Edgar Filing: NATURAL RESOURCE PARTNERS LP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2013

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

Commission file number: 001-31465

NATURAL RESOURCE PARTNERS L.P.

(Exact name of registrant as specified in its charter)

Delaware

35-2164875

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

601 Jefferson Street, Suite 3600

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 751-7507

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “accelerated filer”, “large accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


x	Large Accelerated Filer	¨	Accelerated Filer

¨	Non-accelerated Filer (Do not check if a smaller reporting company)	¨	Smaller Reporting Company

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

At August 7, 2013 there were 109,812,408 Common Units outstanding.

TABLE OF CONTENTS


	Page
PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012		4
Consolidated Statements of Comprehensive Income For the Three and Six Months Ended June 30, 2013 and 2012		5
Consolidated Statements of Cash Flows For the Six Months Ended June 30, 2013 and 2012		6
Consolidated Statements of Partners’ Capital for the Six Months ended June 30, 2013		7
Notes to Consolidated Financial Statements		8

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview		19
Results of Operations		23
Liquidity and Capital Resources		27
Related Party Transactions		30
Environmental		31

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		32

ITEM 4. Controls and Procedures		32

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings		33

ITEM 1A. Risk Factors		33

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds		33

ITEM 3. Defaults Upon Senior Securities		33

ITEM 4. Mine Safety Disclosures		33

ITEM 5. Other Information		33

ITEM 6. Exhibits		34

Signatures		35

Forward-Looking Statements

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

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

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

You should not put undue reliance on any forward-looking statements. Please read “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012 for important factors that could cause our actual results of operations or our actual financial condition to differ.

Part I. Financial Information

Item 1. Financial Statements

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)


ASSETS	June 30, 2013			December 31, 2012
ASSETS	(Unaudited)
Current assets:
Cash and cash equivalents	$	105,204		$	149,424
Accounts receivable, net of allowance for doubtful accounts		29,995			35,116
Accounts receivable – affiliates		13,597			10,613
Other		4,097			1,042

Total current assets		152,893			196,195
Land		24,340			24,340
Plant and equipment, net		29,268			32,401
Mineral rights, net		1,360,386			1,380,473
Intangible assets, net		69,064			70,766
Equity and other unconsolidated investments		279,877			—
Loan financing costs, net		5,383			4,291
Long-term contracts receivable – affiliate		54,080			55,576
Other assets, net		560			630

Total assets	$	1,975,851		$	1,764,672

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	3,399		$	3,693
Accounts payable – affiliates		1,472			957
Current portion of long-term debt		59,175			87,230
Accrued incentive plan expenses – current portion		7,056			7,718
Property, franchise and other taxes payable		6,593			7,952
Accrued interest		9,689			10,265

Total current liabilities		87,384			117,815
Deferred revenue		133,297			123,506
Accrued incentive plan expenses		8,308			8,865
Long-term debt		1,088,556			897,039
Partners’ capital:
Common units outstanding (109,812,408 and 106,027,836)		646,356			605,019
General partner’s interest		10,872			10,026
Non-controlling interest		1,416			2,845
Accumulated other comprehensive loss		(338	)		(443	)

Total partners’ capital		658,306			617,447

Total liabilities and partners’ capital	$	1,975,851		$	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)


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(Unaudited)						(Unaudited)
Revenues:
Coal royalties	$	58,210		$	62,878		$	112,652		$	122,794
Equity and other unconsolidated investment income, net		7,882			—			14,930			—
Aggregate royalties		1,751			1,702			3,303			3,418
Processing fees		1,329			3,138			2,509			5,264
Transportation fees		3,832			5,246			8,757			9,354
Oil and gas royalties		4,093			4,078			5,856			5,466
Property taxes		3,849			3,331			7,796			7,819
Minimums recognized as revenue		836			938			5,427			12,652
Override royalties		3,179			3,497			8,084			8,639
Other		1,843			5,856			11,822			7,130

Total revenues		86,804			90,664			181,136			182,536
Operating expenses:
Depreciation, depletion and amortization		17,411			15,172			32,173			27,581
Asset impairments		443			—			734			—
General and administrative		8,878			7,029			20,464			15,979
Property, franchise and other taxes		4,225			3,771			8,576			8,787
Transportation costs		328			527			787			1,000
Coal royalty and override payments		187			673			542			873

Total operating expenses		31,472			27,172			63,276			54,220

Income from operations		55,332			63,492			117,860			128,316
Other income (expense)
Interest expense		(14,440	)		(13,578	)		(29,103	)		(27,138	)
Interest income		173			24			214			69

Income before non-controlling interest		41,065			49,938			88,971			101,247
Non-controlling interest		—			—			—			—

Net income	$	41,065		$	49,938		$	88,971		$	101,247

Net income attributable to:
General partner	$	821		$	999		$	1,779		$	2,025

Limited partners	$	40,244		$	48,939		$	87,192		$	99,222

Basic and diluted net income per limited partner unit	$	0.37		$	0.46		$	0.80		$	0.94

Weighted average number of units outstanding		109,812			106,028			109,352			106,028

Comprehensive income	$	41,116		$	49,951		$	89,076		$	101,270

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Six Months Ended June 30,
	2013			2012
	(Unaudited)
Cash flows from operating activities:
Net income	$	88,971		$	101,247
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		32,173			27,581
Gain on reserve swap		(8,149	)		—
Equity and other unconsolidated investment income, net		(14,930	)		—
Distributions of earnings from unconsolidated investments		16,162			—
Non-cash interest charge, net		555			300
Gain on sale of assets		(150	)		(4,108	)
Asset impairment		734			—
Change in operating assets and liabilities:
Accounts receivable		4,250			5,851
Other assets		(2,985	)		24
Accounts payable and accrued liabilities		221			562
Accrued interest		(576	)		(158	)
Deferred revenue		9,951			6,551
Accrued incentive plan expenses		(1,219	)		(5,261	)
Property, franchise and other taxes payable		(1,359	)		(582	)

Net cash provided by operating activities		123,649			132,007

Cash flows from investing activities:
Acquisition of land and mineral rights		—			(94,453	)
Acquisition or construction of plant and equipment		—			(492	)
Acquisition of equity interests		(292,979	)		—
Distributions from unconsolidated investments		10,777			—
Proceeds from sale of assets		154			285
Return on direct financing lease and contractual override		555			904
Investment in direct financing lease		—			(59,009	)

Net cash used in investing activities		(281,493	)		(152,765	)

Cash flows from financing activities:
Proceeds from loans		243,000			73,000
Repayment of loans		(79,538	)		(23,108	)
Deferred financing costs		(1,621	)		—
Proceeds from issuance of units		75,000			—
Capital contribution by general partner		1,531			—
Costs associated with equity transactions		(60	)		—
Repayment of obligation related to acquisitions		—			(500	)
Distributions to partners		(124,688	)		(121,582	)

Net cash provided by (used in) financing activities		113,624			(72,190	)

Net (decrease) in cash and cash equivalents		(44,220	)		(92,948	)
Cash and cash equivalents at beginning of period		149,424			214,922

Cash and cash equivalents at end of period	$	105,204		$	121,974

Supplemental cash flow information:
Cash paid during the period for interest	$	29,085		$	26,976

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			Non-Controlling Interest			Accumulated Other Comprehensive
	Units		Amounts			Amounts			Amounts			Income (Loss)			Total
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		—		(60	)		—			—			—			(60	)
Distributions		—		(120,795	)		(2,464	)		(1,429	)		—			(124,688	)
Net income		—		87,192			1,779			—			—			88,971
Interest rate swap from unconsolidated investments		—		—			—			—			79			79
Loss on interest hedge		—		—			—			—			26			26

Comprehensive income		—		—			—			—			105			89,076

Balance at June 30, 2013		109,812,408	$	646,356		$	10,872		$	1,416		$	(338	)	$	658,306

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

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Basis of Presentation and Organization

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and six months ended June 30, 2013 are not necessarily indicative of the results that may be expected for future periods.

You should refer to the information contained in the footnotes included in Natural Resource Partners L.P.’s 2012 Annual Report on Form 10-K in connection with the reading of these unaudited interim consolidated financial statements.

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

In addition, the Partnership owns transportation and preparation equipment, other mineral related rights and oil and gas properties on which it earns revenue. In January 2013, the Partnership purchased non-controlling equity interests in OCI Wyoming, L.P. (“OCI Wyoming”) and OCI Wyoming Co. (“OCI Co”), which operate a trona ore mining operation and a soda ash refinery in the Green River Basin, Wyoming. Please read “Note 4. Equity and Other Investments” for more information concerning this acquisition.

