Edgar Filing: NATURAL RESOURCE PARTNERS LP

10-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(Amendment No. 1)

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

For the fiscal year ended December 31, 2013 or

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

For the transition period from to

Commission file number: 1-31465

NATURAL RESOURCE PARTNERS L.P.

(Exact name of registrant as specified in its charter)


Delaware		35-2164875
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

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

(713) 751-7507

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered
Common Units representing limited partnership interests		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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 x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


x Large Accelerated Filer		¨ Accelerated Filer		¨ Non-accelerated Filer		¨ Smaller Reporting Company

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2) Yes ¨ No x

The aggregate market value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the Common Units outstanding, for this purpose, as if they were affiliates of the registrant) was approximately $1.5 billion on June 30, 2013 based on a price of $20.57 per unit, which was the closing price of the Common Units as reported on the daily composite list for transactions on the New York Stock Exchange on that date.

As of February 28, 2014, there were 109,812,408 Common Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE.

None.

EXPLANATORY NOTE

Natural Resource Partners L.P. (the “Company”) is filing this Annual Report on Form 10-K/A for the year ended December 31, 2013 (this “Form 10-K/A”) to amend its original Annual Report on Form 10-K for the year ended December 31, 2013 originally filed on February 28, 2014 (the “Original Form 10-K”). This Form 10-K/A should be read in conjunction with the Original Form 10-K and the Company’s subsequent reports filed with the SEC. Except for the information specifically amended and restated herein, this Form 10-K/A has not been updated to reflect events, results or developments that occurred after the date of the Original Form 10-K nor does it change any other disclosures contained in the Original Form 10-K.

This Form 10-K/A is being filed to include the audit report of Deloitte & Touche LLP, who have audited the financial statements of OCI Wyoming, L.P. (now “OCI Wyoming LLC”) as of and for the year ended December 31, 2013 and whose report is relied upon by Ernst & Young LLP, the Company’s independent registered public accounting firm. The Deloitte & Touche LLP report was inadvertently omitted from the Original Form 10-K. In addition, the references to “unaudited” in the operating results and balance sheet information relating to the Company’s investment in OCI Wyoming included in “Note 4. Equity and Other Investments” have been removed from the accompanying financial statements. Accordingly, Item 8. “Financial Statements and Supplementary Data” is hereby amended in its entirety. No other changes to the Company’s financial statements or the audit report of Ernst & Young LLP have been made.

Part II.

Item 8. Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page
Report of Ernst & Young LLP, independent registered public accounting firm		3
Report of Deloitte & Touche LLP, independent registered public accounting firm		4
Consolidated balance sheets as of December 31, 2013 and 2012		5
Consolidated statements of comprehensive income for the years ended December 31, 2013, 2012 and 2011		6
Consolidated statements of partners’ capital for the years ended December 31, 2013, 2012 and 2011		7
Consolidated statements of cash flows for the years ended December 31, 2013, 2012 and 2011		8
Notes to consolidated financial statements		9

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Partners of Natural Resource Partners L.P.

We have audited the accompanying consolidated balance sheets of Natural Resource Partners L.P. as of December 31, 2013 and 2012, and the related consolidated statements of comprehensive income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of OCI Wyoming LP (OCI Wyoming) (a Limited Partnership in which Natural Resource Partners LP owns a 49% interest). Natural Resource Partners LP’s investment in OCI Wyoming constituted approximately $269 million of Natural Resource Partners LP’s assets as of December 31, 2013 and Natural Resource Partners LP’s equity in the net income of OCI Wyoming constituted approximately $34 million of Natural Resource Partners LP’s Net Income for the period ended December 31, 2013. OCI Wyoming’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for OCI Wyoming, is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Natural Resource Partners L.P. at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Natural Resource Partners L.P.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission “1992 framework” and our report dated February 28, 2014 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 28, 2014

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Managers and Partners of

OCI Wyoming, L.P.

Atlanta, Georgia

We have audited the balance sheet of OCI Wyoming, L.P. (the “Partnership”) as of December 31, 2013 and the related consolidated statements of operations and comprehensive income, equity, and cash flows for the year then ended, and the related notes to the financial statements (not presented herein). These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position the Partnership as of December 31, 2013, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 26, 2014

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit information)


	December 31, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	92,513		$	149,424
Accounts receivable, net of allowance for doubtful accounts		33,737			35,116
Accounts receivable — affiliates		7,666			10,613
Other		1,691			1,042

Total current assets		135,607			196,195
Land		24,340			24,340
Plant and equipment, net		26,435			32,401
Mineral rights, net		1,405,455			1,380,473
Intangible assets, net		66,950			70,766
Equity and other unconsolidated investments		269,338			—
Loan financing costs, net		11,502			4,291
Long-term contracts receivable — affiliates		51,732			55,576
Other assets		497			630

Total assets	$	1,991,856		$	1,764,672


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	8,659		$	3,693
Accounts payable — affiliates		391			957
Current portion of long-term debt		80,983			87,230
Accrued incentive plan expenses – current portion		8,341			7,718
Property, franchise and other taxes payable		7,830			7,952
Accrued interest		17,184			10,265

Total current liabilities		123,388			117,815
Deferred revenue		142,586			123,506
Accrued incentive plan expenses		10,526			8,865
Other non-current liabilities		14,341			—
Long-term debt		1,084,226			897,039
Partners’ capital:
Common units outstanding: (109,812,408 and 106,027,836)		606,774			605,019
General partner’s interest		10,069			10,026
Non-controlling interest		324			2,845
Accumulated other comprehensive loss		(378	)		(443	)

Total partners’ capital		616,789			617,447

Total liabilities and partners’ capital	$	1,991,856		$	1,764,672

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands, except per unit data)


	For the Years Ended December 31,
	2013			2012			2011
Revenues:
Coal royalties	$	212,663		$	260,734		$	279,221
Equity and other unconsolidated investment income		34,186			—			—
Aggregate royalties		7,643			6,598			6,734
Processing fees		5,049			8,299			13,475
Transportation fees		17,977			19,513			16,688
Oil and gas revenues		17,080			9,160			14,017
Property taxes		15,416			15,273			12,640
Minimums recognized as revenue		8,285			23,956			9,148
Override royalties		13,499			15,527			14,523
Other		26,319			20,087			11,237

Total revenues and other income		358,117			379,147			377,683
Operating expenses:
Depreciation, depletion and amortization		64,377			58,221			65,118
Asset impairments		734			2,568			161,336
General and administrative		36,821			29,714			29,553
Property, franchise and other taxes		16,463			17,678			14,486
Oil and gas lease operating expenses		739			—			—
Transportation costs		1,644			1,944			2,033
Coal royalty and override payments		1,103			1,857			1,022

Total operating expenses		121,881			111,982			273,548

Income from operations		236,236			267,165			104,135
Other income (expense)
Interest expense		(64,396	)		(53,972	)		(49,180	)
Interest income		238			162			69

Income before non-controlling interest		172,078			213,355			55,024
Non-controlling interest		—			—			(998	)

Net income	$	172,078		$	213,355		$	54,026

Net income attributable to:
General partner	$	3,442		$	4,267		$	1,081

Limited partners	$	168,636		$	209,088		$	52,945

Basic and diluted net income per limited partner unit	$	1.54		$	1.97		$	0.50

Weighted average number of common units outstanding		109,584			106,028			106,028

Comprehensive income	$	172,143		$	213,405		$	54,079

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands, except unit data)


	Common Units					General Partner Amounts			Non- Controlling Interest Amounts			Accumulated Other Comprehensive Income (Loss)			Total
	Units		Amounts			General Partner Amounts			Non- Controlling Interest Amounts						Total
Balance at December 31, 2010		106,027,836	$	806,529		$	14,132		$	5,065		$	(546	)	$	825,180
Distributions		—		(230,080	)		(4,696	)		(52	)		—			(234,828	)
Non-controlling interest adjustment		—		—			—			(373	)		—			(373	)
Costs associated with equity transactions		—		(141	)		—			—			—			(141	)
Non-controlling interest		—		—			—			998			—			998
Net income for the year ended December 31, 2011		—		52,945			1,081			—			—			54,026
Loss on interest hedge		—		—			—			—			53			53

Comprehensive income		—		—			—			—			53			54,079

Balance at December 31, 2011		106,027,836	$	629,253		$	10,517		$	5,638		$	(493	)	$	644,915

