. On May 26, 2006, we acquired 16.3 million tons of coal reserves and an overriding royalty interest on an additional 2.4 million tons for $10.85 million from James River Coal Company. These reserves are located in Pike, Warrick and Gibson Counties in Indiana. We funded this acquisition with cash.

     Allegany County, Maryland. On June 29, 2006, we closed an acquisition for $5.5 million consisting of 3.3 million tons of coal in Allegany County, Maryland. We funded this acquisition with cash.

     2005 Acquisitions

     Plum Creek.On March 3, 2005, we completed an acquisition of coal reserves from Plum Creek Timber Company, Inc. for $21.25 million. This property consists of approximately 85 million tons of coal reserves located on approximately 175,000 acres in Virginia, West Virginia and Kentucky with most of the reserves leased under 29 leases.

     Williamson Development.On June 1, 2005, we signed a definitive agreement to purchase interests in approximately 144 million tons in the Illinois Basin for $105 million in three separate transactions. We will acquire approximately 60% of the reserves in fee and will receive an override on the remaining tons. On July 11, 2005, we closed the first of the three transactions for $35 million.

     Dolphin. On September 22, 2005, we acquired a coal preparation plant and rail load-out facility in Greenbrier County, West Virginia for $6 million. The facilities will process coal produced primarily from our Plum Creek properties.

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     Area F/Lexington. In two separate transactions on September 26, 2005, we acquired approximately 25 million tons of owned coal reserves and an overriding royalty on approximately 14 million tons of leased coal reserves in Randolph, Upshur and Barbour Counties in north central West Virginia for $13.5 million.

     AFG.On November 21, 2005, we completed the acquisition of 179 million tons of coal reserves in Ohio and Pennsylvania for $29 million.

Disposition

     Virginia Timber Properties.On May 31, 2006, we closed the second of three related transactions involving the sale of timber and related surface acreage located on our property in Wise and Dickenson Counties, Virginia. We received proceeds of $0.8 million from the second closing, resulting in a gain of $0.5 million. For the six months ended June 30, 2006, we received total proceeds of $4.8 million related to these transactions and recorded a total gain of $2.6 million. The third phase of this transaction is scheduled to close later in 2006.

Impact of Adoption of FAS 123R

     We adopted Statement of Financial Accounting Standards No. 123R “Share-Based Payment,” effective January 1, 2006 using the modified prospective approach. Prior to 2006, awards under our Long Term Incentive Plan have been accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R provides that grants must be accounted for using the fair value method which requires us to estimate the fair value of the grant and charge the estimated fair value to expense over the service or vesting period of the grant. In addition, FAS 123R requires that we include estimated forfeitures in our periodic computation of the fair value of the liability and that the fair value be recalculated at each reporting date over the service or vesting period of the grant. FAS 123R required us to recognize the cumulative effect of the accounting change at the date of adoption based on the difference between the fair value of the unvested awards and the intrinsic value previously recorded. Included in operating costs and expenses was a one time charge of $661,000 which represents the cumulative effect of adopting FAS 123R as of January 1, 2006. This adjustment had the impact of reducing net income per unit for the six month period ended June 30, 2006 by $0.02. Application of FAS 123R to prior periods did not materially impact amounts previously presented.

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Results of Operations

Natural Resource Partners L.P.

