NATURAL RESOURCE PARTNERS LP - Quarter Report: 2017 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________________________________

FORM 10-Q



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

For the quarterly period ended June 30, 2017



¨	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.)

1201 Louisiana Street, Suite 3400

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 ý 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 ý No ¨

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



Large Accelerated Filer	¨	Accelerated Filer	ý
Non-accelerated Filer	¨ (Do not check if a smaller reporting company)	Smaller Reporting Company	¨
		Emerging Growth Company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

At August 1, 2017 there were 12,232,006 Common Units outstanding.

NATURAL RESOURCE PARTNERS, L.P.

TABLE OF CONTENTS



		Page
Part I. Financial Information
Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets	1
	Consolidated Statements of Comprehensive Income	2
	Consolidated Statements of Partners’ Capital	3
	Consolidated Statements of Cash Flows	4
	Notes to Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50
Item 4.	Controls and Procedures	50
Part II. Other Information
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 3.	Defaults Upon Senior Securities	51
Item 4.	Mine Safety Disclosure	51
Item 5.	Other Information	51
Item 6.	Exhibits	52
	Signatures	53

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)



	June 30,			December 31,
	2017			2016
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	40,783		$	40,371
Accounts receivable, net	53,997			43,202
Accounts receivable—affiliates, net	292			6,658
Inventory	7,841			6,893
Prepaid expenses and other	3,192			6,137
Current assets of discontinued operations (see Note 5)	991			991
Total current assets	107,096			104,252
Land	25,272			25,252
Plant and equipment, net	48,822			49,443
Mineral rights, net	895,642			908,192
Intangible assets, net	51,226			3,236
Intangible assets, net—affiliate	—			49,811
Equity in unconsolidated investment	248,919			255,901
Long-term contracts receivable	41,638			—
Long-term contracts receivable—affiliate	—			43,785
Other assets	9,172			3,791
Other assets—affiliate	1,265			1,018
Total assets	$	1,429,052		$	1,444,681
LIABILITIES AND CAPITAL
Current liabilities:
Accounts payable	$	5,257		$	6,234
Accounts payable—affiliates	942			940
Accrued liabilities	37,213			41,587
Current portion of long-term debt, net	173,901			138,903
Current liabilities of discontinued operations (see Note 5)	98			353
Total current liabilities	217,411			188,017
Deferred revenue	110,885			44,931
Deferred revenue—affiliates	—			71,632
Long-term debt, net	700,252			987,400
Warrant liabilities	37,457			—
Other non-current liabilities	2,699			4,565
Total liabilities	1,068,704			1,296,545
Commitments and contingencies (see Note 13)
Convertible Preferred Units (251,250 units issued and outstanding at $1,000 par value per unit; liquidation preference of $1,500 per unit)	160,377			—
Partners’ capital:
Common unitholders’ interest (12,232,006 units issued and outstanding)	204,230			152,309
General partner’s interest	1,946			887
Accumulated other comprehensive loss	(2,811		)	(1,666		)
Total partners’ capital	203,365			151,530
Non-controlling interest	(3,394		)	(3,394		)
Total capital	199,971			148,136
Total liabilities and capital	$	1,429,052		$	1,444,681

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands, except per unit data)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Revenues and other income:
Coal royalty and other	$	36,914		$	59,983		$	71,908		$	88,832
Coal royalty and other—affiliates	12,712			17,504			28,856			28,074
Construction aggregates	33,555			31,642			60,776			56,324
Equity in earnings of Ciner Wyoming	8,389			10,188			18,683			19,989
Gain (loss) on asset sales, net	3,361			(1,071		)	3,405			20,854
Total revenues and other income	94,931			118,246			183,628			214,073

Operating expenses:
Operating and maintenance expenses	31,020			29,797			60,648			56,582
Operating and maintenance expenses—affiliates, net	2,219			2,402			4,774			5,886
Depreciation, depletion and amortization	8,165			10,472			17,889			20,252
Amortization expense—affiliate	240			704			1,008			1,426
General and administrative	2,031			3,173			8,109			6,408
General and administrative—affiliates	852			866			1,976			1,803
Asset impairments	—			91			1,778			1,984
Total operating expenses	44,527			47,505			96,182			94,341

Income from operations	50,404			70,741			87,446			119,732

Other income (expense)
Interest expense	(20,377		)	(22,054		)	(43,518		)	(44,251		)
Interest expense—affiliate	—			(61		)	—			(523		)
Debt modification expense	(132		)	—			(7,939		)	—
Loss on extinguishment of debt	(4,107		)	—			(4,107		)	—
Warrant issuance expense	—			—			(5,709		)	—
Fair value adjustments for warrant liabilities	23,960			—			40,529			—
Interest income	69			7			86			26
Other expense, net	(587		)	(22,108		)	(20,658		)	(44,748		)

Net income from continuing operations	49,817			48,633			66,788			74,984
Income (loss) from discontinued operations (see Note 5)	133			(2,187		)	(74		)	(5,111		)
Net income	$	49,950		$	46,446		$	66,714		$	69,873
Less: income attributable to preferred unitholders	(7,538		)	—			(10,038		)	—
Net income attributable to common unitholders and general partner	$	42,412		$	46,446		$	56,676		$	69,873

Income from continuing operations per common unit (see Note 3)
Basic	$	3.38		$	3.90		$	4.55		$	6.02
Diluted	1.13			3.90			1.35			6.02

Net income per common unit (see Note 3)
Basic	$	3.39		$	3.73		$	4.54		$	5.61
Diluted	1.13			3.73			1.34			5.61

Net income	$	49,950		$	46,446		$	66,714		$	69,873
Add: comprehensive income (loss) from unconsolidated investment and other	(13		)	462			(1,145		)	(83		)
Comprehensive income	$	49,937		$	46,908		$	65,569		$	69,790

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

(Unaudited)



	Common Unitholders				General Partner			Accumulated Other Comprehensive Loss			Partners' Capital Excluding Non-Controlling Interest			Non-Controlling Interest			Total Capital
	Common Unitholders
	Units	Amounts
Balance at December 31, 2016	12,232	$	152,309		$	887		$	(1,666	)	$	151,530		$	(3,394	)	$	148,136
Net income ⁽¹⁾	—	65,380			1,334			—			66,714			—			66,714
Distributions to common unitholders and general partner	—	(11,009		)	(225		)	—			(11,234		)	—			(11,234		)
Distributions to preferred unitholders	—	(2,450		)	(50		)	—			(2,500		)	—			(2,500		)
Comprehensive loss from unconsolidated investment and other	—	—			—			(1,145		)	(1,145		)	—			(1,145		)
Balance at June 30, 2017	12,232	$	204,230		$	1,946		$	(2,811	)	$	203,365		$	(3,394	)	$	199,971


(1)	Net income includes $10.0 million attributable to Preferred Unitholders that accumulated during the period.

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Six Months Ended June 30,
	2017			2016
Cash flows from operating activities:
Net income	$	66,714		$	69,873
Adjustments to reconcile net income to net cash provided by operating activities of continuing operations:
Depreciation, depletion and amortization	17,889			20,252
Amortization expense—affiliates	1,008			1,426
Return on earnings from unconsolidated investment	22,112			22,050
Equity earnings from unconsolidated investment	(18,683		)	(19,989		)
Gain on asset sales, net	(3,405		)	(20,854		)
Fair value adjustments for warrant liabilities	(40,529		)	—
Debt modification expense	7,939			—
Loss on extinguishment of debt	4,107			—
Warrant issuance expense	5,709			—
Loss from discontinued operations	74			5,111
Asset impairments	1,778			1,984
Other, net	2,422			4,094
Other, net—affiliates	(112		)	212
Change in operating assets and liabilities:
Accounts receivable	(3,603		)	3,922
Accounts receivable—affiliates	(826		)	(2,271		)
Accounts payable	46			150
Accounts payable—affiliates	2			(25		)
Accrued liabilities	(3,898		)	(3,131		)
Accrued liabilities—affiliates	—			(456		)
Deferred revenue	4,489			(38,204		)
Deferred revenue—affiliates	(10,166		)	(4,060		)
Other items, net	2,527			(2,045		)
Other items, net—affiliates	—			607
Net cash provided by operating activities of continuing operations	55,594			38,646
Net cash provided by (used in) operating activities of discontinued operations	(531		)	5,815
Net cash provided by operating activities	55,063			44,461

Cash flows from investing activities:
Return of equity from unconsolidated investment	2,388			—
Proceeds from sale of oil and gas royalty properties	(544		)	34,347
Proceeds from sale of coal and aggregates royalty properties	1,427			9,802
Return of long-term contract receivables	1,207			—
Return of long-term contract receivables—affiliate	804			2,180
Proceeds from sale of plant and equipment and other	385			843
Acquisition of plant and equipment and other	(4,998		)	(3,919		)
Net cash provided by investing activities of continuing operations	669			43,253
Net cash provided by (used in) investing activities of discontinued operations	202			(3,814		)
Net cash provided by investing activities	871			39,439

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



Cash flows from financing activities:
Proceeds from issuance of Convertible Preferred Units and Warrants, net	242,100			—
Proceeds from issuance of 2022 Senior Notes, net	103,688			—
Proceeds from loans	—			20,000
Repayments of loans	(348,292		)	(98,482		)
Distributions to common unitholders and general partner	(11,234		)	(11,232		)
Distributions to preferred unitholders	(1,250		)	—
Contributions to discontinued operations	(329		)	—
Debt issue costs and other	(40,534		)	(11,998		)
Net cash used in financing activities of continuing operations	(55,851		)	(101,712		)
Net cash provided by (used in) financing activities of discontinued operations	329			(10,570		)
Net cash used in financing activities	(55,522		)	(112,282		)

Net increase (decrease) in cash and cash equivalents	412			(28,382		)

Cash and cash equivalents of continuing operations at beginning of period	40,371			41,204
Cash and cash equivalents of discontinued operations at beginning of period	—			10,569
Cash and cash equivalents at beginning of period	40,371			51,773

Cash and cash equivalents at end of period	40,783			23,391
Less: cash and cash equivalents of discontinued operations at end of period	—			2,000
Cash and cash equivalents of continuing operations at end of period	$	40,783		$	21,391

Supplemental cash flow information:
Cash paid during the period for interest	$	34,880		$	42,671
Non-cash financing activities:
Issuance of 2022 Senior Notes in exchange for 2018 Senior Notes	$	240,638		$	—

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

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Business

Natural Resource Partners L.P. (the "Partnership") engages principally in the business of owning, operating, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal, trona and soda ash, construction aggregates and other natural resources. As used in these Notes to Consolidated Financial Statements, the terms "NRP," "we," "us" and "our" refer to Natural Resource Partners L.P. and its subsidiaries, unless otherwise stated or indicated by context.

Principles of Consolidation and Reporting

The accompanying unaudited Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP") for interim financial information and with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In management's opinion, all necessary adjustments to fairly present the Partnership's results of operations, financial position and cash flows for the periods presented have been made and all such adjustments were of a normal and recurring nature. Certain reclassifications have been made to prior period amounts to conform to the current period financial statement presentation.

The Partnership reclassified oil and gas royalty activities in prior period amounts to conform to the way it internally manages and monitors segment performance. This change had no impact on the Partnership's consolidated financial position, net income or cash flows. See Note 4. Segment Information for a discussion of our operating segments.

Recently Issued Accounting Standards

The FASB issued authoritative guidance that eliminates the requirement to consider "down-round" features when determining whether certain equity-linked financial instruments or embedded features are indexed to an entity’s own stock. The guidance requires entities that present earnings per share ("EPS") under ASC 260 to recognize the effect of a down round feature in a freestanding equity-classified financial instrument only when it is triggered. The effect of triggering such a feature will be recognized as a dividend and a reduction to income available to common shareholders in basic EPS. Entities will also have to make new disclosures for financial instruments with down-round features and other terms that change conversion or exercise prices. The guidance is effective for annual and interim periods ending after December 31, 2018. Early adoption is permitted. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements and may early adopt this guidance.

The FASB issued authoritative guidance on revenue recognition. The core principle of this guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance will also require enhanced disclosures, provide more comprehensive guidance for transactions such as service revenue and contract modifications, and enhance guidance for multiple-element arrangements. The Partnership is required to adopt this guidance in the first quarter of 2018 using one of two retrospective application methods. The Partnership has performed revenue scoping procedures to identify the contracts for all of its revenue streams and utilized the practical expedient of grouping contracts or performance obligations with similar characteristics as prescribed by the new standard. The Partnership is in the process of completing its revenue contract analysis. The Partnership anticipates utilizing the full retrospective adoption method for financial statement comparability.

The FASB issued authoritative lease guidance that requires lessees to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The guidance also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The guidance is effective for annual and interim periods ending after December 31, 2018. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.

The FASB issued authoritative guidance that replaces the incurred loss impairment methodology in the current standard with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The guidance is effective for annual and interim periods ending after December 31,

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

2019. The Partnership does not expect the impact of the provisions of this guidance to have a material effect on its consolidated financial statements.

The FASB issued authoritative guidance to clarify how certain cash receipts and cash payments are presented and classified in the statement of cash flows in order to reduce current and potential future diversity in practice. The guidance is effective for annual and interim periods ending after December 31, 2017. The Partnership adopted this guidance in the second quarter of 2017 and its adoption did not have a material effect on its consolidated financial statements.

2. Convertible Preferred Units and Warrants

On March 2, 2017, NRP issued $250 million of Class A Convertible Preferred Units representing limited partner interests in NRP (the "Preferred Units") to certain entities controlled by funds affiliated with the Blackstone Group, L.P. (collectively referred to as "Blackstone") and certain affiliates of GoldenTree Asset Management LP (collectively referred to as "GoldenTree") (together the "Preferred Purchasers") pursuant to a Preferred Unit and Warrant Purchase Agreement. NRP issued 250,000 Preferred Units to the Preferred Purchasers at a price of $1,000 per Preferred Unit (the "Per Unit Purchase Price"), less a 2.5% structuring and origination fee. The Preferred Units entitle the Preferred Purchasers to receive cumulative distributions at a rate of 12% per year, up to one half of which NRP may pay in additional Preferred Units (such additional Preferred Units, the "PIK Units").