Distributions		—		(233,263	)		(4,758	)		(2,793	)		—			(240,814	)
Costs associated with equity transactions		—		(59	)		—			—			—			(59	)
Net income for the year ended December 31, 2012		—		209,088			4,267			—			—			213,355
Loss on interest hedge		—		—			—			—			50			50

Comprehensive income		—		—			—			—			50			213,405

Balance at December 31, 2012		106,027,836	$	605,019		$	10,026		$	2,845		$	(443	)	$	617,447

Issuance of common units		3,784,572		75,000			—			—			—			75,000
Capital contribution		—		—			1,531			—			—			1,531
Cost associated with equity transactions		—		(293	)		—			—			—			(293	)
Distributions		—		(241,588	)		(4,930	)		(2,521	)		—			(249,039	)
Net income for the year ended December 31, 2013		—		168,636			3,442			—			—			172,078
Interest rate swap from unconsolidated investments		—		—			—			—			13			13
Loss on interest hedge		—		—			—			—			52			52

Comprehensive income		—		—			—			—			65			172,143

Balance at December 31, 2013		109,812,408	$	606,774		$	10,069		$	324		$	(378	)	$	616,789

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	For the Years Ended December 31,
	2013			2012			2011
Cash flows from operating activities:
Net income	$	172,078		$	213,355		$	54,026
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		64,377			58,221			65,118
Non-cash interest charge		2,200			605			625
Non-cash gain on reserve swap		(8,149	)		—			(2,990	)
Equity and other unconsolidated investment income		(34,186	)		—			—
Distributions of earnings from unconsolidated investments		24,113			—			—
Gain on sale of assets		(10,921	)		(13,575	)		(1,058	)
Asset impairment		734			2,568			161,336
Non-controlling interest		—			—			998
Change in operating assets and liabilities:
Accounts receivable		6,826			(802	)		(6,951	)
Other assets		(516	)		(236	)		90
Accounts payable and accrued liabilities		2,197			1,909			854
Accrued interest		6,919			(496	)		950
Deferred revenue		19,240			11,684			31,277
Accrued incentive plan expenses		2,284			(3,461	)		1,909
Property, franchise and other taxes payable		(122	)		1,636			(610	)

Net cash provided by operating activities		247,074			271,408			305,574

Cash flows from investing activities:
Acquisition of land, coal, other mineral rights and related intangibles		(72,000	)		(180,534	)		(120,284	)
Acquisition of equity interests		(293,085	)		—			—
Distributions from unconsolidated investments		48,833			—			—
Acquisition or construction of plant and equipment		—			(681	)		(404	)
Proceeds from sale of assets		10,929			24,822			5,600
Return on direct financing lease and contractual override		2,558			2,669			—
Investment in direct financing lease		—			(59,009	)		—

Net cash used in investing activities		(302,765	)		(212,733	)		(115,088	)

Cash flows from financing activities:
Proceeds from loans		567,020			148,000			385,000
Proceeds from issuance of common units		75,000			—			—
Deferred financing costs		(9,209	)		—			(2,957	)
Repayments of loans		(386,230	)		(30,800	)		(210,519	)
Payment of obligation related to acquisitions		—			(500	)		(7,625	)
Costs associated with equity transactions		(293	)		(59	)		(141	)
Distributions		(249,039	)		(240,814	)		(234,828	)
Capital contribution by general partner		1,531			—			—

Net cash used in financing activities		(1,220	)		(124,173	)		(71,070	)

Net increase (decrease) in cash and cash equivalents		(56,911	)		(65,498	)		119,416
Cash and cash equivalents at beginning of period		149,424			214,922			95,506

Cash and cash equivalents at end of period	$	92,513		$	149,424		$	214,922

Supplemental cash flow information:
Cash paid during the period for interest	$	55,191		$	53,842		$	47,653

Non-cash investing activities:
Non-controlling interest		—			—		$	373
Note receivable related to sale of assets		—		$	1,808			—
Non-cash contingent consideration on equity investments	$	15,000			—			—
Non-cash financing activities:
Purchase obligation related to reserve and infrastructure acquisitions		—			—		$	500

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

Natural Resource Partners L.P. (the “Partnership”), a Delaware limited partnership, was formed in April 2002. The general partner of the Partnership is NRP (GP) LP (“NRP GP”), a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company. The Partnership engages principally in the business of owning and managing mineral properties in the United States. The Partnership owns coal reserves in the three major coal-producing regions of the United States: Appalachia, the Illinois Basin and the Western United States, as well as lignite reserves in the Gulf Coast region. As of December 31, 2013, the Partnership owned or controlled approximately 2.3 billion tons of proven and probable coal reserves (unaudited), and also owned approximately 500 million tons of aggregate reserves (unaudited) in a number of states across the country. The Partnership does not operate any mines, but leases reserves to experienced mine operators under long-term leases that grant the operators the right to mine reserves in exchange for royalty payments. Lessees are generally required to make royalty payments based on the higher of a percentage of the gross sales price or a fixed price per ton, in addition to a minimum payment.

In addition, the Partnership owns coal and aggregate transportation and preparation equipment, other coal related rights and oil and gas properties on which it earns revenue.

The Partnership’s operations are conducted through, and its operating assets are owned by, its subsidiaries. The Partnership owns its subsidiaries through two wholly owned operating companies, NRP (Operating) LLC and NRP Oil and Gas LLC. NRP GP has sole responsibility for conducting its business and for managing its operations. Because NRP GP is a limited partnership, its general partner, GP Natural Resource Partners LLC, conducts its business and operations, and the board of directors and officers of GP Natural Resource Partners LLC makes decisions on its behalf. Robertson Coal Management LLC, a limited liability company wholly owned by Corbin J. Robertson, Jr., owns all of the membership interest in GP Natural Resource Partners LLC. Mr. Robertson is entitled to nominate all ten of the directors, five of whom must be independent directors, to the board of directors of GP Natural Resource Partners LLC. Mr. Robertson has delegated the right to nominate two of the directors, one of whom must be independent, to Adena Minerals, LLC, an affiliate of Christopher Cline.

2. Summary of Significant Accounting Policies

Principles of Consolidation

The financial statements include the accounts of Natural Resource Partners L.P. and its wholly owned subsidiaries as well as BRP LLC, a venture with International Paper Company controlled by the Partnership. Intercompany transactions and balances have been eliminated.

Business Combinations

For purchase acquisitions accounted for as a business combination, the Partnership is required to record the assets acquired, including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques.

Use of Estimates

Preparation of the accompanying financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the accompanying Consolidated Balance Sheets and the reported amounts of revenues and expenses in the accompanying Consolidated Statements of Comprehensive Income during the reporting period. Actual results could differ from those estimates.

Fair Value

The Partnership discloses certain assets and liabilities using fair value as defined by authoritative guidance. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See Note 11. “Fair Value Measurements.”

There are three levels of inputs that may be used to measure fair value:

•

Level 1 — Quoted prices in active markets for identical assets or liabilities.

•

Level 2 — Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

•

Level 3 — Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Level 3 assets and liabilities include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation.

Cash Equivalents and Restricted Cash

The Partnership considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents.

Accounts Receivable

Accounts receivable from the Partnership’s lessees do not bear interest. Receivables are recorded net of the allowance for doubtful accounts in the accompanying Consolidated Balance Sheets. The Partnership evaluates the collectability of its accounts receivable based on a combination of factors. The Partnership regularly analyzes its lessees’ accounts and when it becomes aware of a specific customer’s inability to meet its financial obligations to the Partnership, such as in the case of bankruptcy filings or deterioration in the lessee’s operating results or financial position, the Partnership records a specific reserve for bad debt to reduce the related receivable to the amount it reasonably believes is collectible. Accounts are charged off when collection efforts are complete and future recovery is doubtful. If circumstances related to specific lessees change, the Partnership’s estimates of the recoverability of receivables could be further adjusted.

Equity Investments

The Partnership accounts for non-marketable investments using the equity method of accounting if the investment gives it the ability to exercise significant influence over, but not control of, an investee. Significant influence generally exists if the Partnership has an ownership interest representing between 20% and 50% of the voting stock of the investee.

Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investment and the proportionate share of earnings or losses and distributions. The basis difference between the investment and the proportional share of the fair value of the underlying net assets of equity method investees is hypothetically allocated first to identified tangible assets and liabilities, finite-lived intangibles or indefinite-lived intangibles and the balance is attributed to goodwill. The portion of the basis difference attributed to net tangible assets and finite-lived intangibles is amortized over their estimated useful life while indefinite-lived intangibles, if any, and goodwill is not amortized. The amortization of the basis difference is recorded as a reduction of earnings from the equity investment in the Consolidated Statements of Comprehensive Income.

An investee’s accounts are not included in the Partnership’s Consolidated Balance Sheets and Statements of Comprehensive Income. However, the Partnership’s carrying value in an equity method investee company is reflected in the caption “Equity and other unconsolidated investments” in the Partnership’s Consolidated Balance Sheets. The Partnership’s adjusted share of the earnings or losses of the investee company is reflected in the

Consolidated Statements of Comprehensive Income as revenues and other income under the caption ‘‘Equity and other unconsolidated investment income.” These earnings are generated from natural resources, which are considered part of the Partnership’s core business activities consistent with its directly owned revenue generating activities. Investee earnings are adjusted to reflect the amortization of any difference between the cost basis of the equity investment and the proportionate share of the investee’s book value, which has been allocated to the fair value of net identified tangible and finite-lived intangible assets and amortized over the estimated lives of those assets.

The Partnership evaluates its equity investments for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other than temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss. The fair value of the impaired investment is based on quoted market prices, or upon the present value of expected cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. No impairment losses have been recognized as of December 31, 2013.

Land and Mineral Rights

Land and mineral rights owned and leased are recorded using the FASB’s business combination and asset purchase authoritative guidance. Coal and aggregate mineral rights are depleted on a unit-of-production basis by lease, based upon minerals mined in relation to the net cost of the mineral properties and estimated proven and probable tonnage therein, or over the amortization period of the lease. The Partnership owns royalty and non-operated working interests in oil and natural gas minerals, all of which are located in the U.S. The Partnership does not determine whether or when to develop reserves. The Partnership uses the successful efforts method to account for its working interest in oil and gas properties. Oil and gas non-operated working interests are depleted on a unit-of-production basis. The depletion rate is adjusted annually based upon the amount of remaining reserves as determined by independent third party petroleum engineers. Oil and gas royalty interests are depleted on a straight-line basis over 30 years or the life of the lease, whichever is shorter.

Plant and Equipment

Plant and equipment consists of coal preparation plants, related coal handling facilities, and other coal and aggregate processing and transportation infrastructure. Expenditures for new facilities and expenditures that substantially increase the useful life of property, including interest during construction, are capitalized and reported in the Consolidated Statements of Cash Flows. These assets are recorded at cost and are depreciated on a straight-line basis over their useful lives, which when originally recorded range from three to twenty years.

Intangible Assets

The Partnership’s intangible assets consist of above-market contracts. Intangible assets are identified related to contracts acquired when compared to the estimate of current market rates for similar contracts. The estimated fair value of the above-market rate contracts are determined based on the present value of future cash flow projections related to the underlying assets acquired. Intangible assets are amortized on a unit-of-production basis except that a minimum amortization is calculated on a straight line basis for temporarily idled assets.

Deferred Financing Costs

Deferred financing costs consist of legal and other costs related to the issuance of the Partnership’s revolving credit facility and senior notes. These costs are amortized over the term of the debt.

Asset Impairment

A long term asset is deemed impaired in most cases when the future expected cash flow from its use and disposition is less than its book value. Impairment is measured based on the present value of the projected future cash flow compared to current book value. The Partnership has developed procedures to periodically evaluate its long-lived assets for possible impairment. These procedures are performed throughout the year and are based on historic, current and future performance and are designed to be early warning tests. If an asset fails one of the early warning tests, additional evaluation is performed for that asset that considers both quantitative and qualitative information. Undiscounted cash flow is used to evaluate recoverability with any adjustment to fair value to reflect impairment based on discounted cash flows. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require a separate impairment evaluation be completed on a significant property. As a result of the continued weakness in the coal markets, the Partnership intends to closely monitor its coal assets impairment risk, and the impairment evaluation process may be completed more frequently if deemed necessary by the Partnership. Future impairment analyses could result in downward adjustments to the carrying value of the Partnership’s assets. See Note 6. “Asset Impairments.”

Revenues

Coal and Aggregate Royalties. Coal and aggregate royalty revenues are recognized on the basis of tons of mineral sold by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of mineral they sell.

Processing and Transportation Fees. Processing fees are recognized on the basis of tons of material processed through the facilities by the Partnership’s lessees and the corresponding revenue from those sales. Generally, the lessees of the processing facilities make payments to the Partnership based on the greater of a percentage of the gross sales price or a fixed price per ton of material that is processed and sold from the facilities. The processing leases are structured in a manner so that the lessees are responsible for operating and maintenance expenses associated with the facilities. Transportation fees are recognized on the basis of tons of material transported over the beltlines. Under the terms of the transportation contracts, the Partnership receives a fixed price per ton for all material transported on the beltlines.

Oil and Gas Revenues. Oil and gas royalty revenues 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. Also, included within oil and gas royalties are lease bonus payments, which are generally paid upon the execution of a lease. Some leases are subject to minimum annual payments or delay rentals. Revenues related to the Partnership’s non-operated working interests in oil and gas assets are recognized on the basis of our net revenue interests in hydrocarbons produced. The Partnership also has capital expenditure and operating expenditure obligations associated with the non-operated working interests. The Partnership’s revenues fluctuate based on changes in the market prices for oil and natural gas, the decline in production from producing wells, and other factors affecting the third-party oil and natural gas exploration and production companies that operate wells, including the cost of development and production.

Minimum Royalties. Most of the Partnership’s lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue when received. The deferred revenue attributable to the minimum payment is recognized as royalty revenue when the lessee recoups the minimum payment through production. The deferred revenue is recognized as minimums recognized as revenue in the period immediately following the expiration of the lessee’s ability to recoup the payments.

Lessee Audits and Inspections

The Partnership periodically audits lessee information by examining certain records and internal reports of its lessees. The Partnership’s regional managers also perform periodic mine inspections to verify that the information that has been reported to the Partnership is accurate. The audit and inspection processes are designed to identify

material variances from lease terms as well as differences between the information reported to the Partnership and the actual results from each property. Audits and inspections, however, are in periods subsequent to when the revenue is reported and any adjustment identified by these processes might be in a reporting period different from when the revenue was initially recorded. Typically there are no material adjustments from this process.

Property Taxes

The Partnership is responsible for paying property taxes on the properties it owns. Typically, the lessees are contractually responsible for reimbursing the Partnership for property taxes on the leased properties. The reimbursement of property taxes is included in property tax revenue in the Consolidated Statements of Comprehensive Income.

Income Taxes

No provision for income taxes related to the operations of the Partnership has been included in the accompanying financial statements because, as a partnership, it is not subject to federal or material state income taxes and the tax effect of its activities accrues to the unitholders. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities. In the event of an examination of the Partnership’s tax return, the tax liability of the partners could be changed if an adjustment in the Partnership’s income is ultimately sustained by the taxing authorities.

Share-Based Payment

The Partnership accounts for awards relating to its Long-Term Incentive Plan using the fair value method, which requires the Partnership to estimate the fair value of the grant, and charge or credit the estimated fair value to expense over the service or vesting period of the grant based on fluctuations in the Partnership’s common unit price. In addition, estimated forfeitures are included in the periodic computation of the fair value of the liability and the fair value is recalculated at each reporting date over the service or vesting period of the grant.

New Accounting Standards

In February 2013, the FASB amended the comprehensive income reporting requirements to require an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. The amendment requires an entity to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. The adoption did not have a material impact on the financial statements.

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

3. Significant Acquisitions

Sundance. On December 19, 2013, the Partnership completed the acquisition of non-operated working interests in the Williston Basin of North Dakota from Sundance Energy, Inc. The Partnership accounted for the transaction in accordance with the authoritative guidance for business combinations. The identification of all assets acquired and liabilities assumed as well as the valuation process required for the allocation of the purchase price is not complete. Pending the final purchase price adjustments and allocation, the assets acquired for approximately $33.7 million are included in mineral rights in the accompanying Consolidated Balance Sheets.