	Three months ended						Six months ended
	June 30,						June 30,
	2006			2005			2006			2005
	(In thousands, except per ton data)
	(Unaudited)
Revenues:
Coal royalties	$	36,527		$	37,957		$	75,637		$	70,487
Oil and gas royalties		928			610			2,647			1,070
Property taxes		1,546			1,547			3,295			2,981
Minimums recognized as revenue		250			481			621			934
Override royalties		181			209			484			824
Other		1,550			893			4,826			1,648
Total revenues		40,982			41,697			87,510			77,944
Operating costs and expenses:
Depreciation, depletion and amortization		7,236			8,625			15,089			16,504
General and administrative		3,420			3,162			7,535			6,474
Property, franchise and other taxes		2,099			1,954			4,344			3,784
Coal royalty and override payments		263			745			954			1,298
Total expenses		13,018			14,486			27,922			28,060
Income from operations		27,964			27,211			59,588			49,884
Other income (expense):
Interest expense		(3,675	)		(2,570	)		(7,293	)		(5,027	)
Interest income		755			331			1,273			562
Net income	$	25,044		$	24,972		$	53,568		$	45,419
Other Data:
Coal royalties
Appalachia
Northern	$	2,730		$	2,105		$	6,038		$	4,569
Central		24,543			25,894			50,385			48,072
Southern		5,133			6,346			10,617			11,357
Total Appalachia		32,406			34,345			67,040			63,998
Illinois Basin		1,704			1,093			3,656			2,400
Northern Powder River Basin		2,417			2,519			4,941			4,089
Total	$	36,527		$	37,957		$	75,637		$	70,487
Production (tons)
Appalachia
Northern		1,482			1,108			3,214			2,416
Central		7,982			8,958			16,176			17,197
Southern		1,436			1,675			2,862			2,999
Total Appalachia		10,900			11,741			22,252			22,612
Illinois Basin		977			707			2,140			1,574
Northern Powder River Basin		1,497			1,665			2,998			2,697
Total		13,374			14,113			27,390			26,883
Average gross royalty per ton
Appalachia
Northern	$	1.84		$	1.90		$	1.88		$	1.89
Central		3.07			2.89			3.11			2.80
Southern		3.58			3.79			3.71			3.79
Total Appalachia		2.97			2.93			3.01			2.83
Illinois Basin		1.74			1.55			1.71			1.52
Northern Powder River Basin		1.61			1.51			1.65			1.52
Total	$	2.73		$	2.69		$	2.76		$	2.62

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Three months ended June 30, 2006 compared with three months ended June 30, 2005

     Revenues. For the three months ended June 30, 2006, coal royalty revenues were $36.5 million on 13.4 million tons of coal produced, compared to $38.0 million in coal royalty revenues on 14.1 million tons of coal produced for the second quarter of 2005, representing a 4% decrease in coal royalty revenues and a 5% decrease in production. Coal royalty revenues comprised approximately 89% and 91% of our total revenue for each of the three month periods ended June 30, 2006 and 2005, while property taxes, minimums recognized as revenue, override royalties and other, comprised the remaining 11% and 9% of our total revenue for those periods.

     The following is a breakdown of our major coal producing regions:

     Appalachia.Primarily as a result of lower production, coal royalty revenues in Appalachia for the quarter ended June 30, 2006 were $32.4 million compared to $34.3 million for the same period in 2005, a decrease of $1.9 million or 6%. For the quarter ended June 30, 2006, production in Appalachia was 10.9 million tons compared to 11.7 million tons for the same period in 2005, a decrease of 0.8 million tons or 7%. The Appalachian results by region are set forth below.

     Northern Appalachia. Primarily as a result of the acquisition of the AFG properties in 2005, our coal royalty revenues increased 29% from $2.1 million for the quarter ended June 30, 2005 to $2.7 million for the quarter ended June 30, 2006. Production increased 36% from 1.1 million tons to 1.5 million tons over the same periods. The properties acquired with the AFG acquisition generated coal royalty revenues of $1.9 million and production of 1.1 million tons. In addition to the properties acquired with the AFG acquisition, the following property experienced a significant variance.

• Sincell — production decreased from 661,000 tons to 85,000 tons and coal royalty revenues decreased from $1.1 million to $158,000. The decreased tonnage was due to a greater proportion of production from the longwall unit being on adjacent property.

     Central Appalachia. Production from our Central Appalachia properties decreased 11% from 9.0 million tons for the quarter ended June 20, 2005 to 8.0 million tons for the quarter ended June 30, 2006 and our coal royalty revenues from these properties decreased 5.4% from $25.9 million to $24.5 million over those same periods. The results in Central Appalachia are a combination of increases and decreases over a number of properties, the most significant of which are described below.