NRP also issued two tranches of warrants (the "Warrants") to purchase common units to the Preferred Purchasers (Warrants to purchase 1.75 million common units with a strike price of $22.81 and Warrants to purchase 2.25 million common units with a strike price of $34.00). The Warrants may be exercised by the holders thereof at any time before the eighth anniversary of the closing date. Upon exercise of the Warrants, NRP may, at its option, elect to settle the Warrants in common units or cash, each on a net basis.

The Preferred Units have a perpetual term, unless converted or redeemed as described below. The Preferred Units (including any PIK Units) are convertible into common units at a price of $1,000 per Preferred Unit plus the value of any accrued and unpaid distributions at the election of the holders (1) after the fifth anniversary and prior to the eighth anniversary of the issue date at a 7.5% discount to the volume weighted average trading price of our common units (the "VWAP") for the 30 trading days immediately prior to the notice of conversion if the 30-day VWAP immediately prior to such notice is greater than $51.00 (subject to a maximum of 33% of the Preferred Units per year) and (2) after the eighth anniversary of the issue date at a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion. Instead of issuing common units pursuant to clause (1) of the preceding sentence, NRP has the option to redeem the Preferred Units proposed to be converted for cash at a price equal to the $1,000 per Preferred Unit plus the value of any accrued and unpaid distributions. To the extent the holders of the Preferred Units have not elected to convert their Preferred Units by the twelfth anniversary of the issue date, NRP has the right to force conversion of the Preferred Units at a price equal to the $1,000 per Preferred Unit plus the value of any accrued and unpaid distributions into common units at a 10% discount to the VWAP for the 30 trading days immediately prior to the notice of conversion.

In addition, NRP has the ability to redeem at any time (subject to compliance with its debt agreements) all or any portion of the Preferred Units (including PIK Units) for cash at the agreed upon per unit amount, which is calculated as the Per Unit Purchase Price multiplied by (i) prior to the third anniversary of the closing date, 1.50, (ii) on or after the third anniversary of the closing date and prior to the fourth anniversary of the closing date, 1.70 and (iii) on or after the fourth anniversary of the closing date, 1.85; less all Preferred Unit distributions made by NRP at the time of redemption; plus the value of all accrued and unpaid Preferred Unit distributions. The Preferred Units are redeemable at the option of the Preferred Unit Purchasers only upon a change in control.

The terms of the Preferred Units contain certain restrictions on NRP's ability to pay distributions on its common units. To the extent that either (i) NRP's consolidated Leverage Ratio, as defined in the Partnership's Fifth Amended and Restated Partnership Agreement dated March 2, 2017 (the "Restated Partnership Agreement"), is greater than 3.25x, or (ii) the ratio of NRP's Distributable Cash Flow (as defined in the Restated Partnership Agreement) to cash distributions made or proposed to be made is less than 1.2x (in each case, with respect to the most recently completed four-quarter period), NRP may not increase the quarterly distribution above $0.45 per quarter without the approval of the holders of a majority of the outstanding Preferred Units. In addition, if at any time after January 1, 2022, any PIK Units are outstanding, NRP may not make distributions on its common units until it has redeemed all PIK Units for cash.

The holders of the Preferred Units have the right to vote with holders of NRP’s common units on an as-converted basis and have other customary approval rights with respect to changes of the terms of the Preferred Units. In addition, Blackstone has certain approval rights over certain matters as identified in the Restated Partnership Agreement. GoldenTree also has more limited approval

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

rights that will expand once Blackstone's ownership goes below the Minimum Preferred Unit Threshold (as defined below). These approval rights are not transferrable without NRP's consent. In addition, the approval rights held by Blackstone and GoldenTree will terminate at such time that Blackstone (together with their affiliates) or GoldenTree (together with their affiliates), as applicable, no longer own at least 20% of the total number of Preferred Units issued on the closing date, together with all PIK Units that have been issued but not redeemed (the "Minimum Preferred Unit Threshold").

At the closing, pursuant to a Board Representation and Observation Rights Agreement, the Preferred Purchasers received certain board appointment and observation rights, and Blackstone appointed one director and one observer to the Board of Directors of GP Natural Resource Partners LLC.

NRP also entered into a registration rights agreement (the "Preferred Unit and Warrant Registration Rights Agreement") with the Preferred Purchasers, pursuant to which NRP is required to file (i) a shelf registration statement to register the common units issuable upon exercise of the Warrants and to cause such registration statement to become effective not later than 90 days following the closing date and (ii) a shelf registration statement to register the common units issuable upon conversion of the Preferred Units and to cause such registration statement to become effective not later than the earlier of the fifth anniversary of the closing date or 90 days following the first issuance of any common units upon conversion of Preferred Units (the "Registration Deadlines"). In addition, the Preferred Unit and Warrant Registration Rights Agreement gives the Preferred Purchasers piggyback registration and demand underwritten offering rights under certain circumstances. The shelf registration statement to register the common units issuable upon exercise of the Warrants became effective on April 20, 2017. If the shelf registration statement to register the common units issuable upon conversion of the Preferred Units is not effective by the applicable Registration Deadline, NRP will be required to pay the Preferred Purchasers liquidated damages in the amounts and upon the term set forth in the Preferred Unit and Warrant Registration Rights Agreement.

Accounting for the Preferred Units and Warrants

Classification

The Preferred Units are accounted for on NRP's consolidated balance sheet as temporary equity due to certain contingent redemption rights that may be exercised at the election of Preferred Purchasers. The Warrants are accounted for on NRP's consolidated balance sheet as a liability because of a "down-round" anti-dilution price protection provision that reduces the Warrant holders' exercise price if NRP sells common units at a price less than the current strike price (subject to certain exceptions).

Initial Measurement

The net transaction price as shown below was allocated first to the fair value of the Warrants with the remainder to the Preferred Units. NRP allocated the transaction issuance costs to the Preferred Units and Warrants primarily on a pro-rata basis based on their relative inception date allocated values. The Preferred Units and Warrants were initially recognized at fair value by allocating the transaction price as follows:



	March 2, 2017
Transaction price, gross	$	250,000
Structuring, origination and other fees to Preferred Purchasers	(7,900		)
Transaction costs to other third parties	(10,696		)
Transaction price, net	$	231,404
Allocation of net transaction price
Preferred Units, net	$	159,127
Warrants liabilities	77,986
Issuance costs allocated to Warrants and expensed	(5,709		)
Transaction price, net	$	231,404

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Subsequent Measurement

Subsequent adjustment of the Preferred Units will not occur until NRP has determined that the conversion or redemption of all or a portion of the Preferred Units is probable of occurring. Once conversion or redemption becomes probable of occurring, the carrying amount of the Preferred Units will be accreted to their redemption value over the period from the date the feature is probable of occurring to the date the preferred stock can first be converted or redeemed. The Warrants and embedded derivatives are accounted for at fair value and are remeasured each quarter. See Note 11. Fair Value Measurements for further information regarding valuation of the warrants and embedded derivatives.

NRP recognizes Preferred Unit distributions on the date the distribution is declared. During the three and six months ended June 30, 2017, NRP declared a $2.5 million distribution on the Preferred Units from March 2, 2017 (the date of issuance) through March 31, 2017. One-half of the $2.5 million distribution was paid-in-kind through the issuance of 1,250 additional Preferred Units and the other half was paid in cash. The following table shows the financial position of the Preferred Units from initial measurement at March 2, 2017 to June 30, 2017 (in thousands):



Balance at December 31, 2016	$	—
Issuance of Preferred Units, net	159,127
Distribution paid-in-kind	1,250
Balance at June 30, 2017	$	160,377

Income available to common unitholders and the general partner is reduced by Preferred Unit distributions that accumulated during the period. During the three and six months ended June 30, 2017, NRP reduced net income attributable to common unitholders and the general partner by $7.5 million and $10.0 million, respectively, as a result of accumulated Preferred Unit distributions.

3. Net Income Per Common Unit

Basic net income per common unit is computed by dividing net income, after considering income attributable to preferred unitholders and the general partner’s interest, by the weighted average number of common units outstanding. Diluted net income per common unit includes the effect of NRP's Warrants and Preferred Units (see Note 2. Convertible Preferred Units and Warrants), if the inclusion of these items is dilutive.

The dilutive effect of the Warrants is calculated using the treasury stock method, which assumes that the proceeds from the exercise of these instruments are used to purchase common units at the average market price for the period. The calculation of the dilutive effect of the Warrants for the three and six months ended June 30, 2017, did not include the net settlement of Warrants to purchase 2.25 million of common units with a strike price of $34.00 because the impact would have been anti-dilutive.

The dilutive effect of the Preferred Units is calculated using the if-converted method. Under the if-converted method, the Preferred Units are assumed to be converted at the beginning of the period, and the resulting common units are included in the denominator of the diluted EPU calculation for the period being presented. Interest recognized during the period (including the effect of accretion of discounts and amortization of issuance costs, if any) and distributions declared in the period and undeclared distributions on the Preferred Units that accumulated during the period are added back to the numerator for purposes of the if-converted calculation.

The following table reconciles net income and weighted average units used in computing basic and diluted net income per common unit is as follows:

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)



	Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016			2017			2016
Allocation of net income:
Net income from continuing operations	$	49,817	$	48,633		$	66,788		$	74,984
Less: income attributable to preferred unitholders	7,538		—			10,038			—
Less: net income from continuing operations and income attributable to preferred unitholders allocated to the general partner	914		907			1,135			1,368
Net income from continuing operations attributable to common unitholders	$	41,365	$	47,726		$	55,615		$	73,616

Net income (loss) from discontinued operations	$	133	$	(2,187	)	$	(74	)	$	(5,111	)
Less: net income (loss) from discontinued operations attributable to the general partner	3		(44		)	(1		)	(102		)
Net income (loss) from discontinued operations attributable to common unitholders	$	130	$	(2,143	)	$	(73	)	$	(5,009	)

Net income	$	49,950	$	46,446		$	66,714		$	69,873
Less: income attributable to preferred unitholders	7,538		—			10,038			—
Less: net income and income attributable to preferred unitholders allocated to the general partner	917		863			1,134			1,266
Net income attributable to common unitholders	$	41,495	$	45,583		$	55,542		$	68,607

Basic Income (Loss) per Unit:
Weighted average common units—basic	12,232		12,232			12,232			12,232
Basic net income from continuing operations per common unit	$	3.38	$	3.90		$	4.55		$	6.02
Basic net income (loss) from discontinued operations per common unit	$	0.01	$	(0.18	)	$	(0.01	)	$	(0.41	)
Basic net income per common unit	$	3.39	$	3.73		$	4.54		$	5.61

Diluted Income (Loss) per Unit:
Weighted average common units—basic	12,232		12,232			12,232			12,232
Plus: dilutive effect of Warrants	467		—			361			—
Plus: dilutive effect of Preferred Units	9,760		—			6,517			—
Weighted average common units—diluted	22,459		12,232			19,110			12,232

Net income from continuing operations	$	49,817	$	48,633		$	66,788		$	74,984
Less: fair value adjustments for warrant liabilities	23,960		—			40,529			—
Less: net income from continuing operations and fair value adjustments for warrant liabilities allocated to the general partner	586		907			525			1,368
Diluted net income from continuing operations attributable to common unitholders	$	25,271	$	47,726		$	25,734		$	73,616

Diluted net income (loss) from discontinued operations attributable to common unitholders	$	130	$	(2,143	)	$	(73	)	$	(5,009	)

Net income	$	49,950	$	46,446		$	66,714		$	69,873
Less: fair value adjustments for warrant liabilities	23,960		—			40,529			—
Less: net income and fair value adjustments for warrant liabilities allocated to the general partner	589		863			524			1,266
Diluted net income attributable to common unitholders	$	25,401	$	45,583		$	25,661		$	68,607

Diluted net income from continuing operations per common unit	$	1.13	$	3.90		$	1.35		$	6.02
Diluted net income (loss) from discontinued operations per common unit	$	0.01	$	(0.18	)	$	—		$	(0.41	)
Diluted net income per common unit	$	1.13	$	3.73		$	1.34		$	5.61

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

4. Segment Information

The Partnership's operating segments are strategic business units that offer products and services to different customer segments in different geographies within the U.S. and that are managed accordingly. NRP has the following three operating segments:

Coal Royalty and Other—consists primarily of coal royalty and coal related transportation and processing assets. Other assets include aggregate royalty, industrial mineral royalty, oil and gas royalty and timber. The Partnership's coal reserves are primarily located in Appalachia, the Illinois Basin and the Western United States. The Partnership's aggregates and industrial minerals are located in a number of states across the United States. The Partnership's oil and gas royalty assets are located in Louisiana.

Soda Ash—consists of the Partnership's 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. Ciner Resources LP, the Partnership's operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. The Partnership receives regular quarterly distributions from this business.

Construction Aggregates—consists of the Partnership's construction materials business that operates hard rock quarries, an underground limestone mine, sand and gravel plants, asphalt plants and marine terminals. The Partnership's construction aggregates business operates in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.

Direct segment costs and certain costs incurred at a corporate level that are identifiable and that benefit the Partnership's segments are allocated to the operating segments. These allocated costs include costs of: taxes, legal, information technology and shared facilities services and are included in Operating and maintenance expenses and Operating and maintenance expenses—affiliates, net on the Consolidated Statements of Comprehensive Income. Intersegment sales are at prices that approximate market.

Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include corporate headquarters and overhead, financing, centralized treasury and accounting and other corporate-level activity not specifically allocated to a segment.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The following table summarizes certain financial information for each of the Partnership's operating segments (in thousands):



	Operating Segments
For the Three Months Ended	Coal Royalty and Other			Soda Ash		Construction Aggregates			Corporate and Financing			Total
June 30, 2017
Revenues (including affiliates)	$	49,626		$	8,389	$	33,555		$	—		$	91,570
Intersegment revenues (expenses)	68			—		(68		)	—			—
Gain on asset sales	3,184			—		177			—			3,361
Operating and maintenance expenses (including affiliates)	5,419			—		27,820			—			33,239
General and administrative (including affiliates)	—			—		—			2,883			2,883
Depreciation, depletion and amortization (including affiliates)	5,375			—		3,030			—			8,405
Other expense, net	—			—		178			409			587
Net income (loss) from continuing operations	42,084			8,389		2,636			(3,292		)	49,817
Net income from discontinued operations	—			—		—			—			133

June 30, 2016
Revenues (including affiliates)	$	77,487		$	10,188	$	31,642		$	—		$	119,317
Intersegment revenues (expenses)	30			—		(30		)	—			—
Gain (loss) on asset sales	(1,080		)	—		9			—			(1,071		)
Operating and maintenance expenses (including affiliates)	7,707			—		24,492			—			32,199
General and administrative (including affiliates)	—			—		—			4,039			4,039
Depreciation, depletion and amortization (including affiliates)	7,486			—		3,690			—			11,176
Asset impairment	91			—		—			—			91
Other expense, net	—			—		—			22,108			22,108
Net income (loss) from continuing operations	61,153			10,188		3,439			(26,147		)	48,633
Net loss from discontinued operations				—		—			—			(2,187		)

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)



	Operating Segments
For the Six Months Ended	Coal Royalty and Other		Soda Ash		Construction Aggregates			Corporate and Financing			Total
June 30, 2017
Revenues (including affiliates)	$	100,764	$	18,683	$	60,776		$	—		$	180,223
Intersegment revenues (expenses)	130		—		(130		)	—			—
Gain on asset sales	3,213		—		192			—			3,405
Operating and maintenance expenses (including affiliates)	12,803		—		52,619			—			65,422
General and administrative (including affiliates)	—		—		—			10,085			10,085
Depreciation, depletion and amortization (including affiliates)	12,348		—		6,549			—			18,897
Asset impairment	1,778		—		—			—			1,778
Other expense, net	—		—		573			20,085			20,658
Net income (loss) from continuing operations	77,178		18,683		1,097			(30,170		)	66,788
Net loss from discontinued operations	—		—		—			—			(74		)

June 30, 2016
Revenues (including affiliates)	$	116,906	$	19,989	$	56,324		$	—		$	193,219
Intersegment revenues (expenses)	52		—		(52		)	—			—
Gain on asset sales	20,845		—		9			—			20,854
Operating and maintenance expenses (including affiliates)	15,841		—		46,627			—			62,468
General and administrative (including affiliates)	—		—		—			8,211			8,211
Depreciation, depletion and amortization (including affiliates)	14,426		—		7,252			—			21,678
Asset impairment	1,984		—		—			—			1,984
Other expense, net	—		—		—			44,748			44,748
Net income (loss) from continuing operations	105,552		19,989		2,402			(52,959		)	74,984
Net loss from discontinued operations	—		—					—			(5,111		)

Total assets at June 30, 2017:
Continuing operations	980,851		248,919		190,233			8,058			1,428,061
Discontinued operations	—		—		—			—			991
Total assets at December 31, 2016:
Continuing operations	990,172		255,901		190,615			7,002			1,443,690
Discontinued operations	—		—		—			—			991

5. Discontinued Operations

In July 2016, NRP Oil and Gas sold its non-operated oil and gas working interest assets for $116.1 million in gross sales proceeds. The sale had an effective date of April 1, 2016.

The Partnership's exit from its non-operated oil and gas working interest business represented a strategic shift to reduce debt and focus on its soda ash, coal royalty and construction aggregates business segments. As a result, the Partnership classified the operating results, cash flows and assets and liabilities of its non-operated oil and gas working interest assets as discontinued operations in its consolidated statements of comprehensive income and consolidated statements of cash flows for all periods presented. The Partnership transitioned the remaining investments in royalty interests in oil and natural gas properties into the Coal Royalty and Other operating segment during the third quarter of 2016.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The following table (in thousands) presents summarized financial results of the Partnership's discontinued operations in the Consolidated Statements of Comprehensive Income:



	Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016			2017			2016
Revenues and other income:
Oil and gas	$	7	$	9,511		$	22		$	16,435
Gain (loss) on asset sales	136		(184		)	57			(184		)
Total revenues and other income	143		9,327			79			16,251

Operating expenses:
Operating and maintenance expenses (including affiliates)	10		5,871			153			10,252
Depreciation, depletion and amortization	—		3,286			—			7,527
Asset impairments	—		427			—			564
Total operating expenses	10		9,584			153			18,343

Interest expense	—		(1,930		)	—			(3,019		)
Income (loss) from discontinued operations	$	133	$	(2,187	)	$	(74	)	$	(5,111	)

The following table (in thousands) presents the carrying amounts of the Partnership's assets and liabilities of discontinued operations in the Consolidated Balance Sheets:



	June 30,		December 31,
	2017		2016
ASSETS
Current assets:
Accounts receivable, net (including affiliates) (1)	$	991	$	991
Total current assets	991		991
Total assets of discontinued operations	$	991	$	991

LIABILITIES
Current liabilities:
Other (including affiliates) (1)	$	98	$	353
Total current liabilities	98		353
Total liabilities of discontinued operations	$	98	$	353


(1)	See Note 12. Related Party Transactions for additional information on the Partnership's related party assets and liabilities.

The following table (in thousands) presents supplemental cash flow information of the Partnership's discontinued operations:



	Six Months Ended June 30,
	2017		2016
Cash paid for interest	$	—	$	1,489

Capital expenditures related to the Partnership's discontinued operations were $0.0 million and $3.8 million during the six months ended June 30, 2017 and 2016, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

6. Equity Investment

The Partnership accounts for its 49% investment in Ciner Wyoming using the equity method of accounting. Ciner Wyoming distributed $24.5 million and $22.1 million to the Partnership in the six months ended June 30, 2017 and 2016, respectively.

The difference between the amount at which the investment in Ciner Wyoming is carried and the amount of underlying equity in Ciner Wyoming's net assets was $147.9 million and $150.0 million as of June 30, 2017 and December 31, 2016, respectively. This excess basis relates to plant, property and equipment and right to mine assets. The excess basis difference that relates to property, plant and equipment is being amortized into income using the straight-line method over a weighted average of 28 years. The excess basis difference that relates to right to mine assets is being amortized into income using the units of production method.

The Partnership's equity in the earnings of Ciner Wyoming is summarized as follows (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Income allocation to NRP’s equity interests	$	9,274		$	11,388		$	20,754		$	22,384
Amortization of basis difference	(885		)	(1,200		)	(2,071		)	(2,395		)
Equity in earnings of unconsolidated investment	$	8,389		$	10,188		$	18,683		$	19,989

The results of Ciner Wyoming’s operations are summarized as follows (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Sales	$	119,737	$	116,698	$	246,309	$	231,082
Gross profit	24,219		28,732		52,916		56,983
Net Income	18,926		23,241		42,354		45,682

The financial position of Ciner Wyoming is summarized as follows (in thousands):



	June 30,		December 31,
	2017		2016
Current assets	$	157,198	$	134,616
Non-current assets	233,313		235,427
Current liabilities	53,713		55,396
Non-current liabilities	130,600		98,425

The purchase agreement for the acquisition of the Partnership’s interest in Ciner Wyoming required the Partnership to pay additional contingent consideration to Anadarko to the extent certain performance criteria described in the purchase agreement were met by Ciner Wyoming in any of the years 2013, 2014 or 2015. During the first quarters of 2014, 2015 and 2016, the Partnership paid contingent consideration of $0.5 million, $3.8 million and $7.2 million, respectively, in contingent consideration to Anadarko for performance criteria met by Ciner Wyoming in 2013, 2014 and 2015, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

7. Plant and Equipment

The Partnership’s plant and equipment consist of the following (in thousands):



	June 30,			December 31,
	2017			2016
Plant and equipment at cost	$	83,339		$	79,171
Construction in process	58			557
Less accumulated depreciation	(34,575		)	(30,285		)
Total plant and equipment, net	$	48,822		$	49,443

Depreciation expense related to the Partnership's plant and equipment totaled $2.5 million and $3.0 million for the three months ended June 30, 2017 and 2016, respectively. Depreciation expense related to the Partnership's plant and equipment totaled $5.4 million and $6.5 million for the six months ended June 30, 2017 and 2016, respectively.

8. Mineral Rights

The Partnership’s mineral rights consist of the following (in thousands):



	June 30, 2017
	Carrying Value		Accumulated Depletion			Net Book Value
Coal properties	$	1,170,700	$	(429,079	)	$	741,621
Aggregates properties	151,236		(14,605		)	136,631
Oil and gas royalty properties	12,395		(6,723		)	5,672
Other	13,168		(1,450		)	11,718
Total	$	1,347,499	$	(451,857	)	$	895,642



	December 31, 2016
	Carrying Value		Accumulated Depletion			Net Book Value
Coal properties	$	1,170,904	$	(420,032	)	$	750,872
Aggregates properties	176,774		(39,056		)	137,718
Oil and gas royalty properties	12,395		(6,289		)	6,106
Other	14,946		(1,450		)	13,496
Total	$	1,375,019	$	(466,827	)	$	908,192

Depletion expense related to the Partnership’s mineral rights totaled $5.0 million and $7.2 million for the three months ended June 30, 2017 and 2016, respectively. Depletion expense related to the Partnership’s mineral rights totaled $11.7 million and $13.3 million for the six months ended June 30, 2017 and 2016, respectively.

2016 Sale of Royalty Properties

The Partnership completed the sale of the following assets during the six months ended June 30, 2016:

1)Oil and gas royalty and overriding royalty interests in the Coal Royalty and Other segment in several producing properties located in the Appalachian Basin for $36.4 million gross sales proceeds. The effective date of the sale was January 1, 2016, and the Partnership recorded a $19.2 million gain from this sale included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income.

2)Aggregates reserves and related royalty rights in the Coal Royalty and Other segment at three aggregates operations located in Texas, Georgia and Tennessee for $10.0 million gross sales proceeds. The effective date of the sale was February 1, 2016, and the Partnership recorded a $1.6 million gain from this sale included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

9. Intangible Assets (Including Affiliate)

The Partnership's intangible assets (including affiliate) primarily consists of above market coal transportation contracts with subsidiaries of Foresight Energy LP ("Foresight Energy") in which the Partnership receives throughput fees for the handling and transportation of coal. In addition, the Partnership's intangible assets include permits, aggregates-related trade names and other agreements. The Partnership's intangible assets (including affiliate) included in the Partnership's Consolidated Balance Sheet are as follows (in thousands):



	June 30,			December 31,
	2017			2016
Intangible assets (including affiliate)	$	86,336		$	86,336
Less: accumulated amortization (including affiliate)	(35,110		)	(33,289		)
Total intangible assets, net (including affiliate)	$	51,226		$	53,047

Amortization expense related to the Partnership's intangible assets—affiliate totaled $0.2 million and $0.7 million for the three months ended June 30, 2017 and 2016, respectively. Amortization expense related to the Partnership's intangible assets—affiliate totaled $1.0 million and $1.4 million for the six months ended June 30, 2017 and 2016, respectively. Amortization expense related to the Partnership's intangible assets totaled $0.6 million and $0.3 million for the three months ended June 30, 2017 and 2016, respectively. Amortization expense related to the Partnership's intangible assets totaled $0.8 million and $0.5 million for the six months ended June 30, 2017 and 2016, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

10. Debt

As of June 30, 2017 and December 31, 2016, the Partnership's debt consisted of the following (in thousands):



	June 30,			December 31,
	2017			2016
NRP LP debt:
10.500% senior notes, with semi-annual interest payments in March and September, due March 2022, $241 million issued at par and $105 million issued at 98.75%	$	345,638		$	—
9.125% senior notes, with semi-annual interest payments in April and October, due October 2018, $300 million issued at 99.007% and $125 million issued at 99.5%	94,362			425,000
Opco debt:
Revolving credit facility, due April 2020	—			210,000
Senior notes
4.91% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018	4,594			9,187
8.38% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2019	42,686			64,029
5.05% with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020	30,633			30,633
5.55% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023	16,136			18,825
4.73% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023	52,204			52,204
5.82% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024	104,583			119,524
8.92% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024	31,738			36,272
5.03% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026	134,035			134,035
5.18% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026	38,262			38,262
5.31% utility local improvement obligation, with annual principal and interest payments in February, due March 2021	—			961
Total debt at face value	$	894,871		$	1,138,932
Net unamortized debt discount	(1,972		)	(1,322		)
Net unamortized debt issuance costs	(18,746		)	(11,307		)
Total debt, net	$	874,153		$	1,126,303
Less: current portion of long-term debt	173,901			138,903
Total long-term debt	$	700,252		$	987,400

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

NRP LP Debt

2018 Senior Notes

In September 2013, the Partnership, together with NRP Finance Corporation ("NRP Finance"), a wholly owned subsidiary of the Partnership, as co-issuer, issued $300.0 million of 9.125% Senior Notes at an offering price of 99.007% of par (the "2018 Senior Notes"). Net proceeds after expenses from the issuance of 2018 Senior Notes were approximately $289.0 million. Interest on the 2018 Senior Notes is paid semi-annually on April 1 and October 1, and the 2018 Senior Notes will mature on October 1, 2018. None of the Partnership's subsidiaries guarantee the 2018 Senior Notes.

In October 2014, the Partnership, together with NRP Finance as co-issuer, issued an additional $125.0 million of the 2018 Senior Notes at an offering price of 99.5% of par. The additional issuance constituted the same series of securities as the existing 2018 Senior Notes.