Abraxas. On August 9, 2013, the Partnership completed the acquisition of non-operated working interests in the Williston Basin of North Dakota and Montana from Abraxas Petroleum. The Partnership accounted for the

transaction in accordance with the authoritative guidance for business combinations. The identification of all assets acquired and liabilities assumed as well as the valuation process required for the allocation of the purchase price is not complete. Pending the final purchase price adjustments and allocation, the assets acquired for approximately $38.3 million are included in mineral rights in the accompanying Consolidated Balance Sheets. Revenues and costs from the working interests for 2013 of $4.6 million and $2.2 million, respectively, are included from June 17, 2013, the effective date of acquisition.

Marcellus Override. In December 2012, the Partnership acquired an overriding royalty interest on approximately 88,000 net acres of overriding royalty interests in oil and gas reserves located in the Marcellus Shale for $30.3 million.

Colt. In September 2009, the Partnership signed a definitive agreement to acquire approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt, LLC, an affiliate of Foresight Energy, through several separate transactions for a total purchase price of $255 million. During the year ended December 31, 2012, the Partnership paid $80.0 million to complete the acquisition of reserves at this mine.

Oklahoma Oil and Gas. From December 2011 through June 2012, the Partnership acquired approximately 19,200 net mineral acres located in the Mississippian Lime oil play in Northern Oklahoma for approximately $63.9 million, of which 15,600 net mineral acres were acquired during 2012 for $51.3 million.

Sugar Camp. In March 2012, the Partnership acquired from Sugar Camp Energy, an affiliate of Foresight Energy, the rail loadout and associated infrastructure assets at the Sugar Camp mine in Illinois for total consideration of $50.0 million. At the time of the acquisition, the Partnership also entered into a lease agreement related to the rail loadout and associated facilities that has been accounted for as a direct financing lease. The lease provides for payments based upon tons of coal transported over the facilities subject to quarterly recoupable minimum payments of $1.25 million. The lease is for a term of 20 years but may be extended by the lessee. Total projected remaining payments under the lease at December 31, 2013 are $91.2 million with unearned income of $42.8 million. The unearned income will be reflected as transportation fees over the term of the lease using the effective interest method. Any amounts in excess of the contractual minimums will be recorded as transportation fees when earned. The net amount receivable under the lease as of December 31, 2013 was $48.5 million, of which $1.6 million is included in accounts receivable – affiliates while the remaining is included in long-term contracts receivable—affiliate. The Partnership recognized $5.1 million in transportation fees during the year ended December 31, 2013 related to this lease.

In a separate transaction, the Partnership acquired, from Ruger, LLC, an affiliate of Foresight Energy, a contractual overriding royalty interest for $8.9 million that will provide for payments based upon production from specific tons at the Sugar Camp operations. This overriding royalty was accounted for as a financing arrangement and is reflected as an affiliate receivable. The payments the Partnership receives with respect to the overriding royalty will be reflected partially as a return of the initial investment and partially as override revenue over the life of the contract using the effective interest method based upon actual production and adjusted periodically for differences in projected and actual production. The net amount receivable under the agreement as of December 31, 2013 was $6.1 million of which $1.2 million is included in accounts receivable – affiliates while the remaining is included in long-term contracts receivable—affiliate. The Partnership recognized $1.3 million in overriding royalty during the year ended December 31, 2013 related to the contractual overriding royalty interest.

4. Equity and Other Investments

In January 2013, the Partnership acquired non-controlling equity interests in OCI Wyoming Co. (OCI Co) and OCI Wyoming, L.P. (OCI LP), an operator of a trona mining and soda ash refinery business. At the time of acquisition, (1) the acquired interests comprised a 48.51% general partner interest in OCI LP and 20% of the common stock and 100% of the preferred stock in OCI Co, (2) OCI Co owned a 1% limited partner interest in OCI LP and the right to receive a $14.5 million annual priority distribution and (3) 80% of the common stock in OCI Co was owned by OCI Chemical Corporation, and the remaining 50.49% general partner interest in OCI LP was owned by OCI Wyoming Holding Co., a subsidiary of OCI Chemical Corporation.

The three investments were acquired from Anadarko Holding Company (Anadarko) and its subsidiary, Big Island Trona Company for $292.5 million. The purchase price was funded from the proceeds of a $200 million term loan, $76.5 million in equity and GP interests issued in a private placement and the balance from operating cash. The acquisition agreement provides for a net present value of up to $50 million in cumulative additional contingent consideration payable by the Partnership should certain performance criteria be met at OCI LP as defined in the purchase and sale agreement in any of the years 2013, 2014 or 2015. At December 31, 2013, the Partnership accrued $15 million of contingent consideration that is included in Equity and other unconsolidated investments. The current portion of $0.7 million is included in Accounts payable and accrued liabilities and the long term portion of $14.3 million is included in Other non-current liabilities.

In July 2013, OCI LP was reorganized pursuant to a series of transactions in connection with an initial public offering by OCI Resources LP, an affiliate of OCI Chemical Corporation, of its interest in OCI LP. In connection with such reorganization, the Partnership exchanged its common stock and preferred stock in OCI Co for a limited partner interest in OCI LP, and OCI Resources LP became the owner of the limited partner interests in OCI LP that were previously owned by OCI Wyoming Holding Co. Following the reorganization, the Partnership’s interest in OCI LP increased to 49%, consisting of both limited and general partner interests. The restructuring did not have any impact on the operations, revenues, management or control of OCI LP.

With respect to the contingent consideration, in February 2014, Anadarko raised in oral discussions with the Partnership whether the reorganization transactions triggered an acceleration of the Partnership’s obligation to pay the additional contingent consideration in full. Although Anadarko has not made a formal claim against the Partnership, Anadarko has indicated that it may do so in the near future. The Partnership does not believe the reorganization transactions triggered an obligation to pay the additional contingent consideration, and the Partnership will continue to engage in discussions with Anadarko to resolve Anadarko’s concerns. However, if Anadarko were to prevail on such a claim, the Partnership would be required to pay an amount to Anadarko in excess of the $15 million accrual described above up to the maximum amount of the additional contingent consideration. Any such additional amount would be considered to be additional acquisition consideration and added to Equity and other unconsolidated investments.

The Partnership engaged a valuation specialist to assist in identifying and valuing the assets and liabilities of OCI Wyoming at the date of acquisition, including the land, mine, plant and equipment as well as identifiable intangible assets. Included in fair value adjustments, is an increase in the Partnership’s proportionate fair value of property, plant and equipment of $58.0 million, which will be depreciated using the straight-line method over a weighted average life of 28 years. Also, $133.0 million has been assigned to a right to mine asset which will be amortized using the units of production method. Under the equity method of accounting, these amount are not reflected individually in the accompanying consolidated financial statements but are used to determine periodic charges to amounts reflected as income earned from the equity investments. For the year ended December 31, 2013, amortization of basis difference of $2.9 million was recorded by the Partnership.

The following is summarized balance sheet information as of December 31, 2013 and the results of operations for the year then ended relating to the Partnership’s investment in OCI Wyoming.

Operating results:


	For the Year Ended December 31, 2013
	(In thousands)
Net sales	$	442,132
Gross profit	$	94,299
Net income	$	79,655
Income allocation to NRP’s equity interests	$	37,036
Amortization of basis difference	$	(2,850	)
Equity and other unconsolidated investment income	$	34,186

Balance Sheet information:


	December 31, 2013
	(In thousands)
Current assets	$	201,265
Property, plant and equipment	$	193,277
Other assets	$	1,231
Total assets	$	395,773
Current liabilities	$	39,663
Long term debt	$	155,000
Other liabilities	$	3,779
Members equity	$	197,331
Total liabilities and capital	$	395,773
Net book value of NRP’s equity interests	$	96,692
Equity and other unconsolidated investments	$	269,338
Excess of NRP’s investment over net book value of NRP’s equity interests	$	172,646

5. Allowance for Doubtful Accounts

Activity in the allowance for doubtful accounts for the years ended December 31, 2013, 2012 and 2011 was as follows:


	2013			2012		2011
	(In thousands)
Balance, January 1	$	711		$	393	$	681
Provision charged to operations:
Additions to the reserve		278			318		71
Collections of previously reserved accounts		—			—		(359	)

Total charged (credited) to operations		278			318		(288	)
Non-recoverable balances written off		(714	)		—		—

Balance, December 31	$	275		$	711	$	393

6. Asset Impairments

For the year ended December 31, 2013, the Partnership recorded asset impairments of $0.7 million on two aggregate properties on BRP LLC. There were no other impairments recorded during 2013.