The general partner of the Partnership is NRP (GP) LP, a Delaware limited partnership, whose general partner is GP Natural Resource Partners LLC, a Delaware limited liability company.

2.	Significant Accounting Policies Update

Reclassification

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

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. Furthermore, under the equity method of accounting, an investee company’s accounts are not reflected within the Partnership’s Consolidated Balance Sheets and Statements of Comprehensive Income; however, the Partnership’s share of the earnings or losses of the investee company is reflected in the caption ‘‘Equity and other unconsolidated investment income, net’’ in the Consolidated Statements of Comprehensive Income. 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 accounts for its non-marketable equity investments using the cost method of accounting if its ownership interest does not provide the ability to exercise significant influence over the investee or if the investment is not determined to be in- substance common stock. The inability to exert significant influence is generally presumed if the investment is less than 20% of the investee’s voting securities.

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 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. No impairment losses have been recognized as of June 30, 2013.

Recent Accounting Pronouncements

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.	Equity and Other Investments

In the first quarter of 2013, the Partnership acquired non-controlling equity interests in OCI Co and OCI Wyoming comprised of a 48.51% general partner interest in OCI Wyoming and 20% of the common stock and 100% of the preferred stock in OCI Co. OCI Co owns a 1% limited partnership interest in OCI Wyoming and has the right to receive a $14.5 million annual priority distribution before distributions are paid to other interests. The 80% common interest in OCI Co is owned by OCI Chemical Corporation and the 50.49% interest in OCI Wyoming is owned by OCI Wyoming Holding Co., a subsidiary of OCI Chemical Corporation. The preferred stock is subject to certain liquidation preferences in the event of any liquidation, dissolution or winding up of OCI Co at $2,776 per share plus any accrued and unpaid preferred dividends. The liquidation value was $64.4 million at June 30, 2013. These investments were restructured in July 2013, resulting in the Partnership holding a 49% interest in OCI Wyoming. See “Note 14. Subsequent Events” for a description of these transactions.

OCI Wyoming’s operations consist of the mining of trona ore, which, when refined, becomes soda ash. All soda ash is sold through an affiliated sales agent to various domestic and European customers and to American Natural Soda Ash Corporation for export primarily to Asia and Latin America. All mining and refining activities take place in one facility located in the Green River Basin, Wyoming. OCI Co’s only significant asset is its ownership interest in OCI Wyoming.

These investments were acquired from Anadarko Holding Company and its subsidiary, Big Island Trona Company for $292.5 million. The acquisition was funded through a $200 million term loan, the issuance of $76.5 million in equity (including a general partner contribution of $1.5 million), and $16 million in 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 as defined in the purchase and sale agreement in any of the years 2013, 2014 or 2015.

The Partnership has engaged a valuation specialist to assist in allocating the purchase price to the equity interests acquired as well as 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, if any. Included in preliminary fair value adjustments, based on updated estimates, is an increase in the Partnership’s proportionate fair value of property, plant and equipment of $78.7 million. Under the equity method of accounting, this amount is not reflected individually in the accompanying consolidated financial statements but is used to determine periodic charges to amounts reflected as income earned from the equity investments. For the quarter and six months ended June 30, 2013, amortization of purchase adjustments of $0.7 and $1.2 million was recorded by the Partnership. Until the valuations are complete, the remainder of the excess of the purchase price over the estimated fair value of the equity interests acquired has been attributed to the value of the Partnership’s investment in preferred stock of OCI Co and goodwill; neither of which are subject to amortization. The allocation of the purchase price to the acquired equity interests and the underlying assets and liabilities is preliminary and subject to further adjustment, which may be material.

The following summarized combined financial information for OCI Wyoming and OCI Co as of June 30, 2013 and the results of their operations for the three and six-month periods then ended were taken from the OCI-prepared unaudited financial statements.


Operating results:
	Three Months Ended March 31, 2013		Six Months Ended June 30, 2013
	(In thousands) (Unaudited)
Net sales	$	79,822	$	157,882
Gross profit	$	22,372	$	43,315
Net income	$	18,589	$	36,958
Income allocation to NRP’s equity interests	$	8,565	$	16,161


Combined balance sheet:
	June 30, 2013
	(In thousands) (Unaudited)
Current assets	$	151,741
Property, plant and equipment		191,051
Other assets		24

Total assets	$	342,816

Current liabilities	$	34,286
Long term debt		46,000
Other liabilities		3,665
Capital		258,865

Total liabilities and capital	$	342,816

Net book value of NRP’s equity interests	$	139,347
Excess of NRP’s investment over net book value of NRP’s equity interests	$	140,530

4.	Plant and Equipment

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


	June 30, 2013			December 31, 2012
	(In thousands) (Unaudited)
	(In thousands) (Unaudited)
Plant and equipment at cost	$	55,271		$	55,271
Less accumulated depreciation		(26,003	)		(22,870	)

Net book value	$	29,268		$	32,401


	Six months ended June 30,
	2013			2012
	(In thousands) (Unaudited)
	(In thousands) (Unaudited)
Total depreciation expense on plant and equipment	$	3,133		$	3,711

5.	Mineral Rights

The Partnership’s mineral rights consist of the following:


	June 30, 2013			December 31, 2012
	(In thousands) (Unaudited)
	(In thousands) (Unaudited)
Mineral rights	$	1,822,594		$	1,815,423
Less accumulated depletion and amortization		(462,208	)		(434,950	)

Net book value	$	1,360,386		$	1,380,473


	Six months ended June 30,
	2013			2012
	(In thousands) (Unaudited)
	(In thousands) (Unaudited)
Total depletion and amortization expense on mineral rights	$	27,338		$	21,680

6.	Intangible Assets

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


	June 30, 2013			December 31, 2012
	(In thousands) (Unaudited)
	(In thousands) (Unaudited)
Contract intangibles	$	89,421		$	89,421
Less accumulated amortization		(20,357	)		(18,655	)

Net book value	$	69,064		$	70,766


	Six months ended June 30,
	2013			2012
	(In thousands) (Unaudited)
Total amortization expense on intangible assets	$	1,702		$	2,192

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


	Estimated Amortization Expense
	(In thousands)
	(Unaudited)
Remainder of 2013	$	2,117
For year ended December 31, 2014		3,690
For year ended December 31, 2015		3,830
For year ended December 31, 2016		3,830
For year ended December 31, 2017		3,830

7.	Long-Term Debt

Long-term debt consists of the following:


	June 30, 2013			December 31, 2012
	(In thousands)
$300 million floating rate revolving credit facility, due August 2016	$	191,000		$	148,000
$200 million floating rate term loan, due January 2016		200,000			—
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		61,538			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
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

Total debt		1,147,731			984,269
Less – current portion of long term debt		(59,175	)		(87,230	)

Long-term debt	$	1,088,556		$	897,039

The Partnership made principal payments of $79.3 million on its senior notes during the six months ended June 30, 2013. The remaining principal payments are due as set forth below:


	Senior Notes		Credit Facility		Term Loan		Total
	(In thousands)
Remainder of 2013	$	7,692	$	—	$	—	$	7,692
2014		80,983		—		10,000		90,983
2015		80,983		—		20,000		100,983
2016		80,983		191,000		170,000		441,983
2017		80,983		—		—		80,983
Thereafter		425,107		—		—		425,107

	$	756,731	$	191,000	$	200,000	$	1,147,731

Of the $7.7 million in principal payments due on the senior notes for the remainder of 2013, the Partnership refinanced $7.0 million of these payments with long-term debt under its revolving credit facility in July 2013 and paid the remaining amount with cash. At June 30, 2013, the Partnership classified $7.0 million of short-term debt as long-term debt, based on its ability and intent to refinance the obligation on a long-term basis under the revolving credit facility.

The senior note purchase agreement contains covenants requiring our operating subsidiary 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 the Partnership’s leverage ratio exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00.

The weighted average interest rates for the debt outstanding under the Partnership’s revolving credit facility for the six months ended June 30, 2013 and year ended December 31, 2012 were 2.14% and 2.09%, respectively. The Partnership 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 the Partnership may request its lenders to increase their aggregate commitment to a maximum of $500 million on the same terms.

In June 2013, the Partnership entered into an amendment to its revolving credit facility. The amendment amends (i) the restricted payments covenant to permit any restricted payment by the Partnership’s subsidiaries so long as no event of default exists at the time of or would result from such restricted payment, and (ii) the investments covenant to permit any investment in a joint venture so long as, immediately after giving effect to such investment, no default has occurred and is continuing and the Partnership is in pro forma compliance with the financial covenants in the revolving credit facility.