• VICC/Kentucky Land — production increased from 758,000 tons to 899,000 tons and coal royalty revenues increased from $2.5 million to $3.3 million. The increased production was due to an increase in tonnage from mines moving onto the property that more than offset mines moving off the property.

• Plum Creek properties — production increased from 174,000 tons to 452,000 tons and coal royalty revenues increased from $541,000 to $1.2 million. The increased production was due primarily to new mines in West Virginia increasing production on the properties.

• Pinnacle — production decreased from 788,000 tons to 533,000 tons and coal royalty revenues decreased from $3.3 million to $1.8 million. The decreased tonnage was due to a greater proportion of production from the mines being on adjacent property.

• Eunice — production decreased from 781,000 tons to 222,000 tons and coal royalty revenues decreased from $1.9 million to $789,000 due to a greater proportion of production from both the longwall mine and the surface mine coming from adjacent property.

• Eastern Kentucky Property— production decreased from 224,000 tons to zero tons and coal royalty revenues decreased from $742,000 to zero. The decreased production was due to the lessee temporarily idling the operation. We are currently working with the lessee and a possible replacement operator to resume production.

     Southern Appalachia. Our coal royalty revenues in Southern Appalachia decreased 19% from $6.3 million for the quarter ended June 30, 2005 to $5.1 million for the quarter ended June 30, 2006, as production decreased 17.6% from 1.7 million tons to 1.4 million tons over those same periods. The following properties contributed to these results.

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• Twin Pines/Drummond — production increased from 136,000 tons to 152,000 tons but coal royalty revenues decreased from $1.2 million to $744,000. The decreased royalty revenue was due to a temporary royalty reduction to partially offset the acquisition of surface property by the operator that allowed our coal to be mined.

• BLC Properties — production decreased from 1.1 million tons to 929,000 tons and coal royalty revenues decreased from $3.5 to $3.0 million. The decrease was due to slightly reduced production and some temporary royalty reduction to one lessee to encourage mining in some areas of difficult geology.

• Oak Grove — production decreased from 457,000 tons to 354,000 tons and coal royalty revenues decreased from $1.5 million to $1.3 million. The decreases were due to slightly lower production from the mine, which was partially offset by higher sales prices received by our lessee.

     Illinois Basin. Production in the Illinois Basin increased 0.3 million tons or 43% from 0.7 million tons for the quarter ended June 30, 2005 to 1.0 million tons for the quarter ended June 30, 2006 and coal royalty revenues increased $0.6 million or 55% from $1.1 million for the quarter ended June 30, 2005 to $1.7 million for the quarter ended June 30, 2006. The following properties experienced significant variances.

• Hocking Wolford/Cummings — production increased from 360,000 tons to 588,000 tons and coal royalty revenues increased from $498,000 to $897,000. The increases were due to a greater proportion of the production from the mine being on our property.

• Sato — production increased from 267,000 tons to 312,000 tons and coal royalty revenues increased from $458,000 to $676,000. The increases were due to slight increase in production from the mine and higher sales price received by our lessee.

     Northern Powder River Basin. Production from our Western Energy property decreased 0.2 million tons or 12% from 1.7 million tons to 1.5 million tons and coal royalty revenues decreased $0.1 million or 4% from $2.5 million to $2.4 million. These decreases were due to the typical variations in production resulting from the checkerboard ownership pattern.

     Other revenues.Included in other revenues is the sale of timber and related surface acreage located on our property in Wise and Dickenson Counties, Virginia. We received proceeds from the sale of $0.8 million, resulting in a gain of $0.5 million. This closing represents the second of three related transactions. The remaining transaction is expected to close in the second half of 2006.

