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 September 30, 2005


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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ No 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 November 3, 2005 there were outstanding 13,986,906 Common Units and 11,353,658 Subordinated Units.

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 “Risks Related to Our Business” beginning on page 24 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)


	September 30,			December 31,
	2005			2004
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	49,457		$	42,103
Accounts receivable		18,099			15,058
Accounts receivable — affiliate		6			25
Other		36			786

Total current assets		67,598			57,972
Land		14,110			13,721
Plant and equipment, net		6,011			—
Coal and other mineral rights, net		569,534			523,844
Loan financing costs, net		2,217			1,837
Other assets, net		1,726			2,552

Total assets	$	661,196		$	599,926

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	681		$	576
Accounts payable — affiliate		78			105
Current portion of long-term debt		9,350			9,350
Accrued incentive plan expenses — current portion		1,941			1,559
Property, franchise and other taxes payable		3,078			3,460
Accrued interest		2,820			266

Total current liabilities		17,948			15,316
Deferred revenue		13,795			15,847
Accrued incentive plan expenses		5,502			3,271
Long-term debt		202,950			156,300
Partners’ capital:
Common units (outstanding: 13,986,906)		249,536			243,814
Subordinated units (outstanding: 11,353,658)		162,191			157,324
General partner’s interest		9,653			8,802
Holders of incentive distribution rights		436			105
Accumulated other comprehensive loss		(815	)		(853	)

Total partners’ capital		421,001			409,192

Total liabilities and partners’ capital	$	661,196		$	599,926

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						Nine months ended
	September 30,						September 30,
	2005			2004			2005			2004
	(Unaudited)						(Unaudited)
Revenues:
Coal royalties	$	34,267		$	30,315		$	104,754		$	79,342
Property taxes		1,552			1,377			4,533			3,961
Minimums recognized as revenue		431			352			1,365			1,280
Override royalties		487			956			1,311			2,390
Other		1,998			1,221			4,716			3,107

Total revenues		38,735			34,221			116,679			90,080
Operating costs and expenses:
Depletion and amortization		8,221			7,800			24,725			22,083
General and administrative		3,527			2,523			10,001			7,656
Property, franchise and other taxes		1,954			1,464			5,738			4,833
Coal royalty and override payments		1,071			450			2,369			1,236

Total operating costs and expenses		14,773			12,237			42,833			35,808

Income from operations		23,962			21,984			73,846			54,272
Other income (expense)
Interest expense		(2,889	)		(2,694	)		(7,916	)		(8,792	)
Interest income		392			78			954			190

Net income	$	21,465		$	19,368		$	66,884		$	45,670

Net income attributable to: ⁽¹⁾
General partner	$	1,103		$	605		$	3,088		$	1,246

Other holders of incentive distribution rights	$	363		$	117		$	943		$	178

Limited partners	$	19,999		$	18,646		$	62,853		$	44,246

Basic and diluted net income per limited partner unit:
Common	$	0.79		$	.74		$	2.48		$	1.79

Subordinated	$	0.79		$	.74		$	2.48		$	1.79

Weighted average number of units outstanding:
Common		13,987			13,987			13,987			13,266

Subordinated		11,354			11,354			11,354			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.

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Nine months ended
	September 30,
	2005			2004
	(Unaudited)
Cash flows from operating activities:
Net income	$	66,884		$	45,670
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and amortization		24,725			22,083
Non-cash interest charge		222			876
Change in operating assets and liabilities:
Accounts receivable		(3,022	)		(3,482	)
Other assets		285			1,083
Accounts payable		78			(300	)
Accrued interest		2,554			1,766
Deferred revenue		(2,016	)		(1,910	)
Accrued incentive plan expenses		2,613			1,345
Property, franchise and other taxes payable		(382	)		151

Net cash provided by operating activities		91,941			67,282

Cash flows from investing activities:
Acquisition of land, plant and equipment, coal and other mineral rights		(76,124	)		(77,733	)

Net cash used in investing activities		(76,124	)		(77,733	)

Cash flows from financing activities:
Proceeds from loans		106,000			75,500
Repayment of loans		(59,350	)		(111,850	)
Distributions to partners		(55,113	)		(43,614	)
Contributions by general partner		—			2,147
Proceeds from sale of 5,250,000 common units, net of transaction costs		—			200,355
Redemption of 2,616,752 common units net of transaction costs		—			(100,121	)

Net cash provided by (used in) financing activities		(8,463	)		22,417

Net increase in cash and cash equivalents		7,354			11,966
Cash and cash equivalents at beginning of period		42,103			24,320

Cash and cash equivalents at end of period	$	49,457		$	36,286


Supplemental cash flow information:
Cash paid during the period for interest	$	5,139		$	6,151

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

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Organization

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2005 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 2004 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.

New Accounting Standards

Statement of Financial Accounting Standards No. 123R “Accounting for Stock-Based Compensation,” revised in 2004, superseded APB No. 25. Awards under our Long Term Incentive Plan have been accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R, effective for the first quarter of 2006, requires us to recognize a 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 recorded. Additionally, FAS 123R provides that grants after the effective date must be accounted for using the fair value method which will require us to estimate the fair value of the grant using the Black-Scholes or another method and charge the estimated fair value to expense over the service or vesting period of the grant. FAS 123R requires that the fair value be recalculated at each reporting date over the service or vesting period of the grant. Use of the fair value method as compared with the intrinsic method will not change the total expense to be reflected for a grant but it may impact the period in which expense is reflected by increasing expense in one period based upon the fair value calculation and lowering expense in a different period. The Partnership is in the process of evaluating the impact of the adoption of FAS 123R.

3. Acquisitions

Plum Creek

On March 3, 2005, the Partnership completed an acquisition of coal reserves from Plum Creek Timber Company, Inc. The purchase price was $21.25 million and was funded through a combination of the Partnership’s revolving credit facility and $3.25 million in cash. 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.

Steelhead

On July 11, 2005, the Partnership completed the first of three separate transactions to acquire coal reserves in the Illinois Basin. The first transaction for $35 million was funded with $32 million in debt and $3 million in cash. Reserves associated with this transaction are approximately 47.5 million tons, approximately 75% of which are owned in fee. The Partnership will receive an override on the remaining tons.