The Partnership and NRP Finance have the option to redeem the 2018 Senior Notes, in whole or in part, at any time on or after April 1, 2016, at fixed redemption prices specified in the indenture governing the NRP 2018 Senior Notes (the "2018 Indenture"). The 2018 Indenture contains covenants that, among other things, limit the ability of the Partnership and certain of its subsidiaries to incur or guarantee additional indebtedness. Under the 2018 Indenture, the Partnership and certain of its subsidiaries generally are not permitted to incur additional indebtedness unless, on a consolidated basis, the fixed charge coverage ratio (as defined in the indenture) is at least 2.0 to 1.0 for the four preceding full fiscal quarters. The ability of the Partnership and certain of its subsidiaries to incur additional indebtedness is further limited in the event the amount of indebtedness of the Partnership and certain of its subsidiaries that is senior to the Partnership's unsecured indebtedness exceeds certain thresholds.

In March 2017, the Partnership and NRP Finance exchanged $241 million aggregate principal amount of the 2018 Senior Notes for $241 million aggregate principal amount of a new series of 10.500% Senior Notes due 2022 (the “2022 Senior Notes”). In April 2017, the Partnership and NRP Finance redeemed $90 million in aggregate principal amount of the 2018 Senior Notes at a redemption price of 104.563%, and paid all accrued and unpaid interest thereon. In addition, pursuant to the 2022 Indenture (as defined below), the Partnership and NRP Finance will redeem any and all remaining outstanding 2018 Senior Notes at par (and pay accrued and unpaid interest thereon) within 60 days after October 1, 2017. NRP anticipates using cash on hand and available borrowings under the Opco Credit Facility in order pay the October 2017 redemption of the 2018 Senior Notes.

2022 Senior Notes

In March 2017, NRP and NRP Finance issued $346 million aggregate principal amount of 2022 Senior Notes to several holders of their 2018 Senior Notes. Of the $346 million of 2022 Senior Notes issued, $241 million in aggregate principal amount were issued in exchange for $241 million in aggregate principal amount of 2018 Senior Notes, and $105 million of the 2022 Senior Notes were issued to the holders for cash. The 2022 Senior Notes are issued under an Indenture dated as of March 2, 2017 (the "2022 Indenture"), bear interest at 10.500% per year, are payable semi-annually on March 15 and September 15, beginning September 15, 2017, and mature on March 15, 2022. The $105.0 million in 2022 Senior Notes purchased for cash were issued at a price of 98.75% (original issue discount of 1.25%), and each holder exchanging 2018 Senior Notes received a fee of 5.813% of the aggregate principal amount of all 2018 Senior Notes tendered for exchange by such holder, as well as all accrued and unpaid interest thereon. The 5.813% fee included a 4.563% call premium on the early repayment of the 2018 Senior Notes and a 1.25% fee on the exchange of the 2018 Notes for 2022 Senior Notes. This fee is accounted for as a debt issue cost, capitalized and shown net of the debt liability on our consolidated balance sheet.

NRP and NRP Finance have the option to redeem the 2022 Senior Notes, in whole or in part, at any time on or after March 15, 2019, at the redemption prices (expressed as percentages of principal amount) of 105.25% for the 12-month period beginning March 15, 2019, 102.625% for the 12-month period beginning March 15, 2020, and thereafter at 100.000%, together, in each case, with any accrued and unpaid interest to the date of redemption. Furthermore, before March 15, 2019, NRP may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2022 Senior Notes with the net proceeds of certain public or private equity offerings at a redemption price of 110.500% of the principal amount of 2022 Senior Notes, plus any accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2022 Senior Notes issued under the 2022 Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. In the event of a change of control, as defined in the 2022 Indenture, the holders of the 2022 Senior Notes may require us to purchase their 2022 Senior Notes at a purchase price equal to 101% of the principal amount of the 2022 Senior Notes, plus accrued and unpaid interest, if any.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The 2022 Indenture contains restrictive covenants that are substantially similar to those contained in the Indenture governing the 2018 Senior Notes, except that the debt incurrence and restricted payments covenants contain additional restrictions. Under the debt incurrence covenant, NRP's non-guarantor restricted subsidiaries will not be permitted to incur additional indebtedness unless their consolidated leverage ratio is less than 3.00x (measured on a pro forma basis and assuming that the greater of (i) $150.0 million of debt (or, if less, at NRP's election, the amount of total lending commitments under any revolving credit facility) and (ii) the actual amount of debt outstanding is outstanding under any revolving credit facility); provided, however, that such non-guarantor restricted subsidiaries will be permitted to make up to $150 million in borrowings under a revolving credit facility (which amount will be reduced on a dollar-for-dollar basis to the extent we have made the election described in clause (i) above). Under the restricted payments covenant, NRP will not be able to increase the quarterly distribution on its common units or elect to pay more than 50% of the distributions required to be made on the Preferred Units in cash, unless, in each case, its consolidated leverage ratio is less than 4.00x. The 2022 Indenture also contains restrictions on NRP's ability to redeem the Preferred Units.

The 2022 Senior Notes are the senior unsecured obligations of NRP and NRP Finance. The 2022 Senior Notes rank equal in right of payment to all existing and future senior unsecured debt of NRP and NRP Finance, including the remaining outstanding 2018 Senior Notes, and senior in right of payment to any of NRP's subordinated debt. The 2022 Senior Notes are effectively subordinated in right of payment to all future secured debt of NRP and NRP Finance to the extent of the value of the collateral securing such indebtedness and are structurally subordinated in right of payment to all existing and future debt and other liabilities of our subsidiaries, including the Opco Credit Facility and each series of Opco’s existing senior notes. None of NRP's subsidiaries guarantee the 2022 Senior Notes.

As of June 30, 2017 and December 31, 2016, NRP and NRP Finance were in compliance with the terms of its debt agreements.

Opco Debt

All of Opco’s debt is guaranteed by its wholly owned subsidiaries and is secured by certain of the assets of Opco and its wholly owned subsidiaries other than NRP Trona LLC, as further described below. As of June 30, 2017 and December 31, 2016, Opco was in compliance with the terms of the financial covenants contained in its debt agreements.

Opco Credit Facility

Opco’s $180 million Third Amended and Restated Credit Agreement, as amended through March 2017 (the "Opco Credit Facility"), matures on April 30, 2020, is guaranteed by all of Opco’s wholly owned subsidiaries, and is secured by liens on certain of the assets of Opco and its subsidiaries, as further described below. Commitments under the Opco Credit Facility will be reduced to $150 million at December 31, 2017 and further reduced to $100 million at December 31, 2018 through maturity in April 2020.

Indebtedness under the Opco Credit Facility bears interest, at Opco's option, at:


•	the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 1%, in each case plus an applicable margin ranging from 2.50% to 3.50%; or


•	a rate equal to LIBOR plus an applicable margin ranging from 3.50% to 4.50%.

The weighted average interest rates for the borrowings outstanding under the Opco Credit Facility for three months ended June 30, 2017 and 2016 were 0.0% and 4.11%, respectively. The weighted average interest rates for the borrowings outstanding under the Opco Credit Facility for six months ended June 30, 2017 and 2016 were 5.22% and 3.95%, respectively. Opco will incur a commitment fee on the unused portion of the revolving credit facility at a rate of 0.50% per annum. Opco may prepay all amounts outstanding under the Opco Credit Facility at any time without penalty. As of June 30, 2017, Opco had no indebtedness outstanding under the Opco Credit Facility.

The Opco Credit Facility contains financial covenants requiring Opco to maintain:


•	a leverage ratio of consolidated indebtedness to EBITDDA (as defined in the Opco Credit Facility) not to exceed 4.0x; provided, however, that if NRP increases its quarterly distribution to its common unitholders above $0.45 per common unit, the maximum leverage ratio under the Opco Credit Facility will permanently decrease from 4.0x to 3.0x.


•	a fixed charge coverage ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease expense) of not less than 3.5 to 1.0.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The Opco Credit Facility contains certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations. Included in the investment covenant are restrictions upon Opco’s ability to acquire assets where Opco does not maintain certain levels of liquidity. In addition, Opco is required to use 75% of the net cash proceeds of certain non-ordinary course asset sales to repay the Opco Credit Facility (without any corresponding commitment reduction) and use the remaining 25% of the net cash proceeds to offer to repay its senior notes on a pro rata basis, as described below under “—Opco Senior Notes.” The Opco Credit Facility also contains customary events of default, including cross-defaults under Opco’s senior notes.

The Opco Credit Facility is collateralized and secured by liens on certain of Opco’s assets with carrying values of $655.2 million and $673.0 million classified as Land, Plant and equipment and Mineral rights on the Partnership’s Consolidated Balance Sheet as of June 30, 2017 and December 31, 2016, respectively. The collateral includes (1) the equity interests in all of Opco’s wholly owned subsidiaries, other than NRP Trona LLC (which owns a 49% non-controlling equity interest in Ciner Wyoming), (2) the personal property and fixtures owned by Opco’s wholly owned subsidiaries, other than NRP Trona LLC, (3) Opco’s material coal royalty revenue producing properties, (4) real property associated with certain of NRP's construction aggregates business, and (5) certain of Opco’s coal-related infrastructure assets.

Opco Senior Notes

Opco has issued several series of private placement senior notes (the "Opco Senior Notes") with various interest rates and principal due dates. As of June 30, 2017 and December 31, 2016, the Opco Senior Notes had cumulative principal balances of $454.9 million and $503.0 million, respectively. The Opco Senior Notes are guaranteed by all of Opco's wholly owned subsidiaries and are secured by the same collateral as the Opco Credit Facility. Opco made mandatory principal payments of $48.1 million and $48.3 million during the six months ended June 30, 2017 and 2016, respectively.

The Note Purchase Agreements relating to the Opco Senior Notes contain covenants requiring Opco to:


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


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


•	maintain the ratio of consolidated EBITDDA (as defined in the note purchase agreement) to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.

In addition, the Note Purchase Agreements include a covenant that provides that, in the event NRP Operating or any of its subsidiaries is subject to any additional or more restrictive covenants under the agreements governing its material indebtedness (including the Opco Credit Facility and all renewals, amendments or restatements thereof), such covenants shall be deemed to be incorporated by reference in the Note Purchase Agreements and the holders of the Notes shall receive the benefit of such additional or more restrictive covenants to the same extent as the lenders under such material indebtedness agreement.

The 8.38% and 8.92% Opco Senior Notes also provide that in the event that Opco’s leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the Note Purchase Agreements) 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. Opco has not exceeded the 3.75 to 1.00 ratio at the end of any fiscal quarter through June 30, 2017.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

In September 2016, Opco amended the Opco Senior Notes. Under this amendment, Opco agreed to use certain asset sale proceeds to make mandatory prepayment offers on the Opco Senior Notes as follows:


•	until the earlier of the time that (1) Opco has sold $300 million of assets and (2) June 30, 2020, Opco will be required to make prepayment offers to the holders of the Opco Senior Notes using 25% of the net cash proceeds from certain asset sales; and


•	after the earlier to occur of the dates above, Opco will be required to make prepayment offers to the holders of the Opco Senior Notes using an amount of net cash proceeds from certain asset sales that will be calculated pro-rata based on the amount of Opco Senior Notes then outstanding compared to the other total Opco senior debt outstanding that is being prepaid.

The mandatory prepayment offers described above will be made pro-rata across each series of outstanding Opco Senior Notes and will not require any make-whole payment by Opco. In addition, the remaining principal and interest payments on the Opco Senior Notes will be adjusted accordingly based on the amount of Opco Senior Notes actually prepaid. The prepayments do not affect the maturity dates of any series of the Opco Senior Notes.

11. Fair Value Measurements

The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, contracts receivable—affiliate, accounts payable, debt and convertible preferred units. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term nature.

Fair Value—Disclosure Only

The following table (in thousands) shows the carrying amount and estimated fair value of the Partnership's debt and contracts receivable—affiliate:



	June 30, 2017				December 31, 2016
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Debt:
NRP 2018 Senior Notes (1)	$	93,940	$	95,777	$	420,097	$	412,250
NRP 2022 Senior Notes (1)	328,852		369,401		—		—
Opco Senior Notes and utility local improvement obligation (2)	451,361		486,143		500,174		488,814
Opco Revolving Credit Facility (3)	—		—		206,032		210,000

Assets:
Contracts receivable, current and long-term (2)	44,551		30,917		46,742		32,554


(1)	The Level 1 fair value is based upon quotations obtained for identical instruments on the closing trading prices near period end.


(2)	The Level 3 fair value is estimated by management using quotations obtained for comparable instruments on the closing trading prices near period end.


(3)	The Level 3 fair value approximates the outstanding borrowing amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Fair Value—Recurring

The Warrants issued in March 2017 are reported on the Partnership's consolidated balance sheets as a liability at Level 3 fair value using a binomial lattice model under the option pricing method. This model incorporates transaction details such as contractual terms, the Partnership’s common unit price, risk free interest rates, dividend yield and volatility. A significant decrease in the volatility or a significant decrease in the Partnership’s unit price, in isolation, would result in a significantly lower fair value measurement, and vice versa. The binomial lattice model utilized the following assumptions on the following dates (fair value in thousands):



Warrant Valuation Model Key Assumptions	March 2, 2017			June 30, 2017
Closing price of NRP common units	$	41.95		$	27.55
Risk-free interest rate	2.38		%	2.18		%
Expected dividend yield	4.29		%	6.53		%
Expected volatility	45.00		%	50.00		%

The Warrants are recorded as non-current liabilities on the Partnership's consolidated balance sheets. Changes in the estimated fair value of the Warrants result in the recognition of other income or expense. The following table (in thousands) sets forth a summary of the beginning and ending balance sheet amounts and the changes in fair value of the Partnership's Level 3 Warrant liabilities that are measured at fair value on a recurring basis:



	Three Months Ended June 30,					Six Months Ended June 30,
	2017			2016		2017			2016
Beginning balance	$	61,417		$	—	$	—		$	—
Issuance of new Warrants	—			—		77,986			—
Fair value adjustments for Warrant liabilities	(23,960		)	—		(40,529		)	—
Ending balance (1)	$	37,457		$	—	$	37,457		$	—


(1)	During the three and six months ended June 30, 2017, there were no transfers in or out of Level 3 from other levels in the fair value hierarchy.