     Operating costs and expenses.For the quarter ended June 30, 2006, total expenses were $13.0 million, compared to $14.5 million for the second quarter of 2005, representing a decrease of $1.5 million, or 10%. Included in total expenses are:

• Depletion and amortization of $7.2 million for the quarter ended June 30, 2006 compared to $8.6 million for the same period in 2005. This was primarily attributed to a reduction in overall production;

• General and administrative expenses of $3.4 million for the second quarter of 2006, compared to $3.2 million for the second quarter of 2005, an increase of $0.2 million, or 6%. The increase in general and administrative expenses is attributable to additional expenses required to manage a larger portfolio of properties as well as an increase in incentive compensation accrual; and

• Property, franchise and other taxes of $2.1 million for the second quarter of 2006, compared to $2.0 million for the second quarter of 2005, an increase of $0.1 million, or 5%, due to an increase in franchise taxes for 2006, as well as taxes on additional properties acquired since the first quarter last year.

     Interest Expense.For the quarter ended June 30, 2006, interest expense was $3.7 million compared to $2.6 million for 2005, an increase of $1.1 million. This increase is attributed to additional borrowings on our senior notes during the third quarter of 2005 and the first quarter of 2006, partially offset by lower outstanding balances on our credit facility.

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Six months ended June 30, 2006 compared with six months ended June 30, 2005

     Revenues. For the six months ended June 30, 2006, coal royalty revenues were $75.6 million on 27.4 million tons of coal produced, compared to $70.5 million in coal royalty revenues on 26.9 million tons of coal produced for the six months ended June 30, 2005, representing a 7% increase in coal royalty revenues and a 2% increase in production. Coal royalty revenues comprised approximately 86% and 90% of our total revenue for each of the six month periods ended June 30, 2006 and 2005, while property taxes, minimums recognized as revenue, override royalties and other, comprised the remaining 14% and 10% of our total revenue for those periods.

     The following is a breakdown of our major coal producing regions:

     Appalachia.Primarily as a result of higher prices, coal royalty revenues in Appalachia for the six months ended June 30, 2006 were $67.0 million compared to $64.0 million for the same period in 2005, an increase of $3.0 million or 5%. For the six months ended June 30, 2006, production in Appalachia was 22.3 million tons compared to 22.6 million tons for the same period in 2005, a decrease of 0.3 million tons or 1%. The Appalachian results by region are set forth below.

     Northern Appalachia. Primarily as a result of the acquisition of the AFG properties in 2005, our coal royalty revenues increased 30% from $4.6 million for the six months ended June 30, 2005 to $6.0 million for the six months ended June 30, 2006. Production increased 33% from 2.4 million tons to 3.2 million tons over the same periods. The properties acquired with the AFG acquisition generated coal royalty revenues of $3.7 million and production of 2.0 million tons. In addition to the properties acquired with the AFG acquisition, the following property experienced a significant variance.

• Sincell — production decreased from 1.5 million tons to 493,000 tons and coal royalty revenues decreased from $2.7 million to $814,000. The decreased tonnage was due to a greater proportion of production from the longwall unit being on adjacent property.

     Central Appalachia. Production from our Central Appalachia properties decreased 6% from 17.2 million tons for the six months ended June 30, 2005 to 16.2 million tons for the six months ended June 30, 2006. However, as a result of higher prices our coal royalty revenues from these properties increased 5% from $48.1 million to $50.4 million over those same periods. The results in Central Appalachia are a combination of increases and decreases over a number of properties, the most significant of which are described below.

• VICC/Kentucky Land — production increased from 1.3 million tons to 1.8 million tons and coal royalty revenues increased from $4.3 million to $6.5 million. The increased production was due to an increase in tonnage from mines moving onto the property that more than offset mines moving off the property.

• Lynch — production increased from 2.6 million tons to 2.7 million tons and coal royalty revenues increased from $5.6 million to $6.9 million. The increased tonnage was due to a new mine starting on our property.

• VICC/Alpha — production decreased slightly from 3.3 million tons to 3.2 million tons and coal royalty revenues increased from $8.4 million to $9.7 million. The increased coal royalty revenues were due to higher sales prices being realized by our lessees.

• Kingston — production increased from 804,000 tons to 976,000 tons and coal royalty revenues increased from $2.2 million to $3.0 million. The increased tonnage was due to additional producing units being on our property and a new surface mine increasing production.