Dolphin

On September 22, 2005, the Partnership acquired a coal preparation plant and rail load-out facility in Greenbrier County, West Virginia for $6 million, which was funded through the Partnership’s revolving credit facility. The facilities will primarily process coal produced from the Partnership’s Plum Creek properties.

Area F/Lexington

In two separate transactions on September 26, 2005, the Partnership 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. The acquisition was funded with cash.

4. Coal and Other Mineral Rights

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


	September 30,			December 31,
	2005			2004
	(In thousands)
	(Unaudited)
Coal and other mineral rights	$	704,632		$	634,960
Less accumulated depletion and amortization		(135,098	)		(111,116	)


Net book value	$	569,534		$	523,844


	Nine months ended
	September 30,
	2005		2004
	(In thousands)
	(Unaudited)
Total depletion and amortization expense on coal interests	$	22,998	$	21,345

5. Long-Term Debt

Long-term debt consists of the following:


	September 30,			December 31,
	2005			2004
	(In thousands)
	(Unaudited)
$175 million floating rate revolving credit facility, due October 2009	$	6,000		$	—
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023		53,400			56,700
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018		67,900			73,950
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		50,000			—

Total debt		212,300			165,650
Less — current portion of long term debt		(9,350	)		(9,350	)

Long-term debt	$	202,950		$	156,300

At September 30, 2005, the Partnership had an outstanding balance of $6.0 million on its revolving credit facility, and the weighted average interest rate on the outstanding balance was 6.39%. The Partnership incurs a commitment fee on the revolving credit facility at rates ranging from 0.30% to 0.40% per annum.

The Partnership was in compliance with all terms under its long-term debt as of September 30, 2005.

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 $0.6 million for the three and nine month periods ended September 30, 2005 and $0.3 million and $0.9 million for the same periods in 2004. These costs are reflected in general and administrative expenses in the accompanying statements of income. At September 30, 2005, 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 $0.7 million and $2.0 million for the three and nine month periods ended September 30, 2005 and 2004, respectively. These costs are reflected in general and administrative expenses in the accompanying statements of income.

8. Commitments and Contingencies

Legal

Limited Partnership and Natural Resource Partners L.P., the plaintiffs allege that coal mining and timbering in Wyoming and Raleigh Counties, West Virginia, exacerbated the flood runoff and the severity of the flooding that damaged the plaintiffs’ homes and businesses. This is only one of dozens of similar flood-related actions now pending in the West Virginia state courts that have been consolidated before a three-judge mass litigation panel.

The Partnership has filed a motion to dismiss NRP in this case on the theory that NRP did not own any surface interests in Wyoming and Raleigh Counties and did not acquire coal interests in Wyoming and Raleigh Counties until after the date of the July 2001 flood. The motion to dismiss remains pending, but will likely not be ruled on soon because the mass litigation panel has thus far chosen not to address either that motion or the many similar dispositive motions filed by other defendants and now pending in flood cases before the mass litigation panel. The Ashley case is currently scheduled for trial as to liability in March 2006. Any judgment as to damages, if any, would be determined in a separate trial following the liability phase.

Although it is too early in the litigation to express any meaningful opinion as to the outcome, the Partnership’s management believes it has a good defense to this action. In addition, pursuant to the Omnibus Agreement, the Partnership has made a demand on Western Pocahontas Properties Limited Partnership for indemnification with respect to any damages NRP might suffer up to $10 million.

The Partnership is also 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.

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. Because Natural Resource Partners L.P. has no employees, Western Pocahontas Properties employees perform regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees and the duty to enforce regulations rests with the appropriate regulatory agencies. Management believes that the Partnership’s lessees will be able to comply with existing regulations and does not expect any lessee’s failure to comply with environmental laws and regulations to have a material impact on its financial condition or results of operations. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties for the period ended September 30, 2005. The Partnership is not associated with any environmental contamination that may require remediation costs. However, lessees regularly conduct reclamation work on the properties under lease to them. Because the Partnership is not the permittee of the operations on its property, it is not responsible for the costs associated with these operations. All of the Partnership’s lessees are required to post bonds to cover reclamation costs. In the event these bonds are insufficient, some states, such as West Virginia have established funds to cover these shortfalls. The Partnership is also indemnified by its original sponsors, jointly and severally, until October 17, 2005 against environmental and tax liabilities attributable to the ownership and operation of the assets contributed to the Partnership prior to the closing of the initial public offering in October 2002. The environmental indemnity is limited to a maximum of $10.0 million. The Partnership has made a claim against Western Pocahontas Properties Limited Partnership under this indemnity with respect to any damages that the Partnership might incur in connection with the flood litigation described above under “-Legal”.

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										Nine months ended
	September 30,										September 30,
	2005					2004					2005					2004
	Revenues		Percent			Revenues		Percent			Revenues		Percent			Revenues		Percent
	Dollars in thousands										Dollars in thousands
			(Unaudited)										(Unaudited)
Lessee A	$	4,740		12	%	$	3,443		10	%	$	13,667		12	%	$	9,968		11	%
Lessee B		5,090		13	%		4,799		14	%		15,117		13	%		14,316		16	%
Lessee C		4,395		12	%		3,194		9	%		12,602		11	%		6,152		7	%

10. Incentive Plans

In February and April 2005, the directors of GP Natural Resource Partners LLC granted to directors and key employees a total of 59,046 additional phantom units that vest in February 2009. There were 224,129 phantom units outstanding at September 30, 2005. The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $1.1 million and $0.7 million for the three months ended September 30, 2005 and 2004, respectively, and $3.2 million and $1.8 million for the nine months ended in the same periods, respectively. In connection with the Long-Term Incentive Plans, cash payments of $0.8 million and $0.6 million were paid during the nine months ended September 30, 2005 and 2004.

11. Distributions

On August 12, 2005, the Partnership paid a cash distribution equal to $0.7125 per unit, or $2.85 on an annualized basis, to unitholders of record on August 1, 2005.

12. Subsequent Events

Distributions and Conversion of Subordinated Units

On October 20, 2005, the Partnership announced a $0.025 per unit increase in its quarterly distributions to $0.7375 per unit, or $2.95 per unit on an annualized basis. The distribution is payable on November 14, 2005 to unitholders of record on November 1, 2005.