Gatling West Virginia. In October 2011, the Partnership was informed by Gatling, LLC, a Cline affiliate, that it was idling the operations and was no longer projecting production from the West Virginia mine. The Partnership and Gatling amended the lease with respect to this property to provide that the existing minimum royalty balance of $24.1 million was non-recoupable, that Gatling pay $3.4 million in non-recoupable minimum royalties when they became due in January and April of 2012, that the minimums would be reduced after the first quarter of 2012, and that Gatling would continue to maintain and ventilate the mine. Following the amendment, Gatling satisfied all terms of the lease. Considering all information available at the time of amendment, the Partnership determined that its investment in the Gatling West Virginia property was not fully recoverable by future cash flows. The assets at the time of amendment included coal reserves, certain above market intangibles and coal transportation equipment.

The 2011 asset impairment of $118.4 million was offset by $24.1 million of recoupable minimum payments received from Gatling, LLC to date and $3.4 million in cash payments received in 2012, resulting in a net asset

impairment of $90.9 million, which is included in operating expenses on the Consolidated Statements of Comprehensive Income.

In December 2012, the Partnership was informed by Gatling that it was dismantling their preparation plant and removing it from the site and cancelling the lease effective June 2013. The Partnership considered this new information as another impairment triggering event and reassessed the remaining coal reserves and coal transportation equipment fair values for impairment. The fair values of both the remaining reserves and transportation equipment were determined using Level 2 market approaches based upon recent comparable transactions. The reserves were adjusted for the mine’s specific characteristics. The 2012 asset impairment of $2.6 million is included in operating expenses on the Consolidated Statements of Comprehensive Income. There were no further indicators of impairment since December 2012 on this property.

The net book value and calculated fair values of the assets relating to the Gatling West Virginia operation were as follows:


	2012 Measurement Date				2011 Measurement Date
	Fair Value		Net Book Value		Fair Value		Net Book Value
	(In thousands)
Coal and other mineral rights, net	$	4,050	$	6,618	$	6,618	$	76,003
Intangible assets, net		—		—		—		43,855
Plant and equipment, net		1,981		1,981		2,600		7,775

Total	$	6,031	$	8,599	$	9,218	$	127,633

Gatling Ohio. In December 2011, the Partnership was informed by Gatling Ohio, LLC, a Cline affiliate, that it was idling its operations and was no longer projecting production from the Ohio mine. Gatling Ohio’s recoupable minimum royalty balance as of December 31, 2011 was $9.6 million. Considering all information the Partnership determined that its investment in the Gatling Ohio property would not be fully recovered by future cash flows. The assets include coal reserves, certain above market intangibles and coal transportation equipment. The asset impairment of $70.4 million is included in operating expenses in 2011 on the Consolidated Statements of Income. There were no further indicators of impairment since December 2012 on this property.

The net book value as of the measurement date and calculated fair values of the assets relating to the Gatling Ohio operation are as follows:


	2011 Measurement Date
	Fair Value		Net Book Value
	(In thousands)
Coal and other mineral rights, net	$	20,035	$	56,769
Intangible assets, net		—		33,670
Plant and equipment, net		2,947		2,947

Total	$	22,982	$	93,386

In determining the 2011 impairments of the Gatling West Virginia and Gatling Ohio assets, the fair values of the coal rights were estimated using a weighted combination of Level 3 expected cash flow and Level 2 market approaches. The fair values of the transportation equipment were estimated using Level 2 market approaches. The expected cash flows were developed using estimated annual sales tons, as well as forecasted sales prices and anticipated market royalty rates. The market approaches include references to recent comparable transactions that were adjusted for each mine’s specific characteristics. Since Gatling, LLC is no longer projecting production in the near term future for the West Virginia and Ohio properties, the related royalty and transportation contract intangible assets were estimated to have no fair value as of the measurement date.

7. Plant and Equipment

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


	December 31, 2013			December 31, 2012
	(In thousands)
Plant and equipment at cost	$	55,271		$	55,271
Less accumulated depreciation		(28,836	)		(22,870	)

Net book value	$	26,435		$	32,401


	For the years ended December 31,
	2013		2012		2011
	(In thousands)
Total depreciation expense on plant and equipment	$	5,966	$	6,825	$	8,589

During the third quarter of 2012, the Partnership sold a preparation plant to Taggart Global USA, LLC, a related party, for $12.3 million. The Partnership received $10.5 million in cash and a note receivable from Taggart, payable over three years for the balance. The Partnership recorded a gain of $4.7 million in 2012 and it is included in Other revenues of the Consolidated Statements of Comprehensive Income. The note receivable balance at December 31, 2012 was $1.7 million and was paid in full during 2013.

8. Mineral Rights

The Partnership’s mineral rights consist of the following:


	December 31, 2013			December 31, 2012
	(In thousands)
Mineral rights	$	1,894,920		$	1,815,423
Less accumulated depletion and amortization		(489,465	)		(434,950	)

Net book value	$	1,405,455		$	1,380,473


	For the years ended December 31,
	2013		2012		2011
	(In thousands)
Total depletion and amortization expense on mineral interests	$	54,595	$	47,042	$	47,230

9. Intangible Assets

Amounts recorded as intangible assets along with the balances and accumulated amortization at December 31, 2013 and 2012 are reflected in the table below:


	December 31, 2013			December 31, 2012
	(In thousands)
Contract intangibles	$	89,421		$	89,421
Less accumulated amortization		(22,471	)		(18,655	)

Net book value	$	66,950		$	70,766


	For the years ended December 31,
	2013		2012		2011
	(In thousands)
Total amortization expense on intangible assets	$	3,816	$	4,354	$	9,298

The estimates of amortization expense for the periods as indicated below are based on current mining plans and are subject to revision as those plans change in future periods.


Estimated amortization expense (In thousands)
For year ended December 31, 2014	$	3,126
For year ended December 31, 2015		3,543
For year ended December 31, 2016		3,508
For year ended December 31, 2017		3,508
For year ended December 31, 2018		3,508

10. Long-Term Debt

As used in this Note 10, references to “NRP LP” refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to “Opco” refer to NRP (Operating) LLC and its subsidiaries. References to NRP Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP LP. NRP Finance Corporation (NRP Finance) is a wholly owned subsidiary of NRP LP and a co-issuer with NRP LP on the 9.125% senior notes.

Long-term debt consists of the following:


	December 31, 2013		December 31, 2012
	(In thousands)
NRP LP Debt:
$300 million 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018, issued at 99.007%	$	297,170	$	—
Opco Debt:
$300 million floating rate revolving credit facility, due August 2016		20,000		148,000
$200 million floating rate term loan, due January 2016		99,000		—
5.55% senior notes, with semi-annual interest payments in June and December, maturing June 2013		—		35,000
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018		23,084		27,700
8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2019		128,571		150,000
5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020		53,846		61,538
5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021		1,538		1,731
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023		27,000		30,300
4.73% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2023		75,000		75,000


	December 31, 2013			December 31, 2012
	(In thousands)
5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2024		165,000			180,000
8.92% senior notes, with semi-annual interest payments in March and September, with scheduled principal payments beginning March 2014, maturing in March 2024		50,000			50,000
5.03% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026		175,000			175,000
5.18% senior notes, with semi-annual interest payments in June and December, with scheduled principal payments beginning December 2014, maturing in December 2026		50,000			50,000
NRP Oil and Gas Debt:
Reserve-based revolving credit facility due 2018		—			—

Total debt		1,165,209			984,269
Less — current portion of long term debt		(80,983	)		(87,230	)

Long-term debt	$	1,084,226		$	897,039

NRP LP Debt

Senior Notes. In September 2013, NRP LP, together with NRP Finance as co-issuer, issued $300 million of 9.125% senior notes at an offering price of 99.007% of par value. Net proceeds after expenses from the issuance of the senior notes of approximately $289.0 million were used to repay all of the outstanding borrowings under Opco’s revolving credit facility and $91.0 million of Opco’s term loan. The senior notes call for semi-annual interest payments on April 1 and October 1 of each year, beginning on April 1, 2014. The notes will mature on October 1, 2018.