During the first quarter, the Partnership also issued $200 million in term debt. The weighted average interest rate for the debt outstanding under the term loan for the six months ended June 30, 2013 was 2.36%. Repayment terms call for principal payments beginning January 23, 2014 of $10.0 million, $20.0 million on January 23, 2015 with the balance due on January 23, 2016. The debt is unsecured but guaranteed by the operating subsidiaries of the Partnership.

In June 2013, the Partnership entered into an amendment to the $200 million term loan agreement. The amendment amends (i) the restricted payments covenant to permit any restricted payment by the Partnership’s subsidiaries so long as no event of default exists at the time of or would result from such restricted payment, (ii) the investments covenant to permit any investment in a joint venture so long as, immediately after giving effect to such investment, no default has occurred and is continuing and the Partnership is in pro forma compliance with the financial covenants in the term loan agreement, and (iii) the provision regarding application of any prepayments of the term loan so that any such prepayments will be applied in forward order of maturity.

The revolving credit facility and the term loan contain covenants requiring the Partnership 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.

The Partnership was in compliance with all terms under its long-term debt as of June 30, 2013.

8.	Fair Value

The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of the Partnership’s financial instruments included in accounts receivable and accounts payable approximates their fair value due to their short-term nature except for the accounts receivable – affiliates 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
	June 30, 2013		December 31, 2012		June 30, 2013		December 31, 2012
	(In thousands)
	(Unaudited)				(Unaudited)
Assets
Sugar Camp override, current and long-term	$	8,812	$	8,817	$	7,953	$	7,495
Taggart plant sale, current and long-term	$	1,552	$	1,668	$	1,552	$	1,667
Liabilities
Long-term debt, current and long-term	$	782,865	$	876,574	$	756,731	$	836,269

The fair value of the Sugar Camp override, Taggart plant sale 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 and term loan are both variable rate debt, their fair values approximate their carrying amounts.

9.	Related Party Transactions

Reimbursements to Affiliates of our General Partner

The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for expenses incurred on the Partnership’s behalf. All direct general and administrative expenses are charged to the Partnership as incurred. The Partnership also reimburses indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates. The Partnership had an amount payable to Quintana Minerals Corporation of $1.3 million at June 30, 2013 for services provided by Quintana to the Partnership. The Partnership also had an amount payable to Western Pocahontas Properties of $0.2 million for services provided to the Partnership.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands) (Unaudited)
Reimbursement for services	$	2,912	$	2,404	$	5,732	$	4,927

The Partnership also 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.

Cline Affiliates

Various companies controlled by Chris Cline lease coal reserves from the Partnership, and the Partnership provides coal transportation services to them for a fee. At June 30, 2013, Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owned a 31% interest in the Partnership’s general partner, as well as 4,917,548 common units.

Revenues from the Cline affiliates are as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands) (Unaudited)
Coal royalty revenues	$	12,340	$	12,833	$	24,558	$	21,456
Processing fees		271		528		593		1,030
Transportation fees		3,831		5,246		8,758		9,354
Minimums recognized as revenue		—		—		3,477		9,556
Override revenue		742		768		1,778		1,694
Other revenue		—		—		8,149		—

	$	17,184	$	19,375	$	47,313	$	43,090

At June 30, 2013, the Partnership had amounts due from Cline affiliates totaling $63.4 million, of which $57.0 million was attributable to agreements relating to Sugar Camp. The Partnership has received $64.0 million in minimum royalty payments that have not been recouped by Cline affiliates, of which $11.1 million was received in the current year.

During 2013, the Partnership recognized an $8.1 million gain on a reserve swap in Illinois with Williamson Energy. This gain is 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 will be fully mined during 2013, while the tons exchanged are not included in the current mine plans

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 the Partnership’s conflicts policy.

At June 30, 2013, 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 quarter, Taggart was sold to Forge Group, and Quintana no longer retains an interest in Taggart or Forge. The Partnership owned and leased preparation plants to Taggart, which operated the plants. The lease payments are based on the sales price for the coal that is processed through the facilities.

At the end of the three and six month periods ended June 30, 2013, the Partnership leased three facilities to Taggart. Revenues from Taggart were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands) (Unaudited)
Processing fees	$	999	$	2,311	$	1,761	$	3,657

At June 30, 2013, the Partnership had accounts receivable from processing of $1.2 million from Taggart, as well as a $1.6 million note receivable from the sale of a preparation plant during 2012. In connection with the sale to Forge in July, the $1.6 million note was paid in full.

At June 30, 2013, a fund controlled by Quintana Capital owned Kopper-Glo, a small coal mining company that is one of the Partnership’s lessees with operations in Tennessee. Subsequent to the end of the quarter, Kopper-Glo merged with Corsa Coal Corp.

Corbin J. Robertson III, one of the Partnership’s directors, has been named Chairman of the Board of Corsa. Revenues from Kopper-Glo are as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands) (Unaudited)
Coal royalty revenues	$	1,051	$	929	$	2,154	$	1,688

The Partnership also had accounts receivable totaling $0.3 million from Kopper-Glo at June 30, 2013.

OCI Co

At June 30, 2013, the Partnership had accounts receivable from OCI Co of $1.2 million for accrued dividends receivable. This amount is presented as Accounts receivable – affiliates on the Partnership’s Consolidated Balance Sheets.

10.

Commitments and Contingencies

Legal

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

Acquisition

On June 17, 2013, the Partnership entered into a definitive agreement to purchase non-operated working interests in producing oil and gas properties located in the Bakken/Three Forks play located in the Williston Basin of North Dakota and Montana from Abraxas Petroleum Corporation for approximately $35.3 million, subject to purchase price adjustments at closing. Upon entering the agreement, the Partnership paid a deposit of $3.5 million in cash.

Environmental Compliance

The operations conducted on the Partnership’s properties by its lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. As owner of surface interests in some properties, the Partnership may be liable for certain environmental conditions occurring at the surface properties. The terms of substantially all of the Partnership’s leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify the Partnership against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. The Partnership has neither incurred, nor is aware of, any material environmental charges imposed on it related to its properties as of June 30, 2013. The Partnership is not associated with any environmental contamination that may require remediation costs. During the second quarter of 2013, several citizen group lawsuits were filed against landowners alleging ongoing discharges of pollutants, including selenium, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mine on the subject property has been closed, the property has been reclaimed, and the state reclamation bond has been released. A subsidiary of NRP has been named as a defendant in one of these lawsuits. While it is too early to determine the merits or predict the outcome of any of these lawsuits, any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations.

11.

Major Lessees

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


	Three Months Ended June 30,										Six Months Ended June 30,
	2013					2012					2013					2012
	(Dollars in thousands) (Unaudited)
	Revenues		Percent			Revenues		Percent			Revenues		Percent			Revenues		Percent
Alpha Natural Resources	$	15,125		17	%	$	20,240		22	%	$	28,907		16	%	$	44,387		24	%
The Cline Group	$	17,184		20	%	$	19,375		21	%	$	47,313		26	%	$	43,090		24	%

In the first six months of 2013, the Partnership derived over 42% of its total revenue from the two companies listed above. The first half 2013 revenues received from the Cline Group include $8.1 million in revenues recorded in connection with a reserve swap at Cline’s Williamson mine. Excluding the revenues from the reserve swap, revenues from the Cline Group accounted for approximately $39.2 million, or 22% of the Partnership’s total revenues for the first six months of 2013. The Partnership has a significant concentration of revenues with Cline and Alpha, although in most cases, with the exception of the Williamson mine, the exposure is spread out over a number of different mining operations and leases. Cline’s Williamson mine was responsible for approximately 14% of the Partnership’s total revenues for the first six months of 2013, which amount includes the $8.1 million of revenue recorded from the reserve swap. Excluding revenues from the reserve swap, revenues from the Williamson mine accounted for approximately 10% of the Partnership’s total revenues for the first six months of 2013.

12.

Incentive Plans

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

Under the plan a grantee will receive the market value of a common unit in cash upon vesting. Market value is defined as the average closing price over the last 20 trading days prior to the vesting date. The CNG Committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines, including the vesting period. Outstanding grants vest upon a change in control of the Partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, outstanding grants will be automatically forfeited unless and to the extent the CNG Committee provides otherwise.