In conjunction with the payment of the third quarter distribution, the Partnership also announced that effective at the close of business on November 14, 2005, as expected, there will be a mandatory and automatic conversion of 25% of the subordinated units traded under the ticker symbol NSP into common units traded under the ticker symbol NRP. Provided all terms of the conversion set forth in the partnership agreement have been met, an additional 25% of the NSP units will convert into NRP units in mid-November 2006 and the remaining 50% will convert in mid-November 2007.

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, 2005.

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, 2004, we controlled approximately 1.8 billion tons of proven and probable coal reserves in nine states. For the nine months ended September 30, 2005, approximately 60% of the coal produced from our properties came from underground mines and approximately 40% came from surface mines. As of December 31, 2004, approximately 69% of our reserves were low sulfur coal. Included in our low sulfur reserves is compliance coal, which constitutes approximately 37% of our reserves.

We lease coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine our coal reserves in exchange for royalty payments. As of September 30, 2005, our reserves were subject to 165 leases with 62 lessees. For the three months ended September 30, 2005, our lessees produced 12.7 million tons of coal generating $34.3 million in coal royalty revenues from our properties and our total revenue was $38.7 million. For the nine months ended September 30, 2005, our lessees produced 39.6 million tons of coal generating $104.8 million in coal royalty revenues from our properties and our total revenue was $116.7 million.

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. In addition, our leases specify minimum monthly, quarterly or annual royalties. 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.

Most of our coal is produced by large companies, many of which are publicly traded, with professional and sophisticated sales departments. We estimate that 80% 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.

Coal royalty revenues from our Appalachian properties represented 91% of our total coal royalty revenues for the nine months ended September 30, 2005, and thus a significant portion of our total revenue is dependent upon Appalachian coal prices. Coal prices are based on supply and demand, specific coal characteristics, economics of alternative fuel, and overall domestic and international economic conditions. Our lessees located in Appalachia have recently experienced a greater demand for coal, and coal prices for both metallurgical and steam coal for those producers increased during 2004 and continuing through 2005. Towards the end of the second quarter of 2004, our Appalachian lessees began to enter into new coal sales contracts at the higher prices. As their older contracts have continued to rollover during the last 15 months, we have received substantially higher royalties from our leases, and our revenue per ton in that region has increased to an average of $2.87 per ton for the nine months ended September 30, 2005 from an average of $2.28 per ton for the same period of 2004. However, because prices have generally stabilized over the last 6 months and our lessees will have fewer contracts that will rollover into substantially higher prices, we expect that our coal royalty revenue per ton will not continue to increase at such a dramatic pace over the next year. In addition, in spite of the higher prices, most of our lessees have not appreciably increased production due to a number of constraints, including a shortage of labor, permitting issues and rail transportation problems. As a result, we believe that a larger percentage of our future revenue growth will come from acquisitions of new reserves.

For the nine months ended September 30, 2005, approximately 32% of our coal royalty revenues and 28% 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. 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.

On July 8, 2004, the United States District Court for the Southern District of West Virginia issued an opinion and an injunctive order in the case of Ohio Valley Environmental Coalition, et al. v. William Bulen. Judge Joseph Goodwin granted summary judgment for the plaintiffs and enjoined further permitting by the Army Corps of Engineers in Southern West Virginia under the Nationwide Permit 21 program. His order only impacts counties in Southern West Virginia and requires applicants in those counties to seek individual permits, which require a more intensive environmental review and public comment. Judge Goodwin also ordered the Corps of Engineers to tell the companies that had received 11 permits issued by the Corps’ office in Huntington, West Virginia since January 2002 to halt any work under those permits where construction of the fills had not started at the time of the July 8 order. The case is on appeal to the Fourth Circuit Court of Appeals, which entertained oral argument in September 2005. A decision is expected in late 2005 or early 2006. Pending the resolution of this appeal, this decision will dramatically slow down the permitting process for our lessees in Southern West Virginia, and the increased cost of obtaining permits could render some of our smaller blocks of reserves uneconomic to develop.

In January 2005, a lawsuit was filed in Eastern District of Kentucky on similar grounds challenging the legality of Nationwide Permit 21. In March 2005, the plaintiffs filed a motion for summary judgment requesting the court to (1) issue a declaratory judgment that Nationwide Permit 21 violates Section 404 of the Clean Water Act and (2) issue an injunction prohibiting the Corps from issuing further authorizations pursuant to Nationwide Permit 21 in Kentucky. The motion also requested the court to suspend those authorizations for valley fills on which the placement of mining spoil in streams had not commenced as of the date of filing of the motion. On June 9, 2005, the judge transferred the case from the Lexington Division to the Pikeville Division. The new judge has yet to schedule arguments on the motion. Should the district court follow the reasoning of Ohio Valley Environmental Coalition v. Bulen and similarly enjoin the Corps of Engineers from authorizing further general permits under Nationwide Permit 21, permittees may have to file for individual permits for fills that will result in increases in the costs of mining coal. The court will entertain argument on cross motions for summary judgment in early November. The court will entertain argument on cross motions for summary judgment in early November. We will continue to monitor this litigation and its impact on the development of our coal reserves.

In addition to coal royalty revenues, other revenues accounted for approximately 4% and 3% of our total revenues for each of the nine month periods ended September 30, 2005 and 2004, respectively. Other revenues consist of: rentals; royalties on oil and gas and coalbed methane leases; timber; and wheelage payments, which are toll payments for the right to transport third-party coal over or through our property.

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 throughout 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”


	Three months ended						Nine months ended
	September 30,						September 30,
	2005			2004			2005			2004
	(Unaudited)
Cash flow from operations	$	34,493		$	30,791		$	91,941		$	67,282
Less scheduled principal payments		—			—			(9,350	)		(9,350	)
Less reserves for future principal payments		(2,350	)		(2,350	)		(7,050	)		(7,050	)
Add reserves used for scheduled principal payments		—			—			9,400			9,400

Distributable cash flow	$	32,143		$	28,441		$	84,941		$	60,282

Acquisitions

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.

Steelhead. 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. The acquisition included approximately 47.5 million tons, of which approximately 75% are owned in fee. We will receive an override on the remaining tons.

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 primarily process coal produced from our Plum Creek properties.

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.

2004 Acquisitions

Clinchfield. In September 2004, we purchased a tract of coal reserves from Clinchfield Coal Company in Dickenson County, Virginia for $0.4 million. This property adjoins other property we own and represents approximately 0.8 million tons. We subsequently combined this property with other properties under an existing lease.