The indenture for the senior notes contains covenants that, among other things, limit the ability of the NRP LP and certain of its subsidiaries to incur or guarantee additional indebtedness. Under the indenture, NRP LP and certain of its subsidiaries generally are not permitted to incur additional indebtedness unless, on a consolidated basis, the fixed charge coverage ratio (as defined in the indenture) is at least 2.0 to 1.0 for the four preceding full fiscal quarters. The ability of NRP LP and certain of its subsidiaries to incur additional indebtedness is further limited in the event the amount of indebtedness of NRP LP and certain of its subsidiaries that is senior to NRP LP’s unsecured indebtedness exceeds certain thresholds.

Opco Debt

Senior Notes. Opco made principal payments of $87.0 million on its senior notes during the year ended December 31, 2013. The Opco senior note purchase agreement contains covenants requiring Opco to:

•

Maintain a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four most recent quarters;

•

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

•

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

The 8.38% and 8.92% senior notes also provide that in the event that Opco’s leverage ratio exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00.

Revolving Credit Facility. The weighted average interest rates for the debt outstanding under Opco’s revolving credit facility for the twelve months ended December 31, 2013 and year ended December 31, 2012 were 2.23% and 2.09%, respectively. Opco incurs a commitment fee on the undrawn portion of the revolving credit facility at rates ranging from 0.18% to 0.40% per annum. The facility includes an accordion feature whereby Opco may request its lenders to increase their aggregate commitment to a maximum of $500 million on the same terms.

Opco’s revolving credit facility contains covenants requiring Opco to maintain:

•

a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to exceed 4.0 to 1.0 and,

•

a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of not less than 3.5 to 1.0 for the four most recent quarters.

Term Loan Facility. During the first quarter of 2013, Opco also issued $200 million in term debt. The weighted average interest rate for the debt outstanding under the term loan for the twelve months ended December 31, 2013 was 2.43%. Opco repaid $101 million in principal under the term loan during the third quarter of 2013. Repayment terms call for the remaining outstanding balance of $99 million to be paid on January 23, 2016. The debt is unsecured but guaranteed by the subsidiaries of Opco.

Opco’s term loan contains covenants requiring Opco to maintain:

•

a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to exceed 4.0 to 1.0 and,

•

NRP Oil and Gas Debt

Revolving Credit Facility. In August 2013, NRP Oil and Gas entered into a 5-year, $100 million senior secured, reserve-based revolving credit facility in order to fund capital expenditure requirements related to the development of the non-operated working interests in oil and gas assets located in the Bakken/Three Forks play acquired on August 9, 2013. The credit facility has a borrowing base of $16.0 million as of December 31, 2013 and is secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. At December 31, 2013, there were no borrowings outstanding under the credit facility.

Indebtedness under the NRP Oil and Gas credit facility bears interest, at the option of NRP Oil and Gas, at either:

•

the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 1%, in each case plus an applicable margin ranging from 0.50% to 1.50%; or

•

a rate equal to LIBOR, plus an applicable margin ranging from 1.75% to 2.75%.

NRP Oil and Gas will incur a commitment fee on the unused portion of the borrowing base under the credit facility at a rate ranging from 0.375% to 0.50% per annum.

The NRP Oil and Gas credit facility contains certain covenants, which, among other things, require the maintenance of:

•

a total leverage ratio (defined as the ratio of the total debt of NRP Oil and Gas to its EBITDAX) of not more than 3.5 to 1.0; and

•

a minimum current ratio of 1.0 to 1.0.

Consolidated Principal Payments

The consolidated principal payments due are set forth below:


	NRP LP			OPCO						NRP Oil & Gas
	Senior Notes			Senior Notes		Credit Facility		Term Loan		Credit Facility		Total
	(In thousands)
2014	$	—		$	80,983	$	—	$	—	$	—	$	80,983
2015		—			80,983		—		—		—		80,983
2016		—			80,983		20,000		99,000		—		199,983
2017		—			80,983		—		—		—		80,983
2018		300,000	(1)		80,983		—		—		—		380,983
Thereafter		—			344,124		—		—		—		344,124

	$	300,000		$	749,039	$	20,000	$	99,000	$	—	$	1,168,039

(1)	The 9.125% senior notes due 2018 were issued at a discount and as of December 31, 2013 were carried at $297.2 million.

NRP LP, Opco and NRP Oil and Gas were in compliance with all terms under their long-term debt as of December 31, 2013.

11. Fair Value Measurements

The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of the Partnership’s financial instruments included in accounts receivable and accounts payable approximates their fair value due to their short-term nature except for the accounts receivable – affiliate relating to the Sugar Camp override and Taggart preparation plant sale that includes both current and long-term portions. The Partnership’s cash and cash equivalents include money market accounts and are considered a Level 1 measurement. The fair market value and carrying value of the contractual override, Taggart note receivable and long-term senior notes are as follows:


	Fair Value As Of				Carrying Value As Of
	December 31, 2013		December 31, 2012		December 31, 2013		December 31, 2012
	(In thousands)
Assets
Sugar Camp override, current and long-term	$	6,852	$	8,817	$	6,063	$	7,495
Taggart plant receivable, current and long term	$	—	$	1,668	$	—	$	1,667
Liabilities
Long-term debt, current and long-term	$	1,071,880	$	876,574	$	1,046,209	$	836,269

The fair value of the Sugar Camp override, Taggart plant receivable and long-term debt is estimated by management using comparable term risk-free treasury issues with a market rate component determined by current financial instruments with similar characteristics which is a Level 3 measurement. Since the Partnership’s credit facility is variable rate debt, its fair value approximates its carrying amount.

12. Related Party Transactions

Reimbursements to Affiliates of our General Partner

The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for expenses incurred on the Partnership’s behalf. All direct general and administrative expenses are charged to the Partnership as incurred. The Partnership also reimburses indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates.

The reimbursements to affiliates of the Partnership’s general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation are as follows:


	For the Years Ended December 31,
	2013		2012		2011
	(In thousands)
Reimbursement for services	$	11,480	$	9,791	$	9,136

The Partnership leases an office building in Huntington, West Virginia from Western Pocahontas Properties and pays $0.6 million in lease payments each year through December 31, 2018.

Transactions with Cline Affiliates

Various companies controlled by Chris Cline, including Foresight Energy, lease coal reserves from the Partnership, and the Partnership provides coal transportation services to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest (unaudited) in the Partnership’s general partner, as well as 4,917,548 common units (unaudited) at December 31, 2013. At December 31, 2013, the Partnership had accounts receivable totaling $7.7 million from Cline affiliates. In addition, the overriding royalty and the lease of the loadout facility at the Sugar Camp mine are classified as contracts receivable of $51.7 million on the Partnership’s Consolidated Balance Sheets. Revenues from the Cline affiliates are as follows:


	For The Years Ended December 31,
	2013		2012		2011
	(In thousands)
Coal royalty revenues	$	54,322	$	48,567	$	42,474
Processing fees		1,281		2,409		2,975
Transportation fees		17,977		19,514		16,689
Minimums recognized as revenue		3,477		17,785		—
Override revenue		3,226		4,066		2,691
Other revenue		8,149		—		2,990

	$	88,432	$	92,341	$	67,819

As of December 31, 2013, the Partnership had received $71.4 million in minimum royalty payments that have not been recouped by Cline affiliates, of which $20.0 million was received in the current year.

The Partnership recognized an asset impairment of $90.9 million during the third quarter of 2011 related to certain of the Partnership’s assets at the Gatling WV location and $70.4 million during the fourth quarter of 2011

related to certain assets at the Gatling Ohio location. During the fourth quarter of 2012, the Partnership recognized an additional asset impairment of $2.6 million related to the assets at the Gatling WV location due to receiving a termination notice in December 2012 that the lease was cancelled as of June 2013.

During 2013 and 2011, the Partnership recognized gains of $8.1 million and $3.0 million on a reserve swap in Illinois with Williamson Energy. The gains are reflected in the table above in the “Other revenue” line. The fair value of the reserves was estimated using Level 3 cash flow approach. The expected cash flows were developed using estimated annual sales tons, forecasted sales prices and anticipated market royalty rates. The tons received during 2013 were fully mined during 2013 and the tons received during 2011 were fully mined during 2012, while the tons exchanged are not included in the current mine plans. The gains are located in Other revenues on the Consolidated Statements of Comprehensive Income.

Quintana Capital Group GP, Ltd.