A summary of activity in the outstanding grants during 2013 is as follows:


Outstanding grants at January 1, 2013	912,314
Grants during the year	334,007
Grants vested and paid during the year	(231,917	)
Forfeitures during the year	(6,720	)

Outstanding grants at June 30, 2013	1,007,684

Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The liability fluctuates with the market value of the Partnership units and because of changes in estimated fair value determined each quarter using the Black-Scholes option valuation model. Risk free interest rates and volatility are reset at each calculation based on current rates corresponding to the remaining vesting term for each outstanding grant and ranged from 0.18% to 1.03% and 30.22% to 34.61%, respectively at June 30, 2013. The Partnership’s average distribution rate of 7.16% and historical forfeiture rate of 4.13% were used in the calculation at June 30, 2013. The Partnership recorded expenses related to its plan to be reimbursed to its general partner of $1.9 million and $0.9 million and $6.9 million and $2.4 million for the three and six months ended June 30, 2013 and 2012, respectively. In connection with the Long-Term Incentive Plan, payments are typically made during the first quarter of the year. Payments of $7.0 million and $6.6 million were made during the six month period ended June 30, 2013 and 2012, respectively.

In connection with the phantom unit awards granted since February 2008, the CNG Committee also granted tandem Distribution Equivalent Rights, or DERs, which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting.

The unaccrued cost, associated with the unvested outstanding grants and related DERs at June 30, 2013 was $13.3 million.

13.

Distributions

On May 14, 2013, the Partnership paid a quarterly distribution $0.55 per unit to all holders of common units on May 6, 2013.

14.

Subsequent Events

The following represents material events that have occurred subsequent to June 30, 2013 through the time of the Partnership’s filing of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission:

Distributions

On July 23, 2013, the Partnership declared a distribution of $0.55 per unit to be paid on August 14, 2013 to unitholders of record on August 5, 2013.

Dividends and Distributions Received From Unconsolidated Equity and Other Investments

Subsequent to the end of the second quarter, the Partnership received $46.0 million in cash distributions from its investments in OCI Wyoming. This includes a one-time special distribution of $44.8 million. The Partnership used a portion of the proceeds from the July 2013 distribution from OCI Wyoming to prepay the $10 million principal payment that is due in January 2014 on the term loan. Following this principal repayment, the next principal repayment obligation on the term loan is not until January 2015. The Partnership intends to use the remaining portion of the OCI Wyoming special distribution to fund the purchase price of the Bakken/Three Forks non-operated working interests acquisition, which is expected to close in August 2013. In July 2013, the interests in OCI Wyoming were restructured to eliminate the Partnership’s interest in OCI Co and increase its interest in OCI Wyoming to 49.0%.

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of the financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included elsewhere in this filing and the financial statements and footnotes included in the Natural Resource Partners L.P. Annual Report on Form 10-K for the year ended December 31, 2012, as filed on February 28, 2013.

Executive Overview

Our Business

We engage principally in the business of owning, managing and leasing mineral properties in the United States. We own coal reserves in the three major U.S. coal-producing regions: Appalachia, the Illinois Basin and the Western United States, as well as lignite reserves in the Gulf Coast region. As of December 31, 2012, we owned or controlled approximately 2.4 billion tons of proven and probable coal reserves. We do not operate any mines, but lease our reserves to experienced mine operators under long-term leases that grant the operators the right to mine and sell our reserves in exchange for royalty payments. We also own and manage infrastructure assets that generate additional revenues for NRP, particularly in the Illinois Basin.

In recent years, we have made a concerted effort to diversify our business. In connection with this effort, we have acquired approximately 500 million tons of aggregate reserves located in a number of states across the country. In our coal and aggregate royalty business, our lessees generally make payments to us based on the greater of a percentage of the gross sales price or a fixed royalty per ton of coal or aggregates they sell, subject to minimum monthly, quarterly or annual payments. These minimum royalties are generally recoupable over a specified period of time, which varies by lease, if sufficient royalties are generated from production in those future periods. We do not recognize these minimum royalties as revenue until the applicable recoupment period has expired or they are recouped through production. Until recognized as revenue, these minimum royalties are recorded as deferred revenue, a liability on our balance sheet.

We have also acquired various interests in oil and gas properties that are located principally in the Appalachian Basin, Louisiana and Oklahoma. Oil and gas royalty revenues include production payments as well as bonus payments. Oil and gas royalty revenues are recognized on the basis of hydrocarbons sold by lessees and the corresponding revenue from those sales. Generally, the lessees make payments based on a percentage of the selling price. Some leases are subject to minimum annual payments or delay rentals.

In 2013, we have made significant strides in our diversification effort through two acquisitions:

•

In January, we purchased non-controlling equity interests in OCI Wyoming, an operator of a trona ore mining operation and a soda ash refinery in the Green River Basin, Wyoming. Through June 30, 2013 we received $26.9 million from our investment in OCI Wyoming, and we received an additional $46.0 million in July 2013. OCI Wyoming’s operations consist of the mining of trona ore, which, when refined, becomes soda ash. All soda ash is sold through an OCI-affiliated sales agent to various domestic and European customers and to American Natural Soda Ash Corporation for export. All mining and refining activities take place in one facility located in the Green River Basin, Wyoming.

•

In June, we entered into a definitive agreement to acquire non-operated working interests in producing oil and gas properties located in the Bakken/Three Forks play in the Williston Basin of North Dakota and Montana for $35.3 million, subject to purchase price adjustments at closing.

For the six months ended June 30, 2013, we recognized $68.5 million of revenues from sources other than coal royalties, which primarily consisted of equity income from our investment in OCI Wyoming, oil and gas royalties, aggregates royalties, overriding royalties (which include coal and aggregates overrides), minimums recognized as revenue, and processing and transportation fees. The revenues that we recognize from minimums and processing/transportation are largely derived from coal-related businesses.

Our Current Liquidity Position

Our revolving credit facility does not mature until August 2016 and, as of June 30, 2013, we had $109 million in available capacity under the facility. In addition to the amounts available under our revolving credit facility, we had approximately $105 million in cash at June 30, 2013. We believe that the combination of our capacity under the revolving credit facility and our cash on hand gives us enough liquidity to meet our current financial needs. We typically access the capital markets to refinance amounts outstanding under the revolving credit facility as we approach the limits under that facility, the timing of which depends on the pace and size of our acquisition program.

We refinanced $42.9 million in principal payments on our senior notes during the second quarter of 2013 using borrowings under our revolving credit facility. We also borrowed $7.0 million under our revolving credit facility in July 2013 to partially refinance an additional $7.7 million principal payment on our senior notes. We intend to continue to refinance some or all of the additional senior notes principal payments that are due over the next twelve months or until the coal markets improve.

We used a portion of the proceeds from the July 2013 distribution from OCI Wyoming to prepay the $10 million principal payment that was due in January 2014 on our term loan. Following this principal repayment, our next principal repayment obligation on the term loan is not until January 2015. We intend to use the remaining portion of the OCI Wyoming special distribution to fund the purchase price of the Bakken/Three Forks non-operated working interests acquisition, which is expected to close in August 2013.

Current Results/Market Outlook

Our total revenues for the first six months of 2013 were $181.1 million, which was essentially flat compared to the $182.5 million in total revenues received for the first six months of 2012. We continue to have substantial exposure to metallurgical coal, from which we derived approximately 39% of our coal royalty revenues and 28% of the related production in the first six months of 2013. Global demand for steel has continued to decline during 2013, resulting in the benchmark price for metallurgical coal being lowered to $145 per metric ton, and in metallurgical coal being sold at prices that are below the benchmark price. Primarily as a result of lower metallurgical prices and demand, but also due to the continued weakness in the steam coal market, our coal royalty revenues from Central Appalachia declined materially in the first six months of 2013 as compared to the same period in 2012. However, we benefitted during the six-month period from the diversity of our assets, receiving higher coal royalty revenues from all other regions as compared to the same period in 2012, and an additional $14.9 million in revenues attributable to our interest in OCI Wyoming.

The market for steam coal has remained soft as expected in the first six months of 2013. Federal government regulations combined with low natural gas prices have led to reduced production and consumption of steam coal, particularly the high cost steam coal mined in Central Appalachia. The Illinois Basin, however, continues to grow production and is displacing Central Appalachian coal at some utilities. We are benefitting from the Illinois Basin growth through our relationship with Foresight Energy and the Cline Group. We expect the markets for both steam and metallurgical coal to remain soft for the remainder of 2013.