Pardee Minerals. In May 2004, we purchased a tract of coal reserves from Pardee Minerals LLC in Wise County, Virginia for $1.6 million. This property adjoins other property we own and represents approximately 1.0 million tons. As a part of this transaction, we took an assignment of a coal lease.

Appolo. In February 2004, we purchased two tracts of property from Appolo Fuels, Inc. in Bell County, Kentucky for $2.5 million. This property adjoins the properties purchased in the BLC acquisition and represents approximately 2.5 million tons. As a part of this transaction, an older below market lease affecting approximately 2.5 million additional tons of adjacent reserves was renegotiated to current royalty rates.

BLC Properties. In January 2004, we purchased all of the mineral interests of BLC Properties LLC for $73.0 million. This acquisition included coal, oil and gas and other mineral rights on approximately 270,000 acres that contain approximately 176 million tons of coal reserves. We lease these reserves to eight different lessees. The transaction also included oil and gas and other mineral rights on approximately 205,000 additional acres. The properties are located in Kentucky, Tennessee, West Virginia, Virginia, and Alabama. BLC retained a 35% non-participating royalty interest in the oil and gas and other mineral rights.

Critical Accounting Policies

Coal Royalties. We recognize coal royalty revenues on the basis of tons of coal sold by our lessees and the corresponding revenue from those sales. Generally, the 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 carried as deferred revenue, a liability on the balance sheet.

Timber Royalties. We primarily sell timber on a contract basis where independent contractors harvest and sell the timber. From time to time, we also sell timber in a competitive bid process. We recognize timber revenues when the independent contractors have harvested the timber, because title and risk of loss pass to the independent contractors at that time. When our timber is sold in a competitive bid process, we recognize revenue upon completion of the sale.

Oil and Gas Royalties. Oil and gas royalties are recognized on the basis of volume of hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the lessees make payments based on a percentage of the selling price. Some leases are subject to minimum annual payments or delay rentals. The minimum annual payments that are recoupable are generally recoupable over certain periods. The minimum payments are initially recorded as deferred revenue and recognized either when the lessee recoups the minimum payments through production or when the period during which the lessee is allowed to recoup the minimum payment expires.

Depletion. We deplete coal properties on a units-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral properties and estimated proved and probable tonnage in those properties. We estimate proven and probable coal reserves with the assistance of third-party mining consultants, and we use estimation techniques and recoverability assumptions. Our estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. Historical revisions have not been material. Timberlands are stated at cost less depletion. We determine the cost of the timber harvested based on the volume of timber harvested in relation to the amount of estimated net merchantable volume by geographic areas. We estimate our timber inventory using statistical information and data obtained from physical measurements and other information gathering techniques. We update these estimates annually, which may result in adjustments of timber volumes and depletion rates that are recognized prospectively. Changes in these estimates have no effect on our cash flow.

New Accounting Standards

Statement of Financial Accounting Standards No. 123R “Accounting for Stock-Based Compensation,” revised in 2004, superseded APB No. 25. Awards under our Long Term Incentive Plan have been accounted for on the intrinsic method under the provisions of APB No. 25. FAS 123R, effective for the first quarter of 2006, requires us to recognize a 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 recorded. Additionally, FAS 123R provides that grants after the effective date must be accounted for using the fair value method which will require us to estimate the fair value of the grant using an accepted method and charge the estimated fair value to expense over the service or vesting period of the grant. FAS 123R requires that the fair value be recalculated at each reporting date over the service or vesting period of the grant. Use of the fair value method as compared with the intrinsic method, will not change the total expense to be reflected for a grant but it may impact the period in which expense is reflected by increasing expense in one period based upon the fair value calculation and lowering expense in a different period. We are in the process of evaluating the impact of the adoption of FAS 123R.

Results of Operations

Natural Resource Partners L.P.


	Three months ended						Nine months ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands, except per ton data)
				(Unaudited)
Revenues:
Coal royalties	$	34,267		$	30,315		$	104,754		$	79,342
Property taxes		1,552			1,377			4,533			3,961
Minimums recognized as revenue		431			352			1,365			1,280
Override royalties		487			956			1,311			2,390
Other		1,998			1,221			4,716			3,107

Total revenues		38,735			34,221			116,679			90,080
Expenses:
Depletion and amortization		8,221			7,800			24,725			22,083
General and administrative		3,527			2,523			10,001			7,656
Property, franchise and other taxes		1,954			1,464			5,738			4,833
Coal royalty and override payments		1,071			450			2,369			1,236

Total expenses		14,773			12,237			42,833			35,808

Income from operations		23,962			21,984			73,846			54,272
Other income (expense):
Interest expense		(2,889	)		(2,694	)		(7,916	)		(8,792	)
Interest income		392			78			954			190

Net income	$	21,465		$	19,368		$	66,884		$	45,670

Other Data:
Coal royalties
Appalachia
Northern	$	2,198		$	2,491		$	6,767		$	5,039
Central		21,950			21,358			70,022			57,320
Southern		7,098			4,089			18,455			11,251

Total Appalachia		31,246			27,938			95,244			73,610
Illinois Basin		956			1,114			3,356			2,612
Northern Powder River Basin		2,065			1,263			6,154			3,120

Total	$	34,267		$	30,315		$	104,754		$	79,342

Production (tons)
Appalachia
Northern		1,161			1,340			3,577			2,927
Central		7,792			8,746			24,989			25,272
Southern		1,667			1,274			4,665			4,029

Total Appalachia		10,620			11,360			33,231			32,228
Illinois Basin		624			942			2,198			2,240
Northern Powder River Basin		1,447			757			4,144			2,249

Total		12,691			13,059			39,573			36,717

Average gross royalty per ton
Appalachia
Northern	$	1.89		$	1.86		$	1.89		$	1.72
Central		2.82			2.44			2.80			2.27
Southern		4.26			3.21			3.96			2.79

Total Appalachia		2.94			2.46			2.87			2.28
Illinois Basin		1.53			1.18			1.53			1.17
Northern Powder River Basin		1.43			1.67			1.49			1.39

Total	$	2.70		$	2.32		$	2.65		$	2.16

Three months ended September 30, 2005 compared with three months ended September 30, 2004

Revenues. For the three months ended September 30, 2005, coal royalty revenues were $34.3 million on 12.7 million tons of coal produced, compared to $30.3 million in coal royalty revenues on 13.0 million tons of coal produced for the third quarter of 2004, representing a 13% increase in coal royalty revenues and a 3% decrease in production. Coal royalty revenues comprised approximately 88% of our total revenue for each of the three month periods ended September 30, 2005 and 2004, while property taxes, minimums recognized as revenue, override royalties and other, comprised the remaining 12% of our total revenue for those periods.