• Plum Creek properties — production increased from 253,000 tons to 723,000 tons and coal royalty revenues increased from $723,000 to $1.8 million. The increased production was due primarily to new mines in West Virginia increasing production on the properties.

• Pinnacle — production decreased from 1.4 million tons to 1.2 million tons and coal royalty revenues decreased from $5.3 million to $4.3 million. The decreases were primarily due to a greater proportion of production from the mines being on adjacent property and slightly lower prices being received by our lessee.

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• Eunice — production decreased from 1.7 million tons to 500,000 tons and coal royalty revenues decreased from $4.3 million to $1.8 million due to a greater proportion of production from both the longwall mine and the surface mine coming from adjacent property.

• Eastern Kentucky Property— production decreased from 353,000 tons to 42,000 tons and coal royalty revenues decreased from $1.1 million to $186,000. The decreased production was due to the lessee temporarily idling the operation. We are currently working with the lessee and a possible replacement operator to resume production.

     Southern Appalachia. Our coal royalty revenues in Southern Appalachia decreased 7% from $11.4 million for the six months ended June 30, 2005 to $10.6 million for the six months ended June 30, 2006, as production decreased 3% from 3.0 million tons to 2.9 million tons over the same period. The following property contributed to this decrease.

• BLC Properties — production decreased from 1.9 million tons to 1.8 million tons and coal royalty revenues decreased from $6.5 to $6.0 million. The decrease was due to slightly reduced production and some temporary royalty reduction to one lessee to encourage mining in some areas of difficult geology.

     Illinois Basin. Production in the Illinois Basin increased 31% from 1.6 million tons for the six months ended June 30, 2005 to 2.1 million tons for the six months ended June 30, 2006 and coal royalty revenues increased 54% from $2.4 million for the six months ended June 30, 2005 to $3.7 million for the six months ended June 30, 2006. The significant increase came from Hocking-Wolford/Cummings tract where production increased from 812,000 tons to 1.4 million tons and coal royalty revenues increased from $1.1 million to $2.2 million. This increase in tonnage was due to a greater proportion of the production being on our property.

     Northern Powder River Basin. Production from our Western Energy property increased 0.3 million tons or 11% from 2.7 million tons to 3.0 million tons and coal royalty revenues increased $0.8 million or 20% from $4.1 million to $4.9 million. These increases were due to the typical variations in production resulting from the checkerboard ownership pattern.

     Other revenues.Included in other revenues are two related sales of timber and related surface acreage located on our property in Wise and Dickenson Counties, Virginia. We received proceeds from the sales of $4.8 million, resulting in a gain of $2.6 million. A third related transaction in the amount of approximately $1.5 million to $2.0 million is expected to close in the second half of 2006.

     Operating costs and expenses.For the six months ended June 30, 2006, total expenses were $27.9 million, compared to $28.1 million for the first six months of 2005, representing a decrease of $0.2 million, or 1%. Included in total expenses are:

• Depletion and amortization of $15.1 million for the six months ended June 30, 2006 compared to $16.5 million for the same period in 2005, representing a decrease of $1.4 million. Fluctuations in depletion are dependent on the depletion rates where coal is mined and can cause total depletion to be lower in periods where production is actually up;

• General and administrative expenses of $7.5 million for the first half of 2006, compared to $6.5 million for the six months ended June 30, 2005, an increase of $1.0 million, or 15%. The increase in general and administrative expenses is attributable to additional expenses required to manage a larger portfolio of properties as well as an increase in incentive compensation accrual partially attributable to the adoption of FAS 123R; and

• Property, franchise and other taxes of $4.3 million for the first half of 2006, compared to $3.8 million for the first half of 2005, an increase of $0.5 million, or 13%, due to an increase in franchise taxes for 2006, as well as taxes on additional properties acquired since the first quarter last year.