Subsequent to our investment in OCI Wyoming and OCI Co, OCI entered into a series of restructuring and refinancing transactions in advance of the OCI Resources LP initial public offering of common units. In connection with such restructuring and refinancing transactions, we received a special distribution of $44.8 million from OCI Wyoming. As a result of the restructuring and refinancing, OCI Wyoming will be able to borrow under its new revolving credit facility to fund capital and operating expenses and is expected to be able to make regular cash distributions to its partners each quarter. OCI Wyoming’s business has performed as projected over the first six months of 2013, but the increased liquidity associated with the restructuring and refinancing has resulted in higher than expected cash distributions to NRP in 2013 in addition to the $44.8 special distribution. If OCI Resources is able to successfully complete its planned initial public offering during 2013, NRP expects to have greater visibility over future distributions out of OCI Wyoming.

Growth Through Acquisitions

In 2012, we spent approximately $240 million to acquire additional assets that will help secure the future growth of the partnership. Included in these acquisitions were additional steam coal reserves and transportation infrastructure in Illinois, oil and gas mineral rights in Oklahoma, an overriding royalty on oil and gas reserves in the liquids-rich portion of the Marcellus Shale play, and an overriding royalty on frac sand reserves in Wisconsin. These efforts are reflective of our management’s desire to continue to grow and diversify the assets of the partnership and attempt to ensure the stability of future revenues and distributions to our unitholders.

In the first half of 2013, we continued to diversify our holdings through the acquisition of the interests in OCI Wyoming for $292.5 million and the execution of a definitive agreement to purchase non-operated working interests in producing oil and gas properties in the Bakken/Three Forks play in the Williston Basin of North Dakota and Montana from Abraxas Petroleum Corporation for approximately $35.3 million, subject to purchase price adjustments. We expect the Abraxas acquisition to close in August 2013.

Political, Legal and Regulatory Environment

The political, legal and regulatory environment continues to be difficult for the coal industry. The Environmental Protection Agency (“EPA”) has used its authority to create significant delays in the issuance of new permits and the modification of existing permits, which has led to substantial delays and increased costs for coal operators. Furthermore, the federal courts have recently handed down several decisions that are adverse to the coal industry and, in a June 2013 speech, President Obama outlined his climate change policies, which include an initiative to limit carbon emissions by existing coal-fired utilities. Under the Obama administration, the EPA has continued to promulgate regulations that will negatively affect the viability of coal-fired generation, which will ultimately reduce coal consumption and the production of coal from our properties.

In addition to government action, private citizens’ groups have continued to be active in bringing lawsuits against operators, as well as challenging permits issued by the Army Corps of Engineers. During the second quarter of 2013, several citizen group lawsuits were filed against landowners alleging ongoing discharges of pollutants, including selenium, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mine on the subject property has been closed, the property has been reclaimed, and the state reclamation bond has been released. A subsidiary of NRP has been named as a defendant in one of these lawsuits. While it is too early to determine the merits or predict the outcome of any of these lawsuits, any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations.

Distributable Cash Flow

Under our partnership agreement, we are required to distribute all of our available cash each quarter. Because distributable cash flow is a significant liquidity metric that is an indicator of our ability to generate cash flows at a level that can sustain or support an increase in quarterly cash distributions paid to our partners, we view it as the most important measure of our success as a company. Distributable cash flow is also the quantitative standard used in the investment community with respect to publicly traded partnerships.

Our distributable cash flow represents cash flow from operations, distributions from unconsolidated investments, proceeds from sale of assets and return on direct financing lease and contractual override. Although distributable cash flow is a “non-GAAP financial measure,” we believe it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. Distributable cash flow may not be calculated the same for us as for other companies. A reconciliation of distributable cash flow to net cash provided by operating activities is set forth below.

We have historically reduced our distributable cash flow by the amount of cash we have reserved for principal payments due on our senior notes in the next calendar year. However, to present our distributable cash flow more in line with MLP practice and because we intend to refinance some or all of the principal payments that are due in 2013 and 2014, beginning with our 2013 presentation, we no longer reduce distributable cash flow by reserves for future principal payments. We have changed our three and six months ended June 30, 2012 calculations in the table below to be comparable with our presentation for 2013.

Reconciliation of GAAP “Net cash provided by operating activities”

to Non-GAAP “Distributable cash flow”


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands) (Unaudited)
Net cash provided by operating activities	$	79,736	$	82,522	$	123,649	$	132,007
Distributions from unconsolidated investments		10,777		—		10,777		—
Return on direct financing lease and contractual override		137		904		555		904
Proceeds from sale of assets		—		285		154		285

Distributable cash flow	$	90,650	$	83,711	$	135,135	$	133,196

Recent Acquisitions

We are a growth-oriented company and have closed a number of acquisitions over the last several years. Our most recent acquisitions are briefly described below.

Abraxas. In June 2013, we signed a definitive agreement to purchase non-operated working interests in producing oil and gas properties in the Bakken/Three Forks play in the Williston Basin of North Dakota and Montana from Abraxas Petroleum Corporation for $35.3 million, subject to purchase price adjustments. The acquisition is expected to close in August 2013.

OCI Wyoming. In January 2013, we acquired non-controlling equity interests in OCI Co and OCI Wyoming. The interests were initially comprised of a 48.51% general partner interest in OCI Wyoming and 20% of the common stock and 100% of the preferred stock in OCI Co. In July 2013, the interests in OCI Co and OCI Wyoming were restructured to eliminate our interest in OCI Co and increase our interest in OCI Wyoming to 49.0%. Following the restructuring transactions, we own a 49% interest in OCI Wyoming. The 51% interest in OCI Wyoming is held by OCI Resources LP and OCI Wyoming Holding Co., which are affiliates of OCI Chemical Corporation.

The interests in OCI Co and OCI Wyoming were acquired from Anadarko Holding Company and its subsidiary, Big Island Trona Company for $292.5 million. The acquisition was funded through a $200 million term loan, the issuance of $76.5 million in equity including a general partner capital contribution of $1.5 million, and $16 million in cash. The acquisition agreement provides for up to $50 million in additional contingent consideration payable by us should certain performance criteria be met as defined in the purchase and sales agreement in any of 2013, 2014 or 2015.

Marcellus Override. In December 2012, we 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.

Hi-Crush Override. In October 2012, we acquired an overriding royalty interest in frac sand reserves located on approximately 561 acres near Wyeville, Wisconsin for approximately $15.0 million.

Colt. Between September 2009 and September 2012, we acquired approximately 200 million tons of coal reserves related to the Deer Run Mine in Illinois from Colt, LLC, an affiliate of the Cline Group, for a total purchase price of $255 million.

Oklahoma Oil and Gas. From December 2011 through June 2012, we acquired approximately 19,200 net mineral acres located in the Mississippian Lime oil play in Northern Oklahoma for $63.9 million.

Sugar Camp. In March 2012, we acquired the rail loadout associated infrastructure assets for $50.0 million and a contractual overriding royalty for $8.9 million interest on certain tonnage at the Sugar Camp mine in Illinois. The rail loadout and infrastructure assets were purchased from Sugar Camp Energy, LLC and the contractual overriding royalty interest was purchased from Ruger, LLC, both affiliates of the Cline Group.

Litz-Moore. In March 2012, we acquired metallurgical coal reserves adjacent to current NRP holdings in Virginia for $2.8 million.