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

Appalachia. As a result of higher prices, coal royalty revenues in Appalachia for the quarter ended September 30, 2005 were $31.2 million compared to $27.9 million for the same period in 2004, an increase of $3.3 million or 12%. For the quarter ended September 30, 2005, production in Appalachia was 10.6 million tons compared to 11.4 million tons for the same period in 2004, 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 an 8% production decline in Northern Appalachia from 1.3 million tons for the quarter ended September 30, 2004 to 1.2 million tons for the quarter ended September 30, 2005, our coal royalty revenues declined 12% from $2.5 million to $2.2 million over those same periods. The only property that significantly contributed to this decline was our Sincell property, where production decreased from 708,000 tons to 615,000 tons and coal royalty revenues decreased from $1.5 million to $937,000 due to lower shipments and decreased sales in the spot market during the third quarter of 2005.

Central Appalachia. Although production from our Central Appalachia properties declined 10.3% from 8.7 million tons for the quarter ended September 30, 2004 to 7.8 million tons for the quarter ended September 30, 2005, our coal royalty revenues from these properties increased 3% from $21.4 million to $22.0 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.

	•		Pardee — production increased from 357,000 tons to 455,000 tons and coal royalty revenues increased from $1.3 million to $1.7 million. The increased production was due to a greater proportion of production from the mine being on our property.

	•		Eastern Kentucky Property — production increased from 10,000 tons to 140,000 tons and coal royalty revenues increased from $28,000 to $515,000. The increased production was due to a greater proportion of production from the mine being on our owned property.

	•		Kingston — production increased from 240,000 tons to 442,000 tons and coal royalty revenues increased from $462,000 to $1.1 million. The increased tonnage was due to additional producing units being on our property and a new surface mine starting on the property.

	•		Plum Creek — production increased from zero to 165,000 tons and coal royalty revenue increased from zero to $462,000, due to the March 2005 acquisition of the property.

	•		Boone-Lincoln — production increased from 9,000 tons to 184,000 tons and coal royalty revenues increased from $19,000 to $490,000. The increased tonnage was due to a greater proportion of production from the mine being on our owned property.

	•		West Fork — production decreased from 565,000 tons to zero and royalty revenues decreased from $1.7 million to zero as longwall mining was completed on our property.

	•		Eunice — production decreased from 669,000 tons to 456,000 tons and coal royalty revenues decreased from $1.6 million to $1.0 million due to a smaller proportion of production from a longwall mine coming from our property.

Southern Appalachia. Our coal royalty revenues in Southern Appalachia increased 73% from $4.1 million for the quarter ended September 30, 2004 to $7.1 million for the quarter ended September 30, 2005, as production increased 31% from 1.3 million tons to 1.7 million tons over those same periods. The following properties contributed to these increases.

	•		BLC Properties — production increased from 956,000 tons to 1.0 million tons and coal royalty revenues increased from $2.9 million to $3.4 million. These increases in tonnage were due to some lessees having a greater proportion of their production on our property.

	•		Twin Pines/Drummond — production increased from 93,000 tons to 233,000 tons and coal royalty revenues increased from $592,000 to $2.1 million. The increased tonnage was due to increased production at a mine and a new mine being started.

	•		Oak Grove — production increased from 226,000 tons to 420,000 tons and coal royalty revenues increased from $621,000 to $1.6 million. The increased tonnage was due to increased production from the mine.

Illinois Basin. Coal royalty revenues in the Illinois Basin for the quarter ended September 30, 2005 were $1.0 million compared to $1.1 million for the same period in 2004, a decrease of $0.1 million or 10%. For the quarter ended September 30, 2005, production in the Illinois Basin was 624,000 tons compared to 942,000 tons for the same period in 2004, a decrease of 318,000 tons or 34%. The significant decrease came from our Cummings/Hocking Wolford property where production decreased from 558,000 tons to 295,000 tons and coal royalty revenue decreased from $569,000 to $388,000. The decreased tonnage was due to a higher proportion of production from the mine being on adjacent property which was partially offset by an increased royalty rate at the mine.

Northern Powder River Basin. Production from our Western Energy property increased 643,000 tons or 85% from 757,000 tons to 1.4 million tons and coal royalty revenues increased $0.8 million or 62% from $1.3 million to $2.1 million. These increases were due to the typical variations in production resulting from the checkerboard ownership pattern.

Expenses. For the quarter ended September 30, 2005, total expenses were $14.7 million, compared to $12.2 million for the third quarter of 2004, representing an increase of $2.5 million, or 20%. Included in total expenses are:

	•		Depletion and amortization of $8.2 million for the third quarter of 2005, compared to $7.8 million for the third quarter of 2004, an increase of $0.4 million, or 5% primarily due to the areas being depleted and their differing depletion rates between periods;

	•		General and administrative expenses of $3.5 million for the third quarter of 2005, compared to $2.5 million for the third quarter of 2004, an increase of $1.0 million, or 40%. 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 $2.0 million for the third quarter of 2005, compared to $1.5 million for the third quarter of 2004, an increase of $0.5 million, or 33%, due to an increase in franchise taxes for 2005, as well as, taxes on additional properties acquired since last year.

Interest Expense. For the quarter ended September 30, 2005, interest expense was $2.9 million compared to $2.7 million for 2004, an increase of $0.2 million. This increase is attributed to additional borrowings on our senior notes during the third quarter of 2005, offset by lower outstanding balances on our credit facility.

Nine months ended September 30, 2005 compared with nine months ended September 30, 2004

Revenues. For the nine months ended September 30, 2005, coal royalty revenues were $104.8 million on 39.6 million tons of coal produced, compared to $79.3 million in coal royalty revenues on 36.7 million tons of coal produced for the first nine months of 2004, representing a 32% increase in coal royalty revenues and an 8% increase in production. Coal royalty revenues comprised approximately 90% of our total revenue for the nine months ended September 30, 2005 and 88% of our total revenue for the same period in 2004, while property taxes, minimums recognized as revenue, override royalties and other, comprised the remaining 10% and 12% of our total revenue for those periods.