NRP has embedded derivatives in the Preferred Units related to certain conversion options, redemption features and the change of control provision that are accounted for separately from the Preferred Units as assets and liabilities at fair value in NRP's consolidated balance sheets. Level 3 valuation of the embedded derivatives are based on numerous factors including the likelihood of the event occurring. The embedded derivatives are revalued quarterly, and changes in their fair value would be recorded in other income (expense) in NRP's consolidated statements of comprehensive income. The embedded derivatives had zero value at inception and as of June 30, 2017.

12. Related Party Transactions

Cline Affiliates and Foresight Energy L.P.

Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC ("Adena"), owned a 31% interest in NRP's general partner, as well as approximately 0.5 million of NRP's common units through May 9, 2017. On May 9, 2017, Adena sold its 31% limited partner interest in NRP (GP) LP (the Partnership’s general partner) (“NRP GP”) to Great Northern Properties Limited Partnership (“GNPLP”) and Western Pocahontas Properties Limited Partnership ("WPPLP") (the “Adena Sale”). GNPLP and WPPLP are companies controlled by Corbin J. Robertson, the Chairman and Chief Executive Officer of GP Natural Resource Partners LLC (the general partner of NRP GP) (“GP LLC”). Following the Adena Sale, GNPLP owns a 9.830% limited partner interest in NRP GP, and WPPLP owns a 90.169% limited partner interest in NRP GP. GP LLC continues to own a 0.001% general partner interest in NRP GP. Upon closing of this transaction, NRP no longer considers the various companies affiliated with Chris Cline, including Foresight Energy LP ("Foresight Energy") to be affiliates of NRP. As a result, all transactions (including revenues, expenses and cash flows) after May 9, 2017, with the various companies affiliated with Chris Cline, including Foresight Energy, are considered to be third party transactions.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Various subsidiaries of Foresight Energy lease coal reserves from the Partnership, and the Partnership also leases coal transportation assets to them for a fee. Revenues related to these transactions with Foresight Energy are included in the Partnership's Consolidated Statement of Comprehensive Income as follows (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Coal royalty and other revenue	$	4,789	$	—	$	4,789	$	—
Coal royalty and other—affiliates revenue	11,425		16,935		27,216		27,013
Total	$	16,214	$	16,935	$	32,005	$	27,013

In addition, NRP owns and leases a rail load out facility and owns a contractual overriding royalty interest at Foresight Energy's Sugar Camp mine. NRP's rail load out lease with a subsidiary of Foresight Energy is accounted for as a direct financing lease. NRP's contractual overriding royalty interest from a subsidiary of Foresight Energy provides for payments based upon production from specific tons at Foresight Energy's Sugar Camp operations. This overriding royalty is accounted for as a financing arrangement. Revenues from these transactions are included in coal royalty and other revenues in the table above.

Lastly, NRP owns rail load out transportation assets and subcontracts out the operating responsibilities to a subsidiary of Foresight Energy at Foresight's Williamson mine. Expenses related to these transactions with Foresight Energy are included in the Partnership's Consolidated Statement of Comprehensive Income as follows (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Operating and maintenance expense	$	285	$	—	$	285	$	—
Operating and maintenance expense—affiliates, net	117		201		452		581
Total	$	402	$	201	$	737	$	581

The following table (in thousands) shows certain amounts related to NRP's Sugar Camp rail load out facility direct financing lease and amounts of all NRP's transactions with subsidiaries of Foresight Energy reflected on NRP's Consolidated Balance Sheets:



	June 30,		December 31,
	2017		2016
Sugar Camp rail load out direct financing lease amounts
Projected remaining payments	$	73,958	$	76,424
Unearned income	30,069		31,803

ASSETS
Accounts receivable	$	7,349	$	—
Accounts receivable—affiliates, net	—		6,496
Long-term contracts receivable	41,638		—
Long-term contracts receivable—affiliate	—		43,785
LIABILITIES
Deferred revenue	$	63,997	$	—
Deferred revenue—affiliates	—		71,632

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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 services provided to the Partnership and for expenses incurred on the Partnership’s behalf. Employees of Quintana Minerals Corporation ("QMC") and WPPLP, affiliates of the Partnership, provide their services to manage the Partnership's business. QMC and WPPLP charge the Partnership the portion of their employee salary and benefits costs related to their employee services provided to NRP. These QMC and WPPLP employee management service costs and non-cash equity compensation expenses are presented as Operating and maintenance expenses—affiliates, net and General and administrative—affiliates on the Consolidated Statements of Comprehensive Income. NRP also reimburses overhead costs incurred by its affiliates to manage the Partnership's business. These overhead costs include certain rent, legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by or on behalf of the Partnership’s general partner and its affiliates and are presented as Operating and maintenance expenses—affiliates, net and General and administrative—affiliates on the Consolidated Statements of Comprehensive Income.

The Partnership had Accounts payable—affiliates to QMC of $0.4 million and $0.4 million, including $0.0 million and less than $0.1 million related to discontinued operations at June 30, 2017 and December 31, 2016, respectively, for services provided by QMC to the Partnership. The Partnership had Accounts payable—affiliates to WPPLP of $0.5 million and $0.6 million at June 30, 2017 and December 31, 2016, respectively.

Direct general and administrative expenses charged to the Partnership by WPPLP and QMC are as follows (in thousands):



	Three Months Ended June 30,			Six Months Ended June 30,
	2017	2016		2017	2016
Operating and maintenance expenses—affiliates, net	1,799	2,099	4,774	3,965	4,611
General and administrative—affiliates	852	866		1,976	1,803

Included in loss from discontinued operations are $0.0 million and $0.5 million of operating and maintenance expenses charged by QMC for the three months ended June 30, 2017 and 2016, respectively. Included in loss from discontinued operations are $0.0 million and $0.7 million of operating and maintenance expenses charged by QMC for the six months ended June 30, 2017 and 2016, respectively.

Quintana Capital Group GP, Ltd.

Corbin J. Robertson, Jr. is a principal in Quintana Capital Group GP, Ltd. ("Quintana Capital"), 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, 2017, a fund controlled by Quintana Capital owned a substantial interest in Corsa Coal Corp. ("Corsa"), a coal mining company traded on the TSX Venture Exchange that is one of the Partnership’s lessees in Tennessee. Corbin J. Robertson III, one of the Partnership’s directors, was Chairman of the Board of Corsa through May 10, 2017. Coal related revenues from Corsa totaled $0.4 million and $0.6 million for the three months ended June 30, 2017 and 2016, respectively. Coal related revenues from Corsa totaled $0.7 million and $1.1 million for the six months ended June 30, 2017 and 2016, respectively. As of June 30, 2017 and December 31, 2016 the Partnership had Accounts receivable—affiliates totaling $0.3 million and $0.2 million from Corsa at June 30, 2017 and December 31, 2016, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

WPPLP Production Royalty and Overriding Royalty

During the three months ended June 30, 2017 and 2016, the Partnership recorded $0.3 million and $0.1 million, respectively in Operating and maintenance expenses—affiliates related to a non-participating production royalty payable to WPPLP pursuant to a conveyance agreement entered into in 2007. These charges were $0.4 million and $0.7 million during the six months ended June 30, 2017 and 2016, respectively. The Partnership had Other assets—affiliate from WPPLP of $1.3 million and $1.0 million at June 30, 2017 and December 31, 2016, respectively related to a non-production royalty receivable from WPPLP for overriding royalty interest on a mine.

Quinwood Coal Company Royalty

In May 2017, a subsidiary of Alpha Natural Resources assigned two coal leases with us to Quinwood Coal Company ("Quinwood"), and entity wholly-owned by Corbin J. Robertson III. In connection with this lease assignment, Quinwood forfeited the historical recoupable balance related to this property. As a result, NRP recognized $0.9 million of deferred minimum payments received in prior periods from a subsidiary of Alpha as Coal royalty and other—affiliates revenue during the three and six months ended June 30, 2017.

13. Commitments and Contingencies

Legal

NRP 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.

Anadarko Contingent Consideration Payment Dispute

In January 2013, we acquired a non-controlling 48.51% general partner interest in OCI OCI Wyoming, L.P. ("OCI LP") and all of the preferred stock and a portion of the common stock of OCI Wyoming Co. ("OCI Co") (which in turn owned a 1% limited partner interest in OCI LP) from Anadarko Holding Company and its subsidiary, Big Island Trona Company (together, "Anadarko"). The remaining general partner interest in OCI LP and common stock of OCI Co were owned by subsidiaries of OCI Chemical Corporation.

The acquisition agreement provided for additional contingent consideration of up to $50 million to be paid by us if certain performance criteria were met at OCI LP as defined in the purchase and sale agreement in any of the years 2013, 2014 or 2015. For those years, we paid an aggregate of $11.5 million to Anadarko in full satisfaction of these contingent consideration payment obligations.

In July 2013, pursuant to a series of transactions in connection with an initial public offering by a subsidiary of OCI Chemical Corporation, the ownership structure in OCI LP was simplified. In connection with such reorganization, we exchanged the stock of OCI Co for a limited partner interest in OCI LP. Following the reorganization, our interest in OCI LP increased to 49%, consisting of both limited and general partner interests. The restructuring did not have any impact on the operations, revenues, management or control of OCI LP.

In July 2017, Anadarko filed a lawsuit against Opco and NRP Trona LLC in the District Court of Harris County, Texas, 157th Judicial District, alleging that the transactions conducted in 2013 triggered an acceleration of our obligation under the purchase agreement with Anadarko to pay additional contingent consideration in full and demanded immediate payment of such amount, together with interest, court costs and attorneys’ fees. We do not believe the reorganization transactions triggered an obligation to pay any additional contingent consideration, and we intend to vigorously defend this lawsuit. However, the ultimate outcome cannot be predicted with certainty given the early stage of this matter and we estimate a possible range of loss between $0, if we prevail, and approximately $40 million, plus interest, court costs and attorneys’ fees if Anadarko prevails and is awarded the full damages it seeks.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Foresight Energy Disputes

In November 2015, we filed a lawsuit against Foresight Energy’s subsidiary, Hillsboro Energy LLC ("Hillsboro"), in the Circuit Court of the Fourth Judicial Circuit in Montgomery County, Illinois. The lawsuit alleges, among other items, breach of contract by Hillsboro resulting from a wrongful declaration of force majeure at Hillsboro’s Deer Run mine in July 2015. In late March 2015, elevated carbon monoxide readings were detected at the Deer Run mine, and coal production at the mine was idled. In July 2015, we received the notice declaring a force majeure event at the mine as a result of the elevated carbon monoxide levels. We believe the force majeure claim by Hillsboro has no merit, and we are vigorously pursuing recovery against them. The effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us minimum deficiency payments of $7.5 million per quarter, or $30.0 million per year. Foresight Energy's failure to make the deficiency payment with respect to three quarters of 2015, each quarter of 2016, and the first and second quarters of 2017 has resulted in a cumulative $61.0 million negative cash impact to us. Such amount will increase for each quarter during which mining operations continue to be idled. We do not currently have an estimate as to when the mine will resume coal production. If the mine remains idled for an extended period or if the mine is permanently closed, our financial condition could be adversely affected.

In April 2016, we filed a lawsuit against Macoupin Energy, LLC ("Macoupin"), a subsidiary of Foresight Energy, in Macoupin County, Illinois. The lawsuit alleges that Macoupin has failed to comply with the terms of its coal mining, rail loadout and rail loop leases by incorrectly recouping previously paid minimum royalties. Foresight Energy’s failure to properly calculate its recoupable balance and failure to make payments in accordance with these lease agreements has resulted in a cumulative $8.4 million negative cash impact to us. While the Partnership is pursuing its claim, a valuation allowance for the receivable amount has been recorded.

14. Major Customers

Revenues from customers that exceeded ten percent of total revenues and other income for any of the periods presented below are as follows (in thousands except for percentages):



	Three months ended June 30,								Six months ended June 30,
	2017				2016				2017				2016
	Revenues		Percent		Revenues		Percent		Revenues		Percent		Revenues		Percent
Foresight Energy (1)	$	16,255	17.1	%	$	16,935	14.3	%	$	32,046	17.5	%	$	27,013	12.6	%

(1)Revenues from Foresight Energy are included within the Partnership's Coal Royalty and Other segment.

15. Unit-Based Compensation

GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan in 2008 (the "Long-Term Incentive Plan") for directors of GP Natural Resource Partners LLC and employees of its affiliates who perform services for the Partnership. The compensation committee of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan. Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.

Phantom units are incentive based equity awards issued to employees over a vesting period that entitle the grantee to receive the cash equivalent to the value of a unit of the Parent common units upon each vesting. The Partnership records compensation cost equal to the fair value of the award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. In addition, compensation cost for unvested phantom unit awards is adjusted quarterly for any changes in the Partnership’s unit price. Under the plan a grantee will receive the market value of a common unit in cash upon vesting. Market value is defined as the average closing price over the 20 trading days prior to the vesting date. The compensation committee may make grants under the Long-Term Incentive Plan to employees and directors containing such terms as it determines, including the vesting period. Outstanding grants vest upon a change in control of the Partnership, the general partner, or GP Natural Resource Partners LLC. If a grantee’s employment or membership on the board of directors terminates for any reason, outstanding grants will be automatically forfeited unless and to the extent the compensation committee provides otherwise.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

In connection with the phantom unit awards, the Compensation, Nominating and Governance Committee also granted tandem Distribution Equivalent Rights ("DERs"), which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units between the date the units are granted and the vesting date. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting.