Results of Operations

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012


	Three Months Ended June 30,					Increase (Decrease)			Percentage Change
	2013		2012			Increase (Decrease)			Percentage Change
	(In thousands, except percent and per ton data) (Unaudited)
Coal:
Royalty revenues
Appalachia
Northern	$	4,242	$	4,689		$	(447	)		(10	)%
Central		30,185		38,403			(8,218	)		(21	)%
Southern		7,352		6,718			634			9	%

Total Appalachia		41,779		49,810			(8,031	)		(16	)%
Illinois Basin		12,843		12,912			(69	)		(1	)%
Northern Powder River Basin		2,295		310			1,985			640	%
Gulf Coast		1,293		(154	)		1,447			—

Total	$	58,210	$	62,878		$	(4,668	)		(7	)%

Production (tons)
Appalachia
Northern		3,531		1,651			1,880			114	%
Central		5,826		6,507			(681	)		(10	)%
Southern		1,163		835			328			39	%

Total Appalachia		10,520		8,993			1,527			17	%
Illinois Basin		3,012		2,910			102			4	%
Northern Powder River Basin		969		126			843			669	%
Gulf Coast		393		(47	)		440			—

Total		14,894		11,982			2,912			24	%

Average gross royalty per ton
Appalachia
Northern	$	1.20	$	2.84		$	(1.64	)		(58	)%
Central		5.18		5.90			(0.72	)		(12	)%
Southern		6.32		8.05			(1.73	)		(21	)%
Total Appalachia		3.97		5.54			(1.57	)		(28	)%
Illinois Basin		4.26		4.44			(0.18	)		(4	)%
Northern Powder River Basin		2.37		2.46			(0.09	)		(4	)%
Gulf Coast		3.29		3.28			0.01			—
Combined average gross royalty per ton	$	3.91	$	5.25		$	(1.34	)		(26	)%
Aggregates:
Royalty revenues	$	1,751	$	1,702		$	49			3	%
Production		1,463		1,447			16			1	%
Average base royalty per ton	$	1.20	$	1.18		$	0.02			2	%
Oil and Gas:
Oil and gas revenues	$	4,093	$	4,078		$	15			—

Coal Royalty Revenues and Production. Coal royalty revenues comprised approximately 67% and 69% of our total revenue for the three month periods ended June 30, 2013 and 2012, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:

Appalachia. Coal royalty revenues decreased $8.0 million or 16% in the three-month period ended June 30, 2013 compared to the same period of 2012, while production increased 1.5 million tons or 17%.

As a result of the difficult coal markets, production from our properties in the Central Appalachian region has declined by 10% as some lessees chose to idle mines or mining units during 2012 and in the first half of 2013. In addition, pricing realized by the lessees for both steam and metallurgical coal in Central Appalachia is generally below the levels of the same quarter in 2012, causing a higher percentage decrease in coal royalty revenues compared to the decrease in production.

In contrast to Central Appalachia, the Southern Appalachian region had increased production and coal royalty revenue, primarily due to increased sales of metallurgical coal from the Oak Grove mine, although these sales were at a lower royalty rate per ton. This increase was slightly offset by lower tonnage and revenue from our BLC property.

With respect to Northern Appalachia, during the quarter ending June 30, 2013, there was a significant increase in production, but a slight decrease in revenue versus the same period in 2012. The increase in tonnage primarily resulted from a longwall mine moving onto our property during the quarter. However, the longwall mine moving onto our property generates lower royalty per ton than a separate longwall mine that had lower sales during the quarter, which contributed to the decline in revenue. In addition, we continue to have production from a 1960s era coal lease where the royalty rate per ton is very low.

Illinois Basin. Production and coal royalty revenue for the three months ended June 30, 2013 were about the same when compared to the same period in 2012. Increased production from the start of the longwall mining unit and the resulting increased sales from our Hillsboro property were offset by lower sales from the Williamson and Macoupin properties. In addition, a lessee moved back onto our property during 2013 which had primarily been mining on adjacent property in 2012.

Northern Powder River Basin. Coal royalty revenues and production increased on our Western Energy property due to the normal variations that occur due to the checkerboard nature of ownership. The lessee did realize lower sales prices, which reduced the royalty per ton for the quarter.

Aggregate Royalty Revenues and Production. Aggregate revenue and production was about the same for the quarter ended June 30, 2013, compared to the same quarter for 2012.

Oil and Gas Royalty Revenues. Oil and gas royalty revenues were flat for the current quarter when compared to the same quarter in 2012. A significant increase in royalties received from our Oklahoma assets was offset by a decrease in revenue from our BRP oil and gas properties in Louisiana. We do not anticipate the Marcellus assets to contribute materially to our revenues until 2014, but do expect to receive revenues from our Bakken/Three Forks properties in the second half of 2013.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012


	Six Months Ended June 30,				Increase (Decrease)			Percentage Change
	2013		2012		Increase (Decrease)			Percentage Change
	(In thousands, except percent and per ton data) (Unaudited)
Coal:
Royalty revenues
Appalachia
Northern	$	9,126	$	7,697	$	1,429			19	%
Central		56,591		80,475		(23,884	)		(30	)%
Southern		15,052		11,021		4,031			37	%

Total Appalachia		80,769		99,193		(18,424	)		(19	)%
Illinois Basin		25,500		21,681		3,819			18	%
Northern Powder River Basin		4,424		1,772		2,652			150	%
Gulf Coast		1,959		148		1,811			—

Total	$	112,652	$	122,794	$	(10,142	)		(8	)%

Production (tons)
Appalachia
Northern		7,272		4,052		3,220			79	%
Central		10,946		13,041		(2,095	)		(16	)%
Southern		2,267		1,388		879			63	%

Total Appalachia		20,485		18,481		2,004			11	%
Illinois Basin		5,906		5,001		905			18	%
Northern Powder River Basin		1,764		595		1,169			196	%
Gulf Coast		572		20		552			—

Total		28,727		24,097		4,630			19	%

Average gross royalty per ton
Appalachia
Northern	$	1.25	$	1.90	$	(0.65	)		(34	)%
Central		5.17		6.17		(1.00	)		(16	)%
Southern		6.64		7.94		(1.30	)		(16	%)
Total Appalachia		3.94		5.37		(1.43	)		(27	)%
Illinois Basin		4.32		4.34		(0.02	)		—
Northern Powder River Basin		2.51		2.98		(0.47	)		(16	)%
Gulf Coast		3.42		7.40		(3.98	)		(54	)%
Combined average gross royalty per ton	$	3.92	$	5.10	$	(1.18	)		(23	)%
Aggregates:
Royalty revenues	$	3,303	$	3,418	$	(115	)		(3	)%
Production		2,746		2,814		(68	)		(2	)%
Average base royalty per ton	$	1.20	$	1.21	$	(0.01	)		(1	)%
Oil and Gas:
Oil and gas revenues	$	5,856	$	5,466	$	390			7	%

Coal Royalty Revenues and Production. Coal royalty revenues comprised approximately 62% and 67% of our total revenue for the six month periods ended June 30, 2013 and 2012, respectively. The following is a discussion of the coal royalty revenues and production derived from our major coal producing regions:

Appalachia. Coal royalty revenues decreased $18.4 million, or 19%, in the six month period ended June 30, 2013 compared to the same period of 2012, while production increased 2.0 million, or 11%.

As a result of the difficult coal markets, production in the Central Appalachian region declined 16% and coal royalty revenues declined by 30% as some lessees continue to idle mines or mining units. The reduced production by some lessees was partially offset by some mines moving back onto our property during the first six months of 2013. In addition, pricing realized by the lessees for both steam and metallurgical coal was below the levels of the same quarter in 2012, causing a higher percentage decrease in coal royalty revenue compared to the decrease in production.

In contrast to Central Appalachia, the Southern Appalachian region had increased production and coal royalty revenue, primarily due to the Oak Grove preparation plant operating for the entire six month period after being idled for much of the first half of 2012 due to damage caused by a tornado in 2011, as well as the lessee having increased sales. In addition, despite a negative variance in the second quarter, our BLC property had an overall increase in tonnage and revenue over the six month period due to one lessee improving its production and other lessees having higher production.

With respect to Northern Appalachia, during the six months ending June 30, 2013, there was an increase in production and revenue versus the same period in 2012. The primary reason for the increase in tonnage and revenue is that a longwall mine operated on our property for most of the first six months of 2013 versus only a part of 2012. This increase was partially offset by other lessees reducing production or having lower revenue per ton. We continue to have production on a 1960s era coal lease where the royalty rate per ton is very low.

Illinois Basin. Production and coal royalty revenue for the six months ended June 30, 2013 increased compared to the same period in 2012. The production increase was primarily due to increased production from the start of the longwall mining unit and the resulting increased sales from our Hillsboro property. In addition, a lessee moved back onto our property during 2013 which had primarily been mining on adjacent property in 2012. These increases were partially offset by lower sales from the Williamson and Macoupin properties.

Aggregate Royalty Revenues and Production. Aggregate revenue and production was nearly the same in 2013 as it was in 2012.

Oil and Gas Royalty Revenues. Oil and gas royalty revenues were up 7% for the six months ended June 30, 2013 when compared to the same period in 2012. The increase reflects royalties received from our Oklahoma assets, offset by decreased revenue from our BRP oil and gas properties in Louisiana. We do not anticipate the Marcellus assets to contribute materially to our revenues until 2014, but do expect to receive revenues from our Bakken/Three Forks properties in 2013.