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

Appalachia. As a result of significantly higher prices, coal royalty revenues in Appalachia for the nine months ended September 30, 2005 were $95.2 million compared to $73.6 million for the same period in 2004, an increase of $21.6 million or 29%. For the nine months ended September 30, 2005, production in Appalachia was 33.2 million tons compared to 32.2 million tons for the same period in 2004, an increase of 1.0 million tons or 3%. The Appalachian results by region are set forth below.

Northern Appalachia. As a result of a 24% production increase in Northern Appalachia from 2.9 million tons for the nine months ended September 30, 2004 to 3.6 million tons for the nine months ended September 30, 2005, our coal royalty revenues increased 36% from $5.0 million to $6.8 million over those same periods. The only property that significantly contributed to this increase was our Sincell property, where production increased from 927,000 tons to 2.1 million tons and coal royalty revenues increased from $1.8 million to $3.6 million. The increased production was due to a longwall unit producing from our property for the entire nine months ended September 30, 2005 versus only a portion of the nine months ended September 30, 2004.

Central Appalachia. Although production from our Central Appalachia properties declined 1% from 25.3 million tons for the nine months ended September 30, 2004 to 25.0 million tons for the nine months ended September 30, 2005, our coal royalty revenues from these properties increased 22% from $57.3 million to $70.0 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.

	•		Pinnacle — production increased from 1.0 million tons to 2.2 million tons while coal royalty revenues increased from $3.5 million to $8.1 million. The increased tonnage was due to the mine resuming production after being idle during a portion of the nine months ended September 30, 2004.

	•		Eunice — production increased from 1.7 million tons to 2.2 million tons and coal royalty revenues increased from $3.6 million to $5.4 million. The increased tonnage was due to higher production by the longwall unit on our property.

	•		Lynch — production increased from 3.3 million tons to 3.8 million tons and coal royalty revenues increased from $6.3 to $8.5 million. The increased production was due to new mines being opened on the property.

	•		Kingston — production increased from 861,000 tons to 1.2 million tons and coal royalty revenues increased from $1.6 million to $3.4 million. The increased tonnage was due to an additional producing unit being on our property and a new surface mine starting on the property.

	•		West Fork — production on our West Fork property decreased from 2.1 million tons to zero and coal royalty revenues decreased from $5.9 million to zero as longwall mining was completed on our property.

	•		Evans-Lavier — production decreased from 2.5 million tons to 911,000 tons and coal royalty revenues decreased from $3.5 million to $2.1 million as a lower proportion of the production was on our property.

	•		Wehrle-Casto — production decreased from 158,000 tons to 12,000 tons and coal royalty revenues decreased from $1.2 million to $22,000. The decrease in production was due to a mine nearing completion of mining on our property.

Southern Appalachia. Our coal royalty revenues in Southern Appalachia increased 64% from $11.3 million for the nine months ended September 30, 2004 to $18.5 million for the nine months ended September 30, 2005, as production increased 15% from 4.0 million tons to 4.7 million tons over those same periods. The following properties contributed to these increases.

•

BLC Properties — production increased from 2.6 million tons to 2.9 million tons and coal royalty revenues increased from $7.0 million to $9.9 million. These increases in tonnage were due to a combination of some lessees increasing production and some having a greater proportion of production on our property, which offset reductions by a lessee who experienced geologic problems.

•

Twin Pines/Drummond — production increased from 279,000 tons to 475,000 tons and coal royalty revenues increased from $1.7 million to $4.1 million. The increased tonnage was due to increased production at a mine and a new mine being started.

•

Oak Grove — production increased from 1.1 million tons to 1.2 million tons and coal royalty revenues increased from $2.6 million to $4.5 million. The increased tonnage was due to increased production from the mine.

Illinois Basin. As a result of higher prices and an increased royalty rate at one mine, coal royalty revenues in the Illinois Basin for the nine months ended September 30, 2005 were $3.4 million compared to $2.6 million for the same period in 2004, an increase of $0.7 million or 27%. For the nine months ended September 30, 2005 and 2004, production in the Illinois Basin was 2.2 million tons in both periods.

Northern Powder River Basin. Production from our Western Energy property increased 1.9 million tons or 86% from 2.2 million tons to 4.1 million tons and coal royalty revenues increased 100% from $3.1 million to $6.2 million. These increases were due to the typical variations in production resulting from the checkerboard ownership pattern and higher sales prices being received by our lessee.

Expenses. For the nine months ended September 30, 2005, total expenses were $42.8 million, compared to $35.8 million for the first nine months of 2004, representing an increase of $7.0 million, or 20%. Included in total expenses are:

	•		Depletion and amortization of $24.7 million for the first nine months of 2005, compared to $22.1 million for the same period of 2004, an increase of $2.6 million, or 12% due to the increase in production volumes;

	•		General and administrative expenses of $10.0 million for the first nine months of 2005, compared to $7.7 million for the first nine months of 2004, an increase of $2.3 million, or 30%. 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;

	•		Property, franchise and other taxes of $5.7 million for the nine months ended September 30, 2005, compared to $4.8 million for the first nine months of 2004, an increase of $0.9 million, or 19%, due to an increase in franchise taxes for 2005; and

	•		Coal royalty and override payments were up $1.1 million or 92% due to increased mining on properties containing overrides.

Interest Expense. For the nine months ended September 30, 2005, interest expense was $7.9 million compared to $8.8 million for 2004, a decrease of $0.9 million. This decrease is attributed to lower outstanding balances on our credit facility and senior notes during 2005.

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 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 $0.9 million and $2.6 million for the three and nine month periods ended September 30, 2005 and $0.9 million and $2.9 million for the three and nine month periods ended September 30, 2004, respectively.

First Reserve Corporation

Prior to August 2005, First Reserve controlled a partnership that held 4,796,920 subordinated units. In connection with this investment, First Reserve had a contractual right to appoint two members to our board of directors. Following the public sale of 4,200,000 of these subordinated units in August, First Reserve relinquished this contractual right. However, the two First Reserve

appointees, Alex Krueger and Steve Smith, have remained on our board. Mr. Smith is an independent director and serves on our audit committee. Mr. Krueger is a managing director at First Reserve, which has a number of investments in the coal business, including in two of our lessees, Alpha Natural Resources and Foundation Coal Holdings. Because Mr. Krueger also serves on the boards of directors of Alpha and Foundation, we have summarized below our relationships with each of these companies.