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

A fund controlled by Quintana Capital owned a significant membership interest in Taggart Global USA, LLC, including the right to nominate two members of Taggart’s 5-person board of directors. Subsequent to the end of the second quarter, Taggart was sold to Forge Group, and Quintana no longer retains an interest in Taggart or Forge. The Partnership owns and leases preparation plants to Forge, which operates the plants. The lease payments were based on the sales price for the coal that was processed through the facilities.

For the years ended December 31, 2013, 2012 and 2011, the revenues from Taggart were as follows:


	For the Years Ended December 31,
	2013		2012		2011
	(In thousands)
Processing revenue	$	1,761	$	5,580	$	9,755

During the third quarter of 2012, the Partnership sold a preparation plant back to Taggart Global for $12.3 million. The Partnership received $10.5 million in cash and a note receivable from Taggart, payable over three years for the balance. The Partnership recorded a gain of $4.7 million included in Other income of the Consolidated Statements of Income for the third quarter of 2012. The net book value of the asset sold was $7.6 million. During 2013, when Taggart was sold to Forge the note receivable that we held was paid in full.

At December 31, 2013, a fund controlled by Quintana Capital owned a majority interest in Corsa Coal Corp., a coal mining company traded on the TSX Venture Exchange that is one of the Partnership’s lessees in Tennessee. Corbin J. Robertson III, one of the Partnership’s directors, is Chairman of the Board of Corsa. Revenues from Corsa are as follows:


	For the Years Ended December 31,
	2013		2012		2011
	(In thousands)
Coal royalty revenues	$	4,594	$	3,486	$	1,629

At December 31, 2013, the Partnership also had accounts receivable totaling $0.3 million from Corsa.

13. Commitments and Contingencies

Legal

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

Environmental Compliance

The operations our lessees conduct on the Partnership’s properties, as well as the aggregates/industrial minerals and oil and gas operations in which the Partnership has interests, are subject to federal and state environmental laws and regulations. As an owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring on the surface properties. The terms of substantially all of the Partnership’s coal, aggregates and industrial mineral 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 the Partnership has 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. The Partnership believes 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. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on the Partnership related to our properties for the period ended December 31, 2013. The Partnership is not associated with any environmental contamination that may require remediation costs. However, the Partnership’s lessees do conduct reclamation work on the properties under lease to them. Because the Partnership is not the permittee of the mines being reclaimed, the Partnership is not responsible for the costs associated with these reclamation operations. In addition, West Virginia has established a fund to satisfy any shortfall in reclamation obligations. As an owner of working interests in oil and natural gas operations, the Partnership is responsible for its proportionate share of any losses and liabilities, including environmental liabilities, arising from uninsured and underinsured events.

The electric utility industry, which is the most significant end-user of domestic coal, is subject to extensive regulation regarding the environmental impact of its power generation activities. On January 8, 2014, EPA published proposed new source performance standards for greenhouse gas emissions from new fossil fuel-fired electric generating units. The effect of the proposed rules would be to require partial carbon capture and sequestration on any new coal-fired power plants, which may amount to their effective prohibition. President Obama has directed EPA to issue proposed regulations on existing fossil fuel-fired power plants in June 2014. The Partnership expects that EPA’s proposed regulations for both new and existing power plants will negatively affect the viability of coal-fired power generation, which will ultimately reduce coal consumption and the production of coal from the Partnership’s properties.

14. Major Lessees

The Partnership has the following lessees that generated in excess of ten percent of total revenues in any one of the years ended December 31, 2013, 2012, and 2011. Revenues from these lessees are as follows:


	For the Years Ended December 31,
	2013					2012					2011
	Revenues		Percent			Revenues		Percent			Revenues		Percent
	(Dollars in thousands)
Foresight Energy and affiliates	$	88,432		24.7	%	$	92,341		24.4	%	$	67,819		18.0	%
Alpha Natural Resources	$	55,147		15.4	%	$	81,077		21.4	%	$	107,267		28.4	%

In 2013, the Partnership derived 40.1% of its revenue from two companies listed above. As a result, the Partnership has a significant concentration of revenues with those lessees, although in most cases, with the exception of the Williamson mine operated by an affiliate of Foresight Energy, the exposure is spread over a number of different mining operations and leases. Foresight’s Williamson mine alone was responsible for approximately 13.0%, 12.4% and 11.7% of our total revenues for 2013, 2012 and 2011, respectively.

Substantially all of the Partnership’s accounts receivable result from amounts due from third-party companies in the coal industry, with approximately 41% of our total revenues being attributable to coal royalty revenues from Appalachia. This concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be collectively affected by the same changes in economic or other conditions. Receivables are generally not collateralized.

15. Incentive Plans

GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the “Long-Term Incentive Plan”) for directors of GP Natural Resource Partners LLC and employees of its affiliates who perform services for the Partnership. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.

Under the plan a grantee will receive the market value of a common unit in cash upon vesting. Market value is defined as the average closing price over the 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.

A summary of activity in the outstanding grants for the year ended December 31, 2013 are as follows:


Outstanding grants at the beginning of the period	912,314
Grants during the period	369,947
Grants vested and paid during the period	(246,372	)
Forfeitures during the period	(22,905	)

Outstanding grants at the end of the period	1,012,984

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 common units and because of changes in estimated fair value determined each quarter using the Black-Scholes option valuation model. Risk free interest rates and historical volatility are reset at each calculation based on current rates corresponding to the remaining vesting term for each outstanding grant and ranged from 0.18% to 0.80% and 24.33% to 31.94%, respectively at December 31, 2013. The Partnership’s cumulative average dividend rate of 7.32% was used in the calculation at December 31, 2013. The Partnership accrued expenses related to its plans to be reimbursed to its general partner of $9.6 million, $2.9 million and $7.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. In connection with the Long-Term Incentive Plans, cash payments of $7.0 million, $6.6 million and $5.7 million were paid during each of the years ended December 31, 2013, 2012, and 2011, respectively. The grant date fair value was $25.27, $33.38 and $42.93 per unit for awards in 2013, 2012 and 2011, respectively.

In connection with the phantom unit awards, the CNG committee also granted tandem Distribution Equivalent Rights, or DERs, which entitle the holders to receive distributions equal to the distributions paid on

the Partnership’s common units. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting.

The unaccrued cost, associated with unvested outstanding grants and related DERs at December 31, 2013, was $9.3 million.

16. Subsequent Events (Unaudited)

The following represents material events that have occurred subsequent to December 31, 2013 through the time of the Partnership’s filing its Form 10-K with the SEC:

Distributions

On January 9, 2014, the Partnership declared a distribution of $0.35 per unit to be paid on January 31, 2014 to unitholders of record on January 21, 2014.

Dividends and Distributions Received From Unconsolidated Equity and Other Investments

Subsequent to December 31, 2013, the Partnership received $11.6 million in cash distributions from its investments in OCI.

17. Supplemental Financial Data (Unaudited)

Shown below are selected unaudited quarterly data.

Selected Quarterly Financial Information

(In thousands, except per unit data)


2013	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Total revenues and other income	$	94,332	$	86,804	$	82,237	$	94,744
Depreciation, depletion and amortization	$	14,762	$	17,411	$	17,852	$	14,352
Income from operations	$	62,528	$	55,332	$	51,624	$	66,752
Net income	$	47,906	$	41,065	$	36,126	$	46,981
Net income per limited partner unit	$	0.43	$	0.37	$	0.32	$	0.42
Weighted average number of common units outstanding		108,887		109,812		109,812		109,812


2012	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Total revenues and other income	$	91,872	$	90,664	$	94,175	$	102,436
Depreciation, depletion and amortization	$	12,409	$	15,172	$	14,485	$	16,155
Income from operations	$	64,824	$	63,492	$	65,643	$	73,206
Net income	$	51,309	$	49,938	$	52,001	$	60,107
Net income per limited partner unit	$	0.47	$	0.46	$	0.48	$	0.56
Weighted average number of common units outstanding		106,028		106,028		106,028		106,028

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)(1) and (2) Financial Statements and Schedules

See Item 8, “Financial Statements and Supplementary Data.”

(a)(3) Exhibits


Exhibit Number		Description

2.1	—	Purchase Agreement, dated as of January 23, 2013, by and among Anadarko Holding Company, Big Island Trona Company, NRP Trona LLC and NRP (Operating) LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on January 25, 2013).