Other Operating Results

In addition to coal, aggregates and oil and gas royalty revenues, we generated approximately 33% and 28% of our revenues from other sources for the first six months of 2013 and 2012, respectively. Other sources of revenue primarily include: equity income from our investment in OCI Wyoming (with respect to the first half of 2013); overriding royalties (which include coal and aggregates overrides); minimums recognized as revenue; and processing and transportation fees. In the first six months of 2013, we recognized $14.9 million in revenue from our equity investment in OCI Wyoming, $8.1 million in overriding royalty revenue and we realized $5.4 million in minimums recognized as revenue. In addition, in the first half of 2013, we recognized a non-cash gain of $8.1 million resulting from a coal reserve swap on one of our Illinois properties. The revenues that we recognize from minimums and processing/transportation are largely derived from coal-related businesses.

Processing and Transportation Revenues. Processing revenues decreased $1.8 million and $2.8 million for the three and six months ended June 30, 2013 when compared to the same periods in 2012. The decrease in processing fees was a result of the sale of one of our facilities in the third quarter of 2012, as well as lower Central Appalachian production from the properties that use these facilities to wash their coal.

In addition to our preparation plants, we own handling and transportation infrastructure. In contrast to our typical royalty structure, we receive a fixed rate per ton for coal transported over these facilities. At the Williamson property in Illinois, we operate handling and transportation infrastructure and have subcontracted out that responsibility to third parties. At the Macoupin and Sugar Camp properties, we own the infrastructure and lease it to Cline affiliates. Transportation fees decreased $1.4 million and $0.6 million for the quarter and six months ended June 30, 2013 compared to the same periods for 2012. The decrease is attributed to Foresight generating higher production and sales from the Hillsboro property in Illinois rather than from the mines on which we collect a transportation fee. Production decreased on the Williamson and Macoupin properties during the six months ended June 30, 2013 when compared to the same periods for 2012.

Operating costs and expenses. Included in total expenses are:

•

Depreciation, depletion and amortization expenses increased $2.2 million and $4.6 million for the three and six months ended June 30, 2013 when compared to the same periods for 2012. The increase in expense reflects higher oil and gas depletion of approximately $1.0 million per quarter, higher coal depletion due to increases in production during the first six months of 2013 as well as depletion related to the reserve swap when compared to the same period for 2012.

•

General and administrative expenses increased $1.8 million and $4.5 million for the three and six months ended June 30, 2013 compared to the same periods for 2012. The change in general and administrative expense is due to increased compensation and long term incentive expense related to the addition of new employees.

Interest Expense. Interest expense increased approximately $0.9 million and $1.9 million for the three and six months ended June 30, 2013 over the same periods in 2012. The increase reflects the issuance of a new term loan in January 2013 to fund the OCI acquisition.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

We satisfy our working capital requirements with cash generated from operations. We finance our property acquisitions with available cash, borrowings under our revolving credit facility, term loan and the issuance of senior notes and additional common units. While our ability to satisfy our debt service obligations and pay distributions to our unitholders depends in large part on our future operating performance, our ability to make acquisitions will depend on prevailing economic conditions in the financial markets as well as the coal, oil and gas and aggregate/industrial minerals industries and other factors, some of which are beyond our control. For a more complete discussion of factors that will affect cash flow we generate from operations, please read “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012. Our capital expenditures, other than for acquisitions, have historically been minimal.

Our credit ratios are within our debt covenants for our credit facility, our term loan and our outstanding senior notes. For a more complete discussion of factors that will affect our liquidity, please read “Item 1A. Risk Factors” in our Form 10-K for the year ended December 31, 2012. Our revolving credit facility does not mature until August 2016 and, as of June 30, 2013, we had $109 million in available capacity under the facility. In addition to the amounts available under our revolving credit facility, we had approximately $105 million in cash at June 30, 2013. We believe that the combination of our capacity under the revolving credit facility and our cash on hand gives us enough liquidity to meet our current financial needs. We typically access the capital markets to refinance amounts outstanding under the revolving credit facility as we approach the limits under that facility, the timing of which depends on the pace and size of our acquisition program.

Net cash provided by operations for the six months ended June 30, 2013 and 2012 was $123.6 million and $132.0 million, respectively. The majority of our cash provided by operations is generated from coal royalty revenues and our equity interest in OCI Wyoming.

Net cash used in investing activities for the six months ended June 30, 2013 and 2012 was $281.5 million and $152.8 million, respectively. Substantially all of our 2013 investing activities consisted of acquiring investments in OCI Wyoming, please read “Note 4. Equity and Other Investments.” During 2012, the majority of our investing activities consisted of acquiring reserves, plant and equipment and related intangibles as well as assets relating to Sugar Camp.

Net cash flows provided by financing activities for the six months ended June 30, 2013 was $113.6 million. During the first six months of 2013, we had net proceeds from loans of $241.4 million, net proceeds from equity transactions of $74.9 million, and a capital contribution from our general partner of $1.5 million. These proceeds were offset by loan repayments of $79.5 million and distributions to partners of $124.7 million. During the same period for 2012, net cash used in financing activities was $72.2 million, which included proceeds from loans of $73.0 million offset by debt repayments of $23.1 million and $121.6 million for distributions to partners.

Contractual Obligations and Commercial Commitments

Credit Facility. As of the date of this report we had $102 million available to us under the facility. Under an accordion feature in the credit facility, we may request our lenders to increase their aggregate commitment to a maximum of $500 million on the same terms. However, we cannot be certain that our lenders will elect to participate in the accordion feature. To the extent the lenders decline to participate, we may elect to bring new lenders into the facility, but cannot make any assurance that the additional credit capacity will be available to us on existing or comparable terms.

During 2013, our borrowings and repayments under our credit facility were as follows:


	Quarter Ending
	March 31		June 30
	(In thousands) (Unaudited)
Outstanding balance, beginning of period	$	148,000	$	148,000
Borrowings under credit facility		—		43,000
Less: Repayments under credit facility		—		—

Outstanding balance, ending period	$	148,000	$	191,000

Subsequent to the end of the second quarter, we borrowed an additional $7 million to partially refinance a principal payment due on our senior notes. Our obligations under the credit facility are unsecured but are guaranteed by our operating subsidiaries. We may prepay all loans at any time without penalty. Indebtedness under the revolving credit facility bears interest, at our option, at either:

•

the Alternate Base Rate (as defined in the credit agreement) plus an applicable margin ranging from 0% to 1%; or

•

the Adjusted LIBO Rate (as defined in the credit agreement) plus an applicable margin ranging from 1.00% to 2.25%.

We incur a commitment fee on the unused portion of the revolving credit facility at a rate ranging from 0.18% to 0.40% per annum.

The credit agreement contains covenants requiring us to maintain:

•

a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) 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) not less than 3.5 to 1.0.

Term Loan. In connection with the OCI Wyoming acquisition, we entered into a 3-year, $200 million term loan facility in January 2013. The term loan facility is guaranteed by our operating subsidiaries and bears interest at a weighted average rate of 2.36%. Interest on the term loan became payable initially in April 2013, with a principal payment of $20.0 million on January 23, 2015 and the balance of $170.0 million on January 23, 2016. The term loan facility contains financial covenants and other terms that are identical to those of our credit facility. In July 2013, we made a $10 million payment on this loan with proceeds received from distributions from OCI Wyoming, reducing the balance on the loan to $190 million.

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

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

•

Maintain a ratio of consolidated indebtedness to consolidated 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.

Long-Term Debt

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

•

$198.0 million of our $300 million floating rate revolving credit facility, due August 2016;

•

$190.0 million floating rate term loan, due January 2016;

•

$23.1 million of 4.91% senior notes due 2018;

•

$128.6 million of 8.38% senior notes due 2019;

•

$53.8 million of 5.05% senior notes due 2020;

•

$1.5 million of 5.31% utility local improvement obligation due 2021;

•

$27.0 million of 5.55% senior notes due 2023;

•

$75.0 million of 4.73% senior notes due 2023;

•

$165.0 million of 5.82% senior notes due 2024;

•

$50.0 million of 8.92% senior notes due 2024;

•

$175.0 million of 5.03% senior notes due 2026; and

•

$50.0 million of 5.18% senior notes due 2026.

All of our senior notes require annual principal payments in addition to semi-annual interest payments. The scheduled principal payments on the 8.92% senior notes due in 2024 do not begin until March 2014, and the scheduled principal payments on the 4.73%, 5.03% and 5.18% senior notes do not begin until December 2014. We also make annual principal and interest payments on the utility local improvement obligation.