Alpha Natural Resources. We have entered into a number of coal mining leases with Alpha through a combination of new leases entered into upon our purchase of the Alpha property and through leases we had with entities that Alpha acquired. The leases we have with Alpha or related companies consist of the following properties:

	•		VICC/Alpha in Virginia, which contains 362.5 million tons of proven and probable reserves as of December 31, 2004.

	•		Kingwood in West Virginia, which contains 17.8 million tons of proven and probable reserves as of December 31, 2004.

	•		Welch/Wyoming in West Virginia, which contains 7.5 million tons of proven and probable reserves as of December 31, 2004.

	•		KY Land in Kentucky, which contains 20.3 million tons of proven and probable reserves as of December 31, 2004.

	•		Plum Creek property in Kentucky, which contains 11.6 million tons of proven and probable reserves as of December 31, 2004.

The Alpha leases in general have terms of five to ten years with the ability to renew the leases for subsequent terms of five to ten years, until the earlier to occur of: (1) delivery of notice that the lessee will not renew the lease or (2) all mineable and merchantable coal has been mined. The leases provide for payments to us based on the higher of a percentage of the gross sales price or a fixed minimum per ton of coal sold from the properties, with minimum annual payments. Under the Alpha leases minimum royalty payments are credited against future production royalties.

Coal royalty revenues payable under these leases for the nine months ended September 30, 2005 totaled $15.1 million, representing 14% of our total coal royalty revenues. If no production had taken place in 2005, minimum recoupable royalties of $3.6 million would have been payable under the leases. At September 30, 2005 we had accounts receivable outstanding of $1.9 million with Alpha Natural Resources.

We believe the production and minimum royalty rates contained in the Alpha leases are consistent with current market royalty rates.

Foundation Coal Holdings, Inc. First Reserve has a significant interest in Foundation Coal Holdings, Inc. who controls our lessee on the Kingston property in West Virginia, which contained approximately 7.7 million tons of proven and probable reserves as of December 31, 2004.

The Kingston lease has a term of ten years with the ability to renew the lease for subsequent terms of five years unless the lessee gives notice it will not renew the lease. The lease provides for payments to us based on the higher of a percentage of the gross sales price or a fixed minimum per ton of coal sold from the properties, with annual minimum payments. Under the Kingston lease minimum royalty payments are credited against future production royalties. We believe the production and minimum royalty rates contained in the Kingston lease are consistent with current market royalty rates.

Coal royalty revenues payable under the Kingston lease for the nine months ended September 30, 2005 totaled $3.3 million, representing 3% of our coal royalty revenues. If no production had taken place in 2005, minimum recoupable royalties of $0.3 million would have been payable under the lease. At September 30, 2005, we had accounts receivable outstanding of $0.5 million with Foundation Coal Holdings, Inc.

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 cash flow we generate from

our operations, please read “Risks Related to Our Business.” Our capital expenditures, other than for acquisitions, have historically been minimal.

Net cash provided by operations for the nine months ended September 30, 2005 and 2004 was $91.9 million and $67.3 million, respectively. Substantially all of our cash provided by operations is generated from coal royalty revenues.

Net cash used in investing activities for the nine months ended September 30, 2005 was $76.1 million compared to $77.7 million for 2004. The 2005 results include the acquisition of coal reserves from Plum Creek Timber Company, Inc. for $21.25 million, the acquisition of coal reserves from Steelhead for $35.0 million, the acquisition of a coal preparation plant and loadout facility from Dolphin for $6.0 million and the acquisition of the Area F/Lexington coal reserves for $13.5 million. Net cash used in investing activities for 2004 include the acquisitions of coal reserves from BLC, Apollo, Pardee Minerals and Clinchfield.

Net cash used in financing activities for the nine months ended September 30, 2005 was $8.5 million compared to net cash provided by financing activities of $22.4 million for the same period a year ago. In the nine months ended September 30, 2005, we borrowed $56.0 million on our revolving credit facility to fund acquisitions, we then repaid $50.0 million of that balance with the issuance of $50.0 million in new 5.05% senior notes. In addition to the repayment of the revolving credit facility, we paid $9.4 million in principal payments on our senior notes and we made distributions to our partner’s of $55.1 million. During the nine months ended September 30, 2004, results include $200.4 million in net proceeds from our equity offering in March 2004, a $2.1 million capital contribution from our general partner to maintain its 2% general partner interest, as well as $75.5 million in proceeds from borrowings on our credit facility. We used $102.5 million of the net proceeds from the equity offering to pay the outstanding balance on our credit facility and $100.1 million to redeem 2.6 million common units owned by Arch Coal. We also paid $9.4 million in principal payments on our senior notes along with distributions to our partners totaling $43.6 million.

Contractual Obligations and Commercial Commitments

At September 30, 2005, our debt consisted of:

	•		$6 million outstanding under our $175 million revolving credit facility that matures in October 2009;

	•		$53.4 million of 5.55% senior notes due 2023, with a 10-year average life;

	•		$68 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

	•		$50 million of 5.05% senior notes due 2020, with a 9-year average life.

The $50 million of 5.05% senior notes due 2020 were issued on July 19, 2005. The proceeds from the issuance of these senior notes were used to repay borrowings under the revolving credit facility.

Credit Facility. On October 29, 2004, NRP (Operating) LLC entered into a 5-year, $175 million revolving credit facility with Citigroup Global Markets, Inc. and Wachovia Capital Markets, LLC as joint lead arrangers. The facility permits NRP Operating to increase the size of the facility up to $300 million without obtaining lender consents.

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 0.25% 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 1.25% to 2.00%.

We incur a commitment fee on the revolving credit facility at rates ranging from 0.30% 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 September 30, 2005 (in millions):


	Payments due by period⁽¹⁾
Contractual Obligations	Total		2005		2006		2007		2008		2009		Thereafter
Long-term debt (including current maturities)	$	369.01	$	5.38	$	22.20	$	21.92	$	28.94	$	34.07	$	256.50

₍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. We currently have approximately $290.2 million available under our registration statement. The registration statement also covers, for possible future sales, up to 373,715 common units held by Great Northern Properties Limited Partnership.