3.1	—	Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of September 20, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on September 21, 2010).

3.2	—	Fifth Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of December 16, 2011 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on December 16, 2011).

3.3	—	Fifth Amended and Restated Limited Liability Company Agreement of GP Natural Resource Partners LLC, dated as of October 31, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on October 31, 2013).

3.4	—	Amended and Restated Limited Liability Company Agreement of NRP (Operating) LLC, dated as of October 17, 2002 (incorporated by reference to Exhibit 3.4 of the Annual Report on Form 10-K for the year ended December 31, 2002).

3.5	—	Certificate of Limited Partnership of Natural Resource Partners L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 filed April 19, 2002, File No. 333-86582).

4.1	—	Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the Purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed June 23, 2003).

4.2	—	First Amendment, dated as of July 19, 2005, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on July 20, 2005).

4.3	—	Second Amendment, dated as of March 28, 2007, to Note Purchase Agreement dated as of June 19, 2003 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on March 29, 2007).

4.4	—	First Supplement to Note Purchase Agreement, dated as of July 19, 2005 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on July 20, 2005).

4.5	—	Second Supplement to Note Purchase Agreement, dated as of March 28, 2007 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on March 29, 2007).

4.6	—	Third Supplement to Note Purchase Agreement, dated as of March 25, 2009 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on March 26, 2009).


Exhibit Number		Description

4.7	—	Fourth Supplement to Note Purchase Agreement, dated as of April 20, 2011 among NRP (Operating) LLC and the purchasers signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 21, 2011).

4.8	—	Subsidiary Guarantee of Senior Notes of NRP (Operating) LLC, dated June 19, 2003 (incorporated by reference to Exhibit 4.5 to the Current Report on Form 8-K filed June 23, 2003).

4.9	—	Form of Series A Note (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed June 23, 2003).

4.10	—	Form of Series B Note (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed June 23, 2003).

4.11	—	Form of Series C Note (incorporated by reference to Exhibit 4.4 to the Current Report on Form 8-K filed June 23, 2003).

4.12	—	Form of Series D Note (incorporated by reference to Exhibit 4.12 to the Annual Report on Form 10-K filed February 28, 2007).

4.13	—	Form of Series E Note (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed March 29, 2007).

4.14	—	Form of Series F Note (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q filed May 7, 2009).

4.15	—	Form of Series G Note (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q filed May 7, 2009).

4.16	—	Form of Series H Note (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q filed May 5, 2011).

4.17	—	Form of Series I Note (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q filed May 5, 2011).

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

4.19	—	Form of Series K Note (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on October 3, 2011).

4.20	—	Registration Rights Agreement, dated as of January 23, 2013, by and among Natural Resource Partners L.P. and the Investors named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on January 25, 2013).

4.21	—	Amendment No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated March 6, 2012 (incorporated by reference to Exhibit 4.1 to Quarterly Report on Form 10-Q filed on May 4, 2012).

4.22	—	Indenture, dated September 18, 2013, by and among Natural Resource Partners L.P. and NRP Finance Corporation, as issuers, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on September 19, 2013).

4.23	—	Form of 9.125% Senior Notes due 2018 (contained in Exhibit 1 to Exhibit 4.22).

4.24	—	Registration Rights Agreement, dated September 18, 2013, by and among Natural Resource Partners L.P., NRP Finance Corporation and Citigroup Global Markets Inc., as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed on September 19, 2013).

10.1	—	Second Amended and Restated Credit Agreement, dated as of August 10, 2011 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 11, 2011).

10.2	—	First Amendment to the Second Amended and Restated Credit Agreement, dated as of January 23, 2013 (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed on January 25, 2013).


Exhibit Number		Description

10.3	—	Second Amendment to the Second Amended and Restated Credit Agreement, dated as of June 7, 2013 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 10, 2013).

10.4	—	Contribution Agreement, dated as of September 20, 2010, by and among Natural Resource Partners L.P., NRP (GP) LP, Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation and NRP Investment L.P. (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on September 21, 2010).

10.5**	—	Natural Resource Partners Second Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 17, 2008).

10.6**	—	Form of Phantom Unit Agreement (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K for the year ended December 31, 2007).

10.7**	—	Natural Resource Partners Annual Incentive Plan (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K for the year ended December 31, 2002).

10.8	—	First Amended and Restated Omnibus Agreement, dated as of April 22, 2009, by and among Western Pocahontas Properties Limited Partnership, Great Northern Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed May 7, 2009).

10.9	—	Restricted Business Contribution Agreement, dated January 4, 2007, by and among Christopher Cline, Foresight Reserves LP, Adena Minerals, LLC, GP Natural Resource Partners LLC, NRP (GP) LP, Natural Resource Partners L.P. and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 4, 2007).

10.10	—	Investor Rights Agreement, dated January 4, 2007, by and among NRP (GP) LP, GP Natural Resource Partners LLC, Robertson Coal Management and Adena Minerals, LLC (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on January 4, 2007).

10.11	—	Waiver Agreement, dated November 12, 2009, by and among Natural Resource Partners L.P., Great Northern Properties Limited Partnership, Western Pocahontas Properties Limited Partnership, New Gauley Coal Corporation, Robertson Coal Management LLC, GP Natural Resource Partners LLC, NRP (GP) LP, and NRP (Operating) LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on November 13, 2009).

10.12	—	Common Unit Purchase Agreement, dated January 23, 2013, by and among Natural Resource Partners, L.P. and the purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on January 25, 2013).

10.13	—	Term Loan Agreement, dated as of January 23, 2013, by and among Natural Resource Partners, L.P., Citibank, N.A., as administrative agent, Citigroup Global Markets, Inc., Wells Fargo Securities, LLC and Compass Bank, as joint lead arrangers and joint bookrunners and Wells Fargo Bank, National Association and Compass Bank, as co-syndication agents (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on January 25, 2013).

10.14	—	First Amendment to Term Loan Agreement, dated as of June 7, 2013 (incorporated by reference to Current Report on Form 8-K filed on June 10, 2013).

10.15	—	Third Amended and Restated Agreement of Limited Partnership of OCI Wyoming, L.P., dated September 18, 2013 (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed by OCI Resources LP on September 18, 2013).


Exhibit Number		Description

10.16	—	Credit Agreement, dated as of August 12, 2013, among NRP Oil and Gas LLC, Wells Fargo Bank, N.A., as Administrative Agent, and Wells Fargo Securities, LLC as Sole Bookrunner and Sole Lead Arranger (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 13, 2012).

10.17	—	First Amendment to Credit Agreement, dated effective as of December 19, 2013, among NRP Oil and Gas LLC, Wells Fargo Bank, N.A., as Administrative Agent, and Wells Fargo Securities, LLC as Sole Bookrunner and Sole Lead Arranger (incorporated by reference to Current Report on Form 8-K filed on December 20, 2013).

10.18	—	Purchase Agreement dated September 13, 2013 by and among Natural Resource Partners L.P., NRP Finance Corporation and Citigroup Global Markets Inc. (as the representative of the several initial purchasers) (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on September 17, 2013).

10.19	—	Equity Distribution Agreement dated November 12, 2013 by and among the Partnership, NRP (GP) LP, GP Natural Resource Partners LLC, and Citigroup Global Markets Inc. BB&T Capital Markets, a division of BB&T Securities, LLC, UBS Securities LLC and Wells Fargo Securities, LLC, as Managers (incorporated by reference to Exhibit 1.1 to Current Report on Form 8-K filed on November 12, 2013).

21.1***	—	List of subsidiaries of Natural Resource Partners L.P.

23.1*	—	Consent of Ernst & Young LLP.

23.2*	—	Consent of Deloitte & Touche LLP.

31.1*	—	Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.

31.2*	—	Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.

32.1*	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.

32.2*	—	Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.

99.1	—	Description of certain provisions of the Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P. (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed on September 21, 2010).

101*	—	The following financial information from the annual report on Form 10-K/A of Natural Resource Partners L.P. for the year ended December 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Comprehensive Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to Consolidated Financial Statements, tagged as blocks of text.

* Submitted herewith

** Management compensatory plan or arrangement

*** Previously submitted.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	NATURAL RESOURCE PARTNERS L.P.
	By:	NRP (GP) LP, its general partner
	By:	GP NATURAL RESOURCE
		PARTNERS LLC, its general partner
Date: November 13, 2014

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