A summary of activity in the outstanding grants during 2017 is as follows (in thousands):



	Phantom Units
Outstanding grants at January 1, 2017	86
Grants vested and paid during the period	(28	)
Forfeitures during the period	(4	)
Outstanding grants at June 30, 2017	54

Grants typically vest at the end of a four-year period and are paid in cash upon vesting. During the three months ended June 30, 2017 the Partnership recorded a credit to G&A expense of $0.2 million due to a decline in NRP's unit price during the period. During the six months ended June 30, 2017 the Partnership had $0.2 million in G&A expense related to its Long-Term Incentive Plan. The Partnership recorded general and administrative expenses related to its Long-Term Incentive Plan of $0.2 million for both the three and six months ended June 30, 2016.

In connection with the Long-Term Incentive Plan, payments are typically made during the first quarter of the year. Payments of $1.8 million and $1.5 million were made during the six months ended June 30, 2017 and 2016, respectively. The unaccrued cost associated with unvested outstanding grants and related DERs at June 30, 2017 and December 31, 2016 was $0.4 million and $0.8 million, respectively.

16. Cash Distributions

The following table shows the distributions paid to common unitholders and the general partner by the Partnership during the six months ended June 30, 2017 and 2016:



				Total Distributions (In thousands)
Date Paid	Period Covered by Distribution	Distribution per Common Unit		Common Units		GP Interest		Total
2017
February 14, 2017	October 1 - December 31, 2016	$	0.45	$	5,503	$	112	$	5,615
May 12, 2017	January 1 - March 31, 2017	$	0.45	$	5,506	$	113	$	5,619

2016
February 12, 2016	October 1 - December 31, 2015	$	0.45	$	5,503	$	113	$	5,616
May 13, 2016	January 1 - March 31, 2016	$	0.45	$	5,503	$	113	$	5,616

The following table shows the distributions paid to preferred unitholders by the Partnership during the six months ended June 30, 2017:



				Total Distributions (In thousands)
Date Paid	Period Covered by Distribution	Distribution per Preferred Unit		Preferred Units
May 30, 2017	March 2 - March 31, 2017	$	5.00	$	1,250

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

17. Deferred Revenue and Deferred Revenue—Affiliate

Most of the Partnership’s coal and aggregates lessees must pay the Partnership minimum annual or quarterly amounts which are generally recoupable out of actual production over certain time periods. These minimum payments are recorded as a deferred revenue liability when received. The deferred revenue attributable to the minimum payment is recognized as revenue based upon the underlying mineral lease when the lessee recoups the minimum payment through production or in the period immediately following the expiration of the lessee’s ability to recoup the payments. The Partnership’s deferred revenue (including affiliate) consists of the following (in thousands):



	June 30, 2017		December 31, 2016
Deferred revenue	$	110,885	$	44,931
Deferred revenue—affiliate	—		71,632
Total deferred revenue (including affiliate)	$	110,885	$	116,563

The Partnership recognized the following amounts of deferred revenue (including affiliate) attributable to previously paid minimums resulting from the expiration of the lessee’s ability to recoup the payments as Coal royalty and other revenue (in thousands):



	Three Months Ended June 30,					Six Months Ended June 30,
	2017			2016		2017			2016
Coal royalty and other	$	(2,070	)	$	38,740	$	(1,312	)	$	44,835
Coal royalty and other—affiliates	9,617			4,787		13,126			5,657
Total coal royalty and other (including affiliates)	$	7,547		$	43,527	$	11,814		$	50,492

Lease Modifications, Termination and Forfeitures of Minimum Royalty Balances

During the three months ended June 30, 2016, the Partnership entered into agreements with certain lessees to either modify or terminate existing coal related leases that resulted in the Partnership recognizing $35 million of deferred revenue as follows:

•

An agreement that terminated a central Appalachia coal royalty lease and resulted in the lessee forfeiting the right to recoup $26.2 million of minimum royalties previously paid to the Partnership. The Partnership agreed to transfer its coal mineral rights that were subject to this former lease to the lessee. This terminated lease had no current or planned production and the mineral rights transferred had zero net book value on the Partnership's consolidated Balance Sheets as of March 31, 2016. As a result of this transaction, in April 2016 the Partnership recognized $26.2 million of revenue.


•	Lease modifications of existing coal royalty leases resulted in lessee forfeiture of rights to recoup previously paid minimum royalties and the reduction in lessee recoupment time. As a result of these modifications, in April 2016 the Partnership recognized approximately $9 million of revenue.

The Partnership recognized a total $36.9 million of revenue from coal and aggregates lease modifications, terminations or forfeitures during the six months ended June 30, 2016. The Partnership recognized $1.0 million and $1.3 million of revenue from coal and aggregates lease modifications, terminations or forfeitures during the three and six months ended June 30, 2017, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

18. Subsequent Events

The following represents material events that have occurred subsequent to June 30, 2017 through the time of the Partnership’s filing of its Quarterly Report on Form 10-Q with the SEC:

Distributions Declared

On July 27, 2017, the Board of Directors of GP Natural Resource Partners LLC declared a distribution of $0.45 per common unit to be paid by the Partnership on August 14, 2017 to common unitholders of record on August 7, 2017. In addition, the Board declared a distribution on NRP's 12.0% Class A Convertible Preferred Units with respect to the period such units were outstanding during the second quarter. One-half of the distribution on the preferred units will be paid-in-kind through the issuance of 3,769 additional Preferred Units.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

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

Such forward-looking statements include, among other things, statements regarding:


•	our business strategy;


•	our liquidity and access to capital and financing sources;


•	our financial strategy;


•	prices of and demand for coal, trona and soda ash, construction aggregates and other natural resources;


•	estimated revenues, expenses and results of operations;


•	the amount, nature and timing of capital expenditures;


•	projected production levels by our lessees and our construction aggregates business


•	Ciner Wyoming LLC’s ("Ciner Wyoming") trona mining and soda ash refinery operations;


•	the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us, and of scheduled or potential regulatory or legal changes; and


•	global and U.S. economic conditions.

These forward-looking statements speak only as of the date hereof and are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and 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. See "Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2016 for important factors that could cause our actual results of operations or our actual financial condition to differ.

As used herein, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries. References to "NRP Oil and Gas" refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP. NRP Finance Corporation ("NRP Finance") is a wholly owned subsidiary of NRP and a co-issuer with NRP on the 2018 and 2022 senior notes.

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our consolidated financial statements and footnotes included elsewhere in this filing. Our discussion and analysis consists of the following subjects:

•Executive Overview

•Results of Operations

•Liquidity and Capital Resources

•Off-Balance Sheet Transactions

•Related Party Transactions

•Recent Accounting Standards

Executive Overview

We are a diversified natural resource company engaged principally in the business of owning, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal, trona and soda ash, construction aggregates and other natural resources. Our common units trade on the New York Stock Exchange under the symbol "NRP".

Our business is organized into three operating segments:

Coal Royalty and Other—consists primarily of coal royalty and coal related transportation and processing assets. Other assets include aggregate royalty, industrial mineral royalty, oil and gas royalty and timber. Our coal reserves are primarily located in Appalachia, the Illinois Basin and the Western United States. Our aggregates and industrial minerals are located in a number of states across the United States. Our oil and gas royalty assets are located in Louisiana.

Soda Ash—consists of our 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. Ciner Resources LP, our operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. We receive regular quarterly distributions from this business.

Construction Aggregates—consists of our construction materials business that operates hard rock quarries, an underground limestone mine, sand and gravel plants, asphalt plants and marine terminals. Our construction aggregates business operates in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.

For the six months ended June 30, 2017, our financial results included (in thousands):



Revenues and other income	$	183,628
Net income from continuing operations	$	66,788
Adjusted EBITDA (1)	$	114,024

Operating cash flow provided by continuing operations	$	55,594
Investing cash flow used in continuing operations	$	669
Financing cash flow provided by continuing operations	$	(55,851	)
Distributable Cash Flow ("DCF") (1)	$	56,877


(1)	See "—Results of Operations" below for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures.

Debt Reduction and 2017 Recapitalization Transactions

During the first quarter of 2017, we completed the recapitalization transactions that improved our liquidity and strengthened our balance sheet. For more information on these transactions, see Note 2. “Convertible Preferred Units and Warrants” and Note 10. “Debt” in the Notes to Consolidated Financial Statements” included elsewhere in this report. We used a portion of the proceeds from these transactions to repay Opco’s revolving credit facility in full and pay all fees and expenses associated with the recapitalization transactions. On April 3, 2017, we redeemed $90 million in aggregate principal amount of the 2018 Senior Notes at a redemption price of 104.563%, and paid all accrued and unpaid interest thereon. In addition, we plan to redeem all remaining outstanding 2018 Senior Notes in October 2017 at par, and we anticipate using cash on hand and available borrowings under Opco's Credit Facility for that purpose. As of June 30, 2017, we had reduced our debt by approximately $244.1 million from December 31, 2016 and extended the majority of our 2018 debt maturities to 2020 and 2022. We remain focused on further reducing our debt and improving our credit metrics in order to ultimately reposition the Partnership for long-term growth.

Current Results/Market Commentary

Coal Royalty and Other Business Segment

For the six months ended June 30, 2017, our Coal Royalty and Other business segment financial results included the following (in thousands):



Revenues and other income	$	103,977
Net income from continuing operations	$	77,178
Adjusted EBITDA (1)	$	91,304

Operating cash flow provided by continuing operations	$	76,469
Investing cash flow provided by continuing operations	$	2,894
Financing cash flow provided by continuing operations	$	33
DCF (1)	$	79,363


(1)	See "—Results of Operations" below for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures.

We derived approximately 60% of our coal royalty revenues and approximately 45% of the related production from metallurgical coal during the six months ended June 30, 2017. NRP continued to benefit from higher metallurgical coal prices compared to 2016, with substantially increased price realizations in Central and Southern Appalachia. While metallurgical coal prices have retreated in 2017 from the peaks reached in the fourth quarter of 2016 and early in the second quarter of 2017, they remained significantly higher than in the comparable period in 2016. Notably, very few tons were sold at the peak of the market, as buyers generally elected to stay out of the market anticipating a short-term price spike. Most recently, met coal prices have increased approximately $20 per metric ton since mid-June as a result of global supply disruptions and increased imports into China. As the market has rebounded, the supply has increased as well, indicating that the recent price increases may not be viable over the long-term.

Appalachian thermal coal prices have also improved over the prior year as inventories have come down significantly, in part due to production cuts over the last two years. Normal summer weather and natural gas prices that continue to remain around $3/mcf have combined to reduce inventories at the end of May to approximately 100 days of supply, down from over 130 days of supply at the end of May 2016. Despite these improvements, producers of Central Appalachian thermal coal continue to face challenges, as many still have large debt burdens and their production costs remain high relative to sales prices. While increased supply has pressured coal from our low cost Illinois Basin properties, stronger export demand in 2017 has helped to maintain prices and sales volumes.

Soda Ash Business Segment

For the six months ended June 30, 2017, our Soda Ash business segment financial results included the following (in thousands):



Revenues and other income	$	18,683
Net income from continuing operations	$	18,683
Adjusted EBITDA (1)	$	24,500

Operating cash flow provided by continuing operations	$	22,112
Investing cash flow provided by continuing operations	$	2,388
DCF (1)	$	24,500


(1)	See "—Results of Operations" below for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures.

During the second quarter, international prices for soda ash, particularly in Asia, continued to be strong, and domestic prices have improved slightly over last year. Income from our trona mining and soda ash refinery investment was lower in the six months ended June 30, 2017 compared to the prior year primarily as a result of lower production output and higher maintenance expenses compared to the prior period.

Ciner Resources LP, our partner that controls and operates Ciner Wyoming, is a publicly traded master limited partnership that depends on distributions from Ciner Wyoming in order to make distributions to its public unitholders.

Construction Aggregates Business Segment

For the six months ended June 30, 2017, our construction aggregates business segment financial results included the following (in thousands):



Revenues and other income	$	60,968
Net income from continuing operations	$	1,097
Adjusted EBITDA (1)	$	8,219

Operating cash flow provided by continuing operations	$	9,522
Investing cash flow used in continuing operations	$	(4,613	)
Financing cash flow used in continuing operations	$	(1,096	)
DCF (1)	$	5,523


(1)	See "—Results of Operations" below for additional information regarding non-GAAP financial measures and reconciliations to the most comparable GAAP financial measures.

Our construction aggregates mining and production business is largely dependent on the strength of the local markets that it serves. The business is also seasonal, with lower production and sales during the first quarter of each year. Although our construction aggregates production and revenues increased on a consolidated basis in the six months ended June 30, 2017 compared to the same period in 2016, weaker pricing due to diminished natural gas drilling in the Marcellus and the lack of infrastructure spending in West Virginia, as well as cutbacks in military spending in the Clarksville market, resulted in lower margins and earnings at those operations. While the Louisiana aggregates market has improved over the course of the summer, operating results were negatively impacted by significant rainfall in the second quarter.

Discontinued Operations

In July 2016, NRP Oil and Gas closed on the sale of its non-operated oil and gas working interest assets in the Williston Basin for $116.1 million in gross sales proceeds. Our exit from our non-operated oil and gas working interest business represented a strategic shift to reduce debt and focus on our soda ash, coal royalty and construction aggregates business segments. As a result, we have classified the assets and liabilities, operating results and cash flows of our non-operated oil and gas working interest assets as discontinued operations in our consolidated financial statements for all periods presented.