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. We will not receive any proceeds from the sale of common units by Great Northern Properties.

On June 28, 2005, we filed a shelf registration statement at the request of FRC-WPP NRP Investment L.P., which owns 4,796,920 subordinated units. The registration statement registered the 4,796,920 subordinated units and the common units into which they convert. In August 2005, FRC-WPP NRP Investment L.P. sold 4,200,000 subordinated units in a public offering. We did not receive any proceeds from the sale of the units. FRC-WPP NRP Investment L.P. may sell the remaining units from time to time under the registration statement, and we will not receive any proceeds from the sale of the units.

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 nine months of 2005 or 2004.

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 for the period ended September 30, 2005. 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. We are also indemnified by our original sponsors, jointly and severally, until October 17, 2005 against environmental and tax liabilities attributable to the ownership and operation of the assets contributed to us prior to the closing of the initial public offering. The environmental indemnity is limited to a maximum of $10.0 million. We have made a claim against Western Pocahontas Properties under this indemnity with respect to any damages that we might incur in connection with the flood litigation described in Part II, Item 1. Legal Proceedings.”

Risks Related to Our Business

	•		We may not have sufficient cash from operations to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

	•		A substantial or extended decline in coal prices could reduce our coal royalty revenues and the value of our coal reserves.

	•		Our lessees’ coal mining operations are subject to operating risks that could result in lower coal royalty revenues to us.

	•		We depend on a limited number of primary operators for a significant portion of our coal royalty revenues, and the loss of or reduction in production from any of our major operators could reduce our coal royalty revenues.

	•		We may not be able to terminate our leases, and we may experience delays and be unable to replace lessees that do not make royalty payments.

	•		If our lessees do not manage their operations well, their production volumes and our coal royalty revenues could decrease.

	•		Adverse developments in the coal industry could reduce our coal royalty revenues, and could substantially reduce our total revenues due to our lack of asset diversification.

	•		Any decrease in the demand for metallurgical coal could result in lower coal production by our lessees, which would thereby reduce our coal royalty revenues.

	•		We may not be able to expand and our business will be adversely affected if we are unable to replace or increase our reserves or obtain other mineral reserves through acquisitions.

	•		Any change in fuel consumption patterns by electric power generators resulting in a decrease in the use of coal could result in lower coal production by our lessees, which would reduce our coal royalty revenues.

	•		Competition within the coal industry may adversely affect the ability of our lessees to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.

	•		Lessees could satisfy obligations to their customers with coal from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments.

	•		Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from our properties.

	•		Our reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of our reserves.

	•		Our lessees’ work forces could become increasingly unionized in the future.

	•		We may be exposed to changes in interest rates because any current borrowings under our revolving credit facility may be subject to variable interest rates based upon LIBOR.

	•		Our lessees are subject to federal, state and local laws and regulations that may limit their ability to produce and sell coal from our properties.

	•		A lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period.

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 substantially higher. 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 September 30, 2005, we had outstanding $6.0 million in variable interest rate debt. If LIBOR rates were to increase by 100 basis points, annual interest expense would increase by $60,000, 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, 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.

Part II. Other Information

Item 1. Legal Proceedings

In July 2001, several counties in West Virginia with significant coal and timber production experienced severe flooding. In response to the floods, numerous plaintiffs living in and around the City of Mullens in Wyoming County have sued, among other defendants, Natural Resource Partners. In Charles Ashley et al. v. Western Pocahontas Corporation, Western Pocahontas Properties Limited Partnership and Natural Resource Partners L.P., the plaintiffs allege that coal mining and timbering in Wyoming and Raleigh Counties, West Virginia, exacerbated the flood runoff and the severity of the flooding that damaged the plaintiffs’ homes and businesses. This is only one of dozens of similar flood-related actions now pending in the West Virginia state courts that have been consolidated before a three-judge mass litigation panel.

We have filed a motion to dismiss NRP in this case on the theory that we do not own any surface interests in Wyoming and Raleigh Counties and did not acquire our coal interests in Wyoming and Raleigh Counties until after the date of the July 2001 flood. The motion to dismiss remains pending, but will likely not be ruled on soon because the mass litigation panel has thus far chosen not to address either that motion or the many similar dispositive motions filed by other defendants and now pending in flood cases before the mass litigation panel. The Ashley case is currently scheduled for trial as to liability in March 2006. Any judgment as to damages, if any, would be determined in a separate trial following the liability phase.

Although it is too early in the litigation to express any meaningful opinion as to the outcome, we believe we have a good defense to this action. In addition, pursuant to the Omnibus Agreement, we have made a demand on Western Pocahontas Properties Limited Partnership for indemnification with respect to any damages we might suffer up to $10 million.

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.


	Page
PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004		4
Consolidated Statements of Income For the Three and Nine Months Ended September 30, 2005 and 2004		5
Consolidated Statements of Cash Flows For the Nine Months Ended September 30, 2005 and 2004		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		16
Related Party Transactions		20
Liquidity and Capital Resources		21
Environmental		24
Risks Related to Our Business		24

ITEM 3. Quantitative And Qualitative Disclosures About Market Risk		25

ITEM 4. Controls And Procedures		26

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings		27

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds		27

ITEM 3. Defaults Upon Senior Securities		27

ITEM 4. Submission Of Matters to a Vote of Security Holders		27

ITEM 5. Other Information		27

ITEM 6. Exhibits		28

Signatures		29
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


4.1	—	Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of August 2, 2005 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on August 3, 2005).

4.2	—	Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of August 2, 2005 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on October 20, 2005).

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.


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


Date: November 3, 2005

	By:	/s/ Corbin J. Robertson, Jr.

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

Date: November 3, 2005

	By:	/s/ Dwight L. Dunlap

		Dwight L. Dunlap,
		Chief Financial Officer and
		Treasurer
		(Principal Financial Officer)

Date: November 3, 2005

	By:	/s/ Kenneth Hudson

		Kenneth Hudson
		Controller
		(Principal Accounting Officer)


4.1	—	Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of August 2, 2005 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on August 3, 2005).

4.2	—	Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of August 2, 2005 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on October 20, 2005).

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.

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*		Filed herewith.

**		Furnished herewith.


*		Filed herewith.

**		Furnished herewith.