Shelf Registration Statements

In addition to our credit facility, on April 24, 2012 we filed an automatically effective shelf registration statement on Form S-3 with the SEC that is available for registered offerings of common units and debt securities. This shelf replaced our previous shelf registration statement, which expired at the end of February 2012. On August 15, 2012, we filed a shelf registration statement that registered the resale of all of the units held by Adena Minerals, as well as up to $500 million in equity or debt securities by NRP. Following the effectiveness of this registration statement, Adena distributed 6,049,155 common units to its shareholders, and we subsequently filed a prospectus supplement to register the resale of these units by those shareholders. On April 12, 2013, we filed a resale shelf registration statement to register the 3,784,572 common units issued in the January 2013 private placement. This shelf registration statement was declared effective by the SEC on May 7. 2013. A portion of the common units issued in the private placement were issued, directly and indirectly, to certain of our affiliates, including Corbin J. Robertson, Jr. and Christopher Cline. We cannot control the resale of the common units by any of the selling unitholders under the shelf registration statements, and the amounts, prices and timing of the issuance and sale of any equity or debt securities by NRP will depend on market conditions, our capital requirements and compliance with our credit facility, term loan and senior notes.

Off-Balance Sheet Transactions

We do not have any off-balance sheet arrangements with unconsolidated entities or related parties and accordingly, there are no off-balance sheet risks to our liquidity and capital resources from unconsolidated entities.

Related Party Transactions

Reimbursements to our General Partner

Our general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with our partnership agreement, we reimburse our general partner and its affiliates for expenses incurred on our behalf. All direct general and administrative expenses are charged to us as incurred. We also reimburse indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates. We had an amount payable to Quintana Minerals Corporation of $1.3 million at June 30, 2013 for services provided by Quintana to NRP and an amount payable to Western Pocahontas of $0.2 million for services they provided to NRP. Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders.

The reimbursements to our general partner for services performed by Western Pocahontas Properties and Quintana Minerals Corporation are as follows:


	Three Months Ended March 31,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands) (Unaudited)
Reimbursement for services	$	2,912	$	2,404	$	5,732	$	4,927

For additional information, please read “Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement” in our Annual Report on Form 10-K for the year ended December 31, 2012.

We also lease an office building in Huntington, West Virginia from Western Pocahontas at market rates. The terms of the lease were approved by our Conflicts Committee. We pay $0.6 million each year in lease payments.

Cline Affiliates

Various companies controlled by Chris Cline lease coal reserves from NRP, and we provide coal transportation services to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest in NRP’s general partner, as well as 4,917,548 common units. Revenues from Cline affiliates are as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands) (Unaudited)
Coal royalty revenues	$	12,340	$	12,833	$	24,558	$	21,456
Processing fees		271		528		593		1,030
Transportation fees		3,831		5,246		8,758		9,354
Minimums recognized as revenue		—		—		3,477		9,556
Override revenue		742		768		1,778		1,694
Other revenue		—		—		8,149		—

	$	17,184	$	19,375	$	47,313	$	43,090

At June 30, 2013, we had amounts due from Cline affiliates totaling $63.4 million, of which $57.0 million was attributable to agreements relating to Sugar Camp. As of June 30, 2013, we had received $64.0 million in minimum royalty payments to date that have not been recouped by Cline affiliates, of which $11.1 million was received in the current year.

During 2013, we recognized an $8.1 million non-cash gain on a coal reserve swap in Illinois with Williamson Energy. This gain is reflected in the table above in the “Other revenue” line. The tons received will be fully mined during 2013, while the tons exchanged are not included in the current mine plans. During the first quarter of 2012, we reported $9.6 million in minimums recognized as revenue attributable to an agreement in 2012 by Gatling Ohio, LLC to relinquish its recoupment rights.

Quintana Capital Group GP, Ltd.

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

As of June 30, 2013, 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 quarter, Taggart was sold to Forge Group, and Quintana no longer retains an interest in Taggart or Forge. We own and lease preparation plants to Forge, which operates the plants. The lease payments are based on the sales price for the coal that is processed through the facilities.

For the three and six months ended June 30, 2013, we leased three facilities to Taggart. Revenues from Taggart were as follows:


	Three Months Ended March 31,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands) (Unaudited)
Processing revenues	$	999	$	2,311	$	1,761	$	3,657

At June 30, 2013, we had accounts receivable from processing totaling $1.2 million from Taggart, as well as a $1.6 million note receivable from the sale of a preparation plant during 2012. However, in connection with the Forge acquisition, Forge paid off the $1.6 million note and has begun to reduce the accounts receivable balance.

At June 30, 2013, a fund controlled by Quintana Capital owned Kopper-Glo, a small coal mining company that is one of our lessees with operations in Tennessee. Subsequent to the end of the quarter, Kopper-Glo merged with Corsa Coal Corp. Corbin J. Robertson III, one of our directors, has been named Chairman of the Board of Corsa. Revenues from Kopper-Glo are as follows:


	Three Months Ended March 31,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands) (Unaudited)
Coal royalty revenues	$	1,051	$	929	$	2,154	$	1,688

We also had accounts receivable totaling $0.3 million from Kopper-Glo at June 30, 2013.

OCI Co

At June 30, 2013, we had accounts receivable from OCI Co of $1.2 million for accrued dividends receivable. This amount is presented as Accounts receivable – affiliates on our Balance Sheet and was received on July 15, 2013.

Environmental

The operations our lessees conduct on our properties are subject to federal and state environmental laws and regulations. See Item 1, “Business — Regulation and Environmental Matters” in our Annual Report on Form 10-K for the year ended December 31, 2012. As an owner of surface interests in some properties, we may be liable for certain environmental conditions occurring on the surface properties. The terms of substantially all of our coal leases require the lessee to comply with all applicable laws and regulations, including environmental laws and regulations. Lessees post reclamation bonds assuring that reclamation will be

completed as required by the relevant permit, and substantially all of the leases require the lessee to indemnify us against, among other things, environmental liabilities. Some of these indemnifications survive the termination of the lease. Because we have no employees, employees of Western Pocahontas Properties Limited Partnership make regular visits to the mines to ensure compliance with lease terms, but the duty to comply with all regulations rests with the lessees. We believe that our lessees will be able to comply with existing regulations and do not expect any lessee’s failure to comply with environmental laws and regulations to have a material impact on our financial condition or results of operations. We have neither incurred, nor are aware of, any material environmental charges imposed on us related to our properties for the period ended June 30, 2013. We are not associated with any environmental contamination that may require remediation costs. However, our lessees do conduct reclamation work on the properties under lease to them. Because we are not the permittee of the mines being reclaimed, we are 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. During the second quarter of 2013, several citizen group lawsuits were filed against landowners alleging ongoing discharges of pollutants, including selenium, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mine on the subject property has been closed, the property has been reclaimed, and the state reclamation bond has been released. A subsidiary of NRP has been named as a defendant in one of these lawsuits. While it is too early to determine the merits or predict the outcome of any of these lawsuits, any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

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

Interest Rate Risk

Our exposure to changes in interest rates results from our borrowings under our revolving credit facility and term loan, which are subject to variable interest rates based upon LIBOR. At June 30, 2013, we had $391.0 million in variable interest rate debt. If interest rates were to increase by 1%, annual interest expense would increase approximately $3.9 million, assuming the same principal amount remained outstanding during the year.

Item 4.

Controls and Procedures

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

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

Part II. Other Information

Item 1.

Legal Proceedings

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

Item 1A.

Risk Factors

During the period covered by this report, there were no material changes from the risk factors previously disclosed in Natural Resource Partners L.P.’s Form 10-K for the year ended December 31, 2012.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

None.

Item 5.

Other Information

None.

Item 6.

Exhibits



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	—	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)

3.2	—	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).

3.3	—	First Amendment, dated March 6, 2012, to the Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P. (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q filed on August 7, 2012).

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

10.2	—	First Amendment to Term Loan Agreement, dated as of June 7, 2013 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 10, 2013).

10.3	—	Second Amended and Restated Agreement of Limited Partnership of OCI Wyoming, L.P. dated July 18, 2013 (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to Registration Statement on Form S-1 (Registration No. 333-189838) filed by OCI Resources LP on July 22, 2013).

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

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

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

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

101*	—	The following financial information from the Quarterly Report on Form 10-Q of Natural Resource Partners L.P. for the quarter ended June 30, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to Consolidated Financial Statements, tagged as blocks of text.

*	Filed or, in the case of Exhibits 32.1 and 32.2, furnished herewith.

SIGNATURES

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


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

Date: August 7, 2013

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

Date: August 7, 2013

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

Date: August 7, 2013

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

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