Results of Operations

Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016

Revenues and Other Income

Revenues and other income decreased $23.3 million, or 20%, from $118.2 million in the three months ended June 30, 2016 to $94.9 million in the three months ended June 30, 2017. The following table shows our diversified sources of natural resource revenues and other income by business segment for the three months ended June 30, 2017 and 2016 (in thousands except for percentages):



	Coal Royalty and Other			Soda Ash			Construction Aggregates			Total
June 30, 2017
Revenues and other income	$	52,810		$	8,389		$	33,732		$	94,931
Percentage of total	55		%	9		%	36		%
June 30, 2016
Revenues and other income	$	76,407		$	10,188		$	31,651		$	118,246
Percentage of total	64		%	9		%	27		%

The changes in revenue and other income is discussed for each of our business segments below:

Coal Royalty and Other

Revenues and other income related to our Coal Royalty and Other segment decreased $23.6 million, or 31%, from $76.4 million in the three months ended June 30, 2016 to $52.8 million in the three months ended June 30, 2017. The table below presents coal production and coal royalty revenues (including affiliates) derived from our major coal producing regions and the significant categories of other coal royalty and other revenues:



	For the Three Months Ended June 30,					Increase (Decrease)			Percentage Change
	2017		2016			Increase (Decrease)			Percentage Change
	(In thousands, except percent and per ton data) (Unaudited)
Coal production (tons)
Appalachia
Northern (1)	247		(138		)	385			279	%
Central	3,897		3,470			427			12	%
Southern	690		773			(83		)	(11	)%
Total Appalachia	4,834		4,105			729			18	%
Illinois Basin	734		1,909			(1,175		)	(62	)%
Northern Powder River Basin	910		442			468			106	%
Total coal production	6,478		6,456			22			—	%

Coal royalty revenue per ton
Appalachia
Northern (1)	$	3.78	$	2.08		1.70			82	%
Central	5.05		3.13			1.92			61	%
Southern	5.69		3.36			2.33			69	%
Illinois Basin	4.06		3.76			0.30			8	%
Northern Powder River Basin	2.62		3.05			(0.43		)	(14	)%

Coal royalty revenues
Appalachia
Northern (1)	$	933	$	463		$	470		102	%
Central	19,691		10,864			8,827			81	%
Southern	3,927		2,598			1,329			51	%
Total Appalachia	24,551		13,925			10,626			76	%
Illinois Basin	2,978		7,181			(4,203		)	(59	)%
Northern Powder River Basin	2,384		1,348			1,036			77	%
Total coal royalty revenue	$	29,913	$	22,454		$	7,459		33	%

Other revenues
Minimums recognized as revenue	$	7,547	$	43,527		$	(35,980	)	(83	)%
Transportation and processing fees	5,520		5,302			218			4	%
Property tax revenue	1,100		3,027			(1,927		)	(64	)%
Wheelage	1,025		465			560			120	%
Coal override revenue	1,885		657			1,228			187	%
Hard mineral royalty revenues	1,452		603			849			141	%
Oil and gas royalty revenues	924		1,091			(167		)	(15	)%
Other	260		361			(101		)	(28	)%
Total other revenues	$	19,713	$	55,033		$	(35,320	)	(64	)%
Coal royalty and other income	49,626		77,487			(27,861		)	(36	)%
Gain (loss) on coal royalty and other segment asset sales	3,184		(1,080		)	4,264			395	%
Total coal royalty and other segment revenues and other income	$	52,810	$	76,407		$	(23,597	)	(31	)%

(1)Northern Appalachia was impacted by a prior period adjustment in 2016 of 0.4 million tons and less than $0.1 million in royalty revenue related to the Hibbs Run mine that temporarily ceased production during 2016. Absent this adjustment, production in the Northern Appalachia region was 0.2 million tons with revenue of $0.4 million. Coal royalty revenue per ton removes the impact of the Hibbs Run prior period adjustment.

Total coal production remained flat in the three months ended June 30, 2017 as compared to the three months June 30, 2016. Total coal royalty revenues increased $7.5 million, or 33%, from $22.5 million in the three months ended June 30, 2016 to $29.9 million in the three months ended June 30, 2017. Coal royalty revenue increased in Central Appalachia as a result of an increase in prices and production in the second quarter of 2017 as compared to the second quarter of 2016. Despite decreased production, coal royalty revenue in Southern Appalachia increased in the second quarter of 2017 as compared to the second quarter of 2016 as a result of higher coal prices. Conversely, the increase in production led to higher revenue in the Northern Powder River Basin

quarter-over-quarter despite a decrease in coal prices. Lower production in the Illinois Basin led to the decrease in coal royalty revenue in the region in the second quarter of 2017 as compared to the second quarter of 2016, despite the modest increase in prices in the region. The lower Illinois Basin production was primarily a result of production at the Williamson mine moving off NRP's coal reserves. However, this decrease in coal royalty revenue was partially offset by NRP's overriding royalty interest from this production that increased the Partnership's overriding royalty revenue compared to the prior period.

Total other revenues decreased $35.3 million in the three months ended June 30, 2017 compared to the three months ended June 30, 2016 primarily as a result of minimums recognized as revenue due to second quarter 2016 lease modifications and terminations. In addition, the decrease in other revenues resulted from decreased property tax reimbursements that were fully offset by lower property tax expenses as described in operating and maintenance expenses below. These decreases in revenue were partially offset by increased coal override revenue from the Williamson mine as described above, increased wheelage revenue and increased hard mineral royalty revenues.

Gain on coal royalty and other segment asset sales increased $4.3 million, from a loss of $1.1 million in the three months ended June 30, 2016 to a gain of $3.2 million in the three months ended June 30, 2017. Asset sale gains during the three months ended June 30, 2017 related to the sales of aggregates royalty properties, while the loss recorded in the three months ended June 30, 2016 resulted from purchase price adjustments to a first quarter 2016 oil and gas royalty sale.

Soda Ash

Revenues and other income related to our equity investment in Ciner Wyoming decreased $1.8 million, or 18%, from $10.2 million in the three months ended June 30, 2016 to $8.4 million in the three months ended June 30, 2017. This decrease is primarily related to lower production output and higher maintenance expenses compared to the prior period.

Construction Aggregates

Revenues and other income related to our construction aggregates segment increased $2.0 million, or 6%, from $31.7 million in the three months ended June 30, 2016 to $33.7 million in the three months ended June 30, 2017. This increase is primarily due to higher production and sales quarter-over-quarter.

Operating and Maintenance Expenses (including affiliates)

Operating and maintenance expenses (including affiliates) increased $1.0 million, or 3%, from $32.2 million in the three months ended June 30, 2016 to $33.2 million in the three months ended June 30, 2017. This increase is primarily related to the following:

Construction Aggregates

Operating and maintenance expenses (including affiliates) in our construction aggregates segment increased $3.3 million, or 13% from $24.5 million in the three months ended June 30, 2016 to $27.8 million in the three months ended June 30, 2017. This increase is primarily related to higher materials costs driven by the increase in production.

This increase in operating and maintenance expenses (including affiliates) was partially offset by:

Coal Royalty and Other

Operating and maintenance expenses (including affiliates) in our Coal Royalty and Other segment decreased $2.3 million, or 30% from $7.7 million in the three months ended June 30, 2016 to $5.4 million in the three months ended June 30, 2017. This decrease is primarily related to decreased property tax expense.

Depreciation, Depletion and Amortization ("DD&A") Expense

DD&A expense decreased $2.8 million, or 25%, from $11.2 million in three months ended June 30, 2016 to $8.4 million in three months ended June 30, 2017. This decrease is primarily driven by lower coal production in the Illinois Basin.

General and Administrative (including affiliates) ("G&A") Expense

Corporate and financing G&A expense (including affiliates) includes corporate headquarters, financing and centralized treasury and accounting. These costs decreased $1.1 million, or 28%, from $4.0 million in the three months ended June 30, 2016 to $2.9 million in the three months ended June 30, 2017. This decrease is primarily due to lower consulting and advisory fees following the completion of the recapitalization transactions in March 2017 and decreased LTIP expense.

Loss on Extinguishment of Debt

Loss on extinguishment of debt was $4.1 million for the three months ended June 30, 2017 and related to the 4.563% premium paid to redeem the 2018 Senior Notes in April 2017.

Fair Value Adjustments for Warrant Liabilities

Fair value adjustments for warrant liabilities was $24.0 million for the three months ended June 30, 2017 and related to the change in fair value of the warrants during the period.

Income from Discontinued Operations

Income from discontinued operations increased $2.3 million, or 105%, from a loss of $2.2 million in the three months ended June 30, 2016 to income of $0.1 million in the three months ended June 30, 2017. The increase is primarily a result of costs incurred in the three months ended June 30, 2016 related to the non-operated oil and gas working interest business that we sold in July 2016.

Adjusted EBITDA (Non-GAAP Financial Measure)

Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) from continuing operations less equity earnings from unconsolidated investment, fair value adjustments for warrant liabilities and income to non-controlling interest; plus distributions from unconsolidated investment, interest expense, debt modification expense, loss on extinguishment of debt, warrant issuance expense, depreciation, depletion and amortization and asset impairments.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring items that materially affect our net income (loss), the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by different companies. In addition, Adjusted EBITDA presented below is not calculated or presented on the same basis as Consolidated EBITDA as defined in our partnership agreement.

Adjusted EBITDA is a supplemental performance measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis.

The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment for the three months ended June 30, 2017 and 2016:



	Operating Segments
For the Three Months Ended	Coal Royalty and Other		Soda Ash			Construction Aggregates		Corporate and Financing			Total
June 30, 2017
Net income (loss) from continuing operations	$	42,084	$	8,389		$	2,636	$	(3,292	)	$	49,817
Less: equity earnings from unconsolidated investment	—		(8,389		)	—		—			(8,389		)
Less: fair value adjustments for warrant liabilities	—		—			—		(23,960		)	(23,960		)
Add: distributions from unconsolidated investment	—		12,250			—		—			12,250
Add: interest expense	—		—			178		20,199			20,377
Add: debt modification expense	—		—			—		132			132
Add: loss on extinguishment of debt	—		—			—		4,107			4,107
Add: warrant issuance expense	—		—			—		—			—
Add: depreciation, depletion and amortization	5,375		—			3,030		—			8,405
Add: asset impairments	—		—			—		—			—
Adjusted EBITDA	$	47,459	$	12,250		$	5,844	$	(2,814	)	$	62,739

June 30, 2016
Net income (loss) from continuing operations	$	61,153	$	10,188		$	3,439	$	(26,147	)	$	48,633
Less: equity earnings from unconsolidated investment	—		(10,188		)	—		—			(10,188		)
Add: distributions from unconsolidated investment	—		9,800			—		—			9,800
Add: interest expense	—		—			—		22,115			22,115
Add: depreciation, depletion and amortization	7,486		—			3,690		—			11,176
Add: asset impairments	91		—			—		—			91
Adjusted EBITDA	$	68,730	$	9,800		$	7,129	$	(4,032	)	$	81,627

Adjusted EBITDA decreased $18.9 million, or 23%, from $81.6 million in the three months ended June 30, 2016 to $62.7 million in the three months ended June 30, 2017. The decrease is primarily a result of one-time lease modifications and terminations recorded in the second quarter of 2016, partially offset by higher coal royalty revenues, increased cash distributions from Ciner Wyoming and lower consulting and advisory G&A costs quarter-over-quarter.

Distributable Cash Flow (Non-GAAP Financial Measure)

Our Distributable Cash Flow ("DCF") represents net cash provided by (used in) operating activities of continuing operations, plus returns of equity from unconsolidated investment, proceeds from sales of assets, including those included in discontinued operations, and return on long-term contract receivables (including affiliate); less maintenance capital expenditures and distributions to non-controlling interest. DCF 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. DCF may not be calculated the same for us as for other companies. In addition, DCF presented below is not calculated or presented on the same basis as Distributable Cash Flow as defined in our partnership agreement, which is used as a metric to determine whether we are able to increase quarterly distributions to our common unitholders. DCF is a supplemental liquidity measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess the Partnership's ability to make cash distributions to our common and preferred unitholders and our general partner and repay debt.

The following table (in thousands) presents the three major categories of the statement of cash flows by business segment for the three months ended June 30, 2017 and 2016:



	Operating Segments
For the Three Months Ended	Coal Royalty and Other		Soda Ash		Construction Aggregates			Corporate and Financing			Total
June 30, 2017
Net cash provided by (used in) operating activities of continuing operations	$	38,537	$	9,862	$	5,476		$	(18,770	)	$	35,105
Net cash provided by (used in) investing activities of continuing operations	2,888		2,388		(2,539		)	—			$	2,737
Net cash provided by (used in) financing activities of continuing operations	17		—		(1,000		)	(109,021		)	$	(110,004	)

June 30, 2016
Net cash provided by (used in) operating activities of continuing operations	$	34,814	$	9,800	$	6,210		$	(34,866	)	$	15,958
Net cash provided by (used in) investing activities of continuing operations	4,184		—		(2,472		)	—			1,712
Net cash used in financing activities of continuing operations	—		—		(793		)	(46,105		)	(46,898		)

The following table (in thousands) reconciles net cash provided by operating activities (the most comparable GAAP financial measure) by business segment to DCF for the three months ended June 30, 2017 and 2016:



	Operating Segments
For the Three Months Ended	Coal Royalty and Other		Soda Ash		Construction Aggregates			Corporate and Financing			Total
June 30, 2017
Net cash provided by (used in) operating activities of continuing operations	$	38,537	$	9,862	$	5,476		$	(18,770	)	$	35,105
Add: return of equity from unconsolidated investment	—		2,388		—			—			2,388
Add: proceeds from sale of PP&E	—		—		363			—			363
Add: proceeds from sale of mineral rights	1,292		—		—			—			1,292
Add: return on long-term contract receivables (including affiliate)	1,597		—		—			—			1,597
Less: maintenance capital expenditures	—		—		(2,415		)	—			(2,415		)
Distributable Cash Flow	$	41,426	$	12,250	$	3,424		$	(18,770	)	$	38,330

June 30, 2016
Net cash provided by (used in) operating activities of continuing operations	$	34,814	$	9,800	$	6,210		$	(34,866	)	$	15,958
Add: proceeds from sale of PP&E	819		—		21			—			840
Add: proceeds from sale of mineral rights	1,499		—		—			—			1,499
Add: return on long-term contract receivables—affiliate	1,871		—		—			—			1,871
Less: maintenance capital expenditures	—		—		(2,079		)	—			(2,079		)
Distributable Cash Flow	$	39,003	$	9,800	$	4,152		$	(34,866	)	$	18,089

DCF increased $20.2 million, or 112%, from $18.1 million in the three months ended June 30, 2016 to $38.3 million in the three months ended June 30, 2017. This increase is due primarily to lower cash paid for interest quarter-over-quarter. Interest payments on our 2018 Senior Notes are historically paid in the second quarter, but were paid in the first quarter of 2017 in connection with the March 2017 extension of the 2018 Senior Notes. Cash paid for interest was also lower in the second quarter of 2017 as compared to the same period in 2016 due to lower debt balances period-over-period. Also contributing to an increase in DCF are higher distributions received from Ciner Wyoming and an increase in coal segment royalty revenue during the three months ended June 30, 2017 as compared to the same period in 2016.