     Interest Expense.For the six months ended June 30, 2006, interest expense was $7.3 million compared to $5.0 million for 2005, an increase of $2.3 million. This increase is attributed to additional borrowings on our senior notes during the third quarter of 2005 and the first quarter of 2006, partially offset by lower outstanding balances on our credit facility.

Related Party Transactions

Partnership Agreement

     Our general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with our partnership agreement, our general partner and its affiliates are reimbursed for expenses incurred on our behalf. All direct general and administrative expenses are charged to us as incurred. We also reimburse indirect

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general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates. Reimbursements to affiliates of our general partner may be substantial and will reduce our cash available for distribution to unitholders. The reimbursements to affiliates of our general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation totaled $1.0 million and $0.8 million for the three month periods ended June 30, 2006 and 2005, respectively, and $2.0 million and $1.7 million for the six month periods ended June 30, 2006 and 2005, respectively.

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 through borrowings under our revolving credit facility, the issuance of our senior notes and the issuance of additional common units and cash. We believe that cash generated from our operations, combined with the availability under our credit facility and the proceeds from the issuance of debt and equity, will be sufficient to fund working capital, capital expenditures and future acquisitions. Our ability to satisfy debt service obligations, fund planned capital expenditures, make acquisitions and pay distributions to our unitholders will depend upon our ability to access the capital markets, as well as our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control. For a more complete discussion of factors that will affect the amount of cash we generate from our operations, please read “Item 1A — Risk Factors” in this Form 10-Q and our Form 10-K for the year ended December 31, 2005. Our capital expenditures, other than for acquisitions, have historically been minimal.

     Net cash provided by operations for the six months ended June 30, 2006 and 2005 was $69.2 million and $57.4 million, respectively. Substantially all of our cash provided by operations is generated from coal royalty revenues.

     Net cash used in investing activities for the six months ended June 30, 2006 was $46.7 million compared to $21.5 million for the same period in 2005. The 2006 results include the funding of the second phase of the Williamson Development acquisition for $35 million, the James River acquisition for $10.85 million and the Allegany County acquisition for $5.5 million. These acquisitions were partially offset by the proceeds from the sale of our Virginia timber assets and related surface tracts for $4.8 million. The 2005 results include the acquisition of coal reserves from Plum Creek Timber Company, Inc. for $21.3 million.

     Net cash used in financing activities for the six months ended June 30, 2006 was $17.6 million compared to $27.2 million for the same period a year ago. In the six months ended June 30, 2006, we issued $50.0 million of 5.05% senior notes to fund the second phase of the Williamson Development acquisition for $35 million and repaid $15 million on our credit facility. We also made our annual principal payment of $9.35 million on our senior notes. The prior year included $18 million in borrowings in the first quarter of 2005 to fund the Plum Creek acquisition. In addition to these transactions, we paid distributions to our partners of $43.2 million in the first half of 2006 compared to $35.9 million for the same period in 2005.

Contractual Obligations and Commercial Commitments

     At June 30, 2006, our debt consisted of:

• $10 million outstanding under our $175 million revolving credit facility that matures in October 2010;

• $50.1 million of 5.55% senior notes due 2023, with a 10-year average life;

• $61.85 million of 4.91% senior notes due 2018, with a 7.5-year average life;

• $35 million of 5.55% senior notes due 2013, with a 9-year average life; and

• $100 million of 5.05% senior notes due 2020, with a 9-year average life.

     Credit Facility.In November 2005, we completed an extension of our $175 million revolving credit facility for an additional year and improved its pricing. We retained the option to increase the limit up to $300 million. The amendment extends the term of the credit facility by one year to 2010 with two separate options to extend for one additional year each. The amendment also lowers the borrowing costs and commitment fees.

     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:

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• the higher of the federal funds rate plus an applicable margin ranging from 0% to 1.00% or the prime rate as announced by the agent bank; or

• at a rate equal to LIBOR plus an applicable margin ranging from .75% to 2.00%.

     We incur a commitment fee on the unused portion of the revolving credit facility at a rate ranging from 0.15% to 0.40% per annum.

     The credit agreement contains covenants requiring us to maintain:

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

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

     Senior Notes.NRP Operating LLC issued the senior notes under a note purchase agreement. The senior notes are unsecured but are guaranteed by our operating subsidiaries. We may prepay the senior notes at any time together with a make-whole amount (as defined in the note purchase agreement). If any event of default exists under the note purchase agreement, the noteholders will be able to accelerate the maturity of the senior notes and exercise other rights and remedies.

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

• not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and

• maintain the ratio of consolidated EBITDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.

     The following table reflects our long-term non-cancelable contractual obligations as of June 30, 2006 (in millions):

	Payments due by period(1)
Contractual Obligations	Total		2006		2007		2008		2009		2010		Thereafter
Long-term debt (including current maturities)	$	345.60	$	6.40	$	21.92	$	29.13	$	28.26	$	27.39	$	232.50

(1) The amounts indicated in the table include principal and interest due on our senior notes.

Shelf Registration Statement

     On December 23, 2003, we and our operating subsidiaries jointly filed a $500 million “universal shelf” registration statement with the Securities and Exchange Commission for the proposed sale of debt and equity securities. Securities issued under this registration statement may be in the form of common units representing limited partner interests in Natural Resource Partners or debt securities of NRP or any of our operating subsidiaries. The registration statement also covers, for possible future sales, up to 673,715 common units held by Great Northern Properties Limited Partnership. In November 2004, Great Northern Properties sold 300,000 common units in a private placement. We did not and will not receive any proceeds from the sale of common units by Great Northern Properties.

     Approximately $290.2 million is available under our shelf registration statement. The securities may be offered from time to time directly or through underwriters at amounts, prices, interest rates and other terms to be determined at the time of any offering. The net proceeds from the sale of securities from the shelf will be used for future acquisitions and other general corporate purposes, including the retirement of existing debt.

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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.

Inflation

     Inflation in the United States has been relatively low in recent years and did not have a material impact on operations for the first half of 2006 or 2005.

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 coal 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, 2006. 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 property, we are not responsible for the costs associated with these operations. In addition, West Virginia has established a fund to satisfy any shortfall in our lessees’ reclamation obligations.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

     We are dependent upon the effective marketing and efficient mining of our coal reserves by our lessees. Our lessees sell coal under various long-term and short-term contracts as well as on the spot market. A large portion of these sales are under long-term contracts. The coal industry in Appalachia is experiencing an increase in both domestic and foreign demand, as well as a shortage of supply. As a result, the current price of coal in Appalachia is at historically high levels. If this price level is not sustained or our lessees’ costs increase, some of our coal could become uneconomic to mine, which would adversely affect our coal royalty revenues. In addition, the current prices may make coal from other regions more economical and may make other competing fuels relatively less costly than Appalachian coal.

Interest Rate Risk

     Our exposure to changes in interest rates results from our borrowings under our revolving credit facility, which may be subject to variable interest rates based upon LIBOR. At June 30, 2006, we had outstanding $10.0 million in variable interest rate debt. If LIBOR rates were to increase by 100 basis points, annual interest expense would increase by $100,000, assuming the same principal amount remained outstanding over the next twelve months.

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 producing the timely recording,

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processing, summarizing and reporting of information and in accumulating and communicating information to management as appropriate to allow for timely decisions with regard to required disclosure.

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

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Part II. Other Information

Item 1. Legal Proceedings

     None.

Item 1A. Risk Factors

     During the period covered by this report, there were no material changes from the risk factors previously disclosed in Natural Resource Partners L.P.’s Form 10-K for the year ended December 31, 2005.

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

     None.

Item 3. Defaults Upon Senior Securities

     None.

Item 4. Submission of Matters to a Vote of Security Holders

     None.

Item 5. Other Information

     None.

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Item 6. Exhibits

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.

*	Filed herewith.
**	Furnished herewith.

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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 3, 2006

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

Date: August 3, 2006

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

Date: August 3, 2006

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

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Exhibit Index

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.

*	Filed herewith.
**	Furnished herewith.

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