Results of Operations

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Revenues and Other Income

Revenues and other income decreased $30.5 million, or 14%, from $214.1 million in the six months ended June 30, 2016 to $183.6 million in the six months ended June 30, 2017. The following table shows our diversified sources of natural resource revenues and other income by business segment for the six months ended June 30, 2017 and 2016 (in thousands except for percentages):



	Coal Royalty and Other			Soda Ash			Construction Aggregates			Total
June 30, 2017
Revenues and other income	$	103,977		$	18,683		$	60,968		$	183,628
Percentage of total	57		%	10		%	33		%
June 30, 2016
Revenues and other income	$	137,751		$	19,989		$	56,333		$	214,073
Percentage of total	65		%	9		%	26		%

The changes in revenue and other income is discussed for each of our business segments below:

Coal Royalty and Other

Revenues and other income related to our Coal Royalty and Other segment decreased $33.8 million, or 25%, from $137.8 million in the six months ended June 30, 2016 to $104.0 million in the six months ended June 30, 2017. The table below presents coal production and coal royalty revenues (including affiliates) derived from our major coal producing regions and the significant categories of other coal royalty and other revenues:



	For the Six Months Ended June 30,				Increase (Decrease)			Percentage Change
	2017		2016		Increase (Decrease)			Percentage Change
	(In thousands, except percent and per ton data) (Unaudited)
Coal production (tons)
Appalachia
Northern	1,454		1,292		162			13	%
Central	7,597		6,698		899			13	%
Southern	1,253		1,518		(265		)	(17	)%
Total Appalachia	10,304		9,508		796			8	%
Illinois Basin	2,751		3,637		(886		)	(24	)%
Northern Powder River Basin	1,859		1,416		443			31	%
Total coal production	14,914		14,561		353			2	%

Coal royalty revenue per ton
Appalachia
Northern	$	1.06	$	1.27	$	(0.21	)	(17	)%
Central	5.25		3.19		2.06			65	%
Southern	6.03		3.16		2.87			91	%
Illinois Basin	3.50		3.54		(0.04		)	(1	)%
Northern Powder River Basin	2.63		2.82		(0.19		)	(7	)%

Coal royalty revenues
Appalachia
Northern	$	1,540	$	1,635	$	(95	)	(6	)%
Central	39,875		21,337		18,538			87	%
Southern	7,559		4,800		2,759			57	%
Total Appalachia	48,974		27,772		21,202			76	%
Illinois Basin	9,624		12,867		(3,243		)	(25	)%
Northern Powder River Basin	4,882		4,000		882			22	%
Total coal royalty revenue	$	63,480	$	44,639	$	18,841		42	%

Other revenues
Minimums recognized as revenue	$	12,743	$	50,492	$	(37,749	)	(75	)%
Transportation and processing fees	10,159		9,536		623			7	%
Property tax revenue	3,798		6,332		(2,534		)	(40	)%
Wheelage	2,292		878		1,414			161	%
Coal override revenue	2,709		867		1,842			212	%
Hard mineral royalty revenues	2,696		1,494		1,202			80	%
Oil and gas royalty revenues	2,415		1,464		951			65	%
Other	472		1,204		(732		)	(61	)%
Total other revenues	$	37,284	$	72,267	$	(34,983	)	(48	)%
Coal royalty and other income	100,764		116,906		(16,142		)	(14	)%
Gain on coal royalty and other segment asset sales	3,213		20,845		(17,632		)	(85	)%
Total coal royalty and other segment revenues and other income	$	103,977	$	137,751	$	(33,774	)	(25	)%

Total coal production increased 0.4 million tons, or 2%, from 14.6 million tons in the six months ended June 30, 2016 to 14.9 million tons in the six months ended June 30, 2017. Total coal royalty revenues increased $18.8 million, or 42%, from $44.6 million in the six months ended June 30, 2016 to $63.5 million in the six months ended June 30, 2017. Coal royalty revenue increased in Central Appalachia primarily due to an increase in prices in the first half of 2017 as compared to the first half of 2016. Despite decreased production, coal royalty revenue in Southern Appalachia increased in the first half of 2017 as compared to the first half of 2016 as a result of higher coal prices. Conversely, the increase in production led to higher revenue in the Northern Powder River Basin compared to the first six months of 2016 despite a decrease in coal prices. Lower production in the Illinois Basin led to the decrease in coal royalty revenue in the region in the first half of 2017 as compared to the first half of 2016, despite the fact that the prices remained relatively flat year-over-year. The lower Illinois Basin production was primarily a result of production at the Williamson mine moving off NRP's coal reserves. However, this decrease in coal royalty revenue was partially offset by NRP's overriding royalty interest from this production that increased the Partnership's overriding royalty revenue compared to the prior period.

Total other revenues decreased $35.0 million in the six months ended June 30, 2017 compared to the six months ended June 30, 2016 primarily as a result of a decrease in minimums recognized as revenue due to the second quarter 2016 lease modifications and terminations in addition to lower property tax reimbursements, partially offset by increased coal override revenue from the Williamson mine as described above, wheelage revenue and hard mineral royalty revenues.

Gain on coal royalty and other segment asset sales decreased $17.6 million year-over-year primarily as a result of the following asset sales during the first half of 2016:

1)Oil and gas royalty and overriding royalty interests in several producing properties located in the Appalachian Basin for $36.4 million gross sales proceeds. The effective date of the sale was January 1, 2016, and we recorded a $19.2 million gain from this sale.

2)Aggregate reserves and related royalty rights in the Coal Royalty and Other segment at three aggregates operations located in Texas, Georgia and Tennessee for $10.0 million gross sales proceeds. The effective date of the sale was February 1, 2016, and we recorded a $1.6 million gain from this sale.

Gain on coal royalty and other segment asset sales during the six months ended June 30, 2017 included sales of aggregates royalty properties and condemnation payments for a total gain of $3.2 million.

Construction Aggregates

Revenues and other income related to our construction aggregates segment increased $4.7 million, or 8%, from $56.3 million in the six months ended June 30, 2016 to $61.0 million in the six months ended June 30, 2017. This increase is primarily due to higher production and sales.

Soda Ash

Revenues and other income related to our equity investment in Ciner Wyoming decreased $1.3 million, or 7%, from $20.0 million in the six months ended June 30, 2016 to $18.7 million in the six months ended June 30, 2017. This decrease is primarily related to lower production output and higher maintenance expenses compared to the prior period.

Operating and Maintenance Expenses (including affiliates)

Operating and maintenance expenses (including affiliates) increased $2.9 million, or 5%, from $62.5 million in the six months ended June 30, 2016 to $65.4 million in the six months ended June 30, 2017. This increase is primarily related to the following:

Construction Aggregates

Operating and maintenance expenses (including affiliates) in our construction aggregates segment increased $6.0 million, or 13% from $46.6 million in the six months ended June 30, 2016 to $52.6 million in the six months ended June 30, 2017. This increase is primarily related to an increase in materials and labor costs due to the increase in production and sales as discussed above.

This increase in operating and maintenance expenses (including affiliates) was partially offset by:

Coal Royalty and Other

Operating and maintenance expenses (including affiliates) in our Coal Royalty and Other segment decreased $3.0 million, or 19% from $15.8 million in the six months ended June 30, 2016 to $12.8 million in the six months ended June 30, 2017. This decrease is primarily related to decreased property tax expense.

Depreciation, Depletion and Amortization ("DD&A") Expense

DD&A expense decreased $2.8 million, or 13%, from $21.7 million in six months ended June 30, 2016 to $18.9 million in six months ended June 30, 2017. This decrease is primarily driven by lower coal production in the Illinois Basin.

General and Administrative (including affiliates) ("G&A") Expense

Corporate and financing G&A expense (including affiliates) includes corporate headquarters, financing and centralized treasury and accounting. These costs increased $1.9 million, or 23%, from $8.2 million in the six months ended June 30, 2016 to $10.1 million in the six months ended June 30, 2017. This increase is primarily due to additional LTIP expense as a result of performance-based awards that vested following the completion of the March 2017 recapitalization transactions.

Debt Modification Expense

Debt modification expense was $7.9 million for the six months ended June 30, 2017 and related to costs incurred as a result of the exchange of $241 million of our 2018 Senior Notes for 2022 Senior Notes.

Loss on Extinguishment of Debt

Loss on extinguishment of debt was $4.1 million for the six months ended June 30, 2017 and related to the 4.563% premium paid to redeem the 2018 Senior Notes in April 2017.

Warrant Issuance Expense

Warrant issuance expense was $5.7 million for the six months ended June 30, 2017 and related to the costs incurred resulting from issuance of the warrants.

Fair Value Adjustments for Warrant Liabilities

Fair value adjustments for warrant liabilities was $40.5 million for the six months ended June 30, 2017 and related to the change in fair value of the warrants during the period.

Loss from Discontinued Operations

Loss from discontinued operations decreased $5.0 million, or 98%, from a loss of $5.1 million in the six months ended June 30, 2016 to a loss of $0.1 million in the six months ended June 30, 2017. The decrease in loss is primarily a result of costs incurred in the six months ended June 30, 2016 related to the non-operated oil and gas working interest business that we sold in July 2016.

Adjusted EBITDA (Non-GAAP Financial Measure)



	Operating Segments
For the Six Months Ended	Coal Royalty and Other		Soda Ash			Construction Aggregates		Corporate and Financing			Total
June 30, 2017
Net income (loss) from continuing operations	$	77,178	$	18,683		$	1,097	$	(30,170	)	$	66,788
Less: equity earnings from unconsolidated investment	—		(18,683		)	—		—			(18,683		)
Less: fair value adjustments for warrant liabilities	—		—			—		(40,529		)	(40,529		)
Add: distributions from unconsolidated investment	—		24,500			—		—			24,500
Add: interest expense	—		—			573		42,945			43,518
Add: debt modification expense	—		—			—		7,939			7,939
Add: loss on extinguishment of debt	—		—			—		4,107			4,107
Add: warrant issuance expense	—		—			—		5,709			5,709
Add: depreciation, depletion and amortization	12,348		—			6,549		—			18,897
Add: asset impairments	1,778		—			—		—			1,778
Adjusted EBITDA	$	91,304	$	24,500		$	8,219	$	(9,999	)	$	114,024

June 30, 2016
Net income (loss) from continuing operations	$	105,552	$	19,989		$	2,402	$	(52,959	)	$	74,984
Less: equity earnings from unconsolidated investment	—		(19,989		)	—		—			(19,989		)
Add: distributions from unconsolidated investment	—		22,050			—		—			22,050
Add: interest expense	—		—			—		44,774			44,774
Add: depreciation, depletion and amortization	14,426		—			7,252		—			21,678
Add: asset impairments	1,984		—			—		—			1,984
Adjusted EBITDA	$	121,962	$	22,050		$	9,654	$	(8,185	)	$	145,481

Adjusted EBITDA decreased $31.5 million, or 22%, from $145.5 million in the six months ended June 30, 2016 to $114.0 million in the six months ended June 30, 2017. The decrease is primarily a result of the asset sale gains recorded in the first quarter of 2016 and one-time lease modifications and terminations recorded in the second quarter of 2016, partially offset by higher coal royalty revenues year-over-year. See "—Results of Operations—Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016" for an explanation of Adjusted EBITDA.

Distributable Cash Flow (Non-GAAP Financial Measure)

The following table (in thousands) presents the three major categories of the statement of cash flows by business segment for the six months ended June 30, 2017 and 2016:



	Operating Segments
For the Six Months Ended	Coal Royalty and Other		Soda Ash			Construction Aggregates			Corporate and Financing			Total
June 30, 2017
Net cash provided by (used in) operating activities of continuing operations	$	76,469	$	22,112		$	9,522		$	(52,509	)	$	55,594
Net cash provided by (used in) investing activities of continuing operations	2,894		2,388			(4,613		)	—			669
Net cash provided by (used in) financing activities of continuing operations	33		—			(1,096		)	(54,788		)	(55,851		)

June 30, 2016
Net cash provided by (used in) operating activities of continuing operations	$	56,375	$	22,050		$	12,323		$	(52,102	)	$	38,646
Net cash provided by (used in) investing activities of continuing operations	47,143		—			(3,890		)	—			43,253
Net cash used in financing activities of continuing operations	—		(7,232		)	(1,593		)	(92,887		)	(101,712		)

The following table (in thousands) reconciles net cash provided by operating activities (the most comparable GAAP financial measure) by business segment to DCF for the six months ended June 30, 2017 and 2016:



	Operating Segments
For the Six Months Ended	Coal Royalty and Other		Soda Ash		Construction Aggregates			Corporate and Financing			Total
June 30, 2017
Net cash provided by (used in) operating activities of continuing operations	$	76,469	$	22,112	$	9,522		$	(52,509	)	$	55,594
Add: return of equity from unconsolidated investment	—		2,388		—			—			2,388
Add: proceeds from sale of PP&E	—		—		385			—			385
Add: proceeds from sale of mineral rights	883		—		—			—			883
Add: return on long-term contract receivables (including affiliate)	2,011		—		—			—			2,011
Less: maintenance capital expenditures	—		—		(4,384		)	—			(4,384		)
Distributable Cash Flow	$	79,363	$	24,500	$	5,523		$	(52,509	)	$	56,877

June 30, 2016
Net cash provided by (used in) operating activities of continuing operations	$	56,375	$	22,050	$	12,323		$	(52,102	)	$	38,646
Add: proceeds from sale of PP&E	819		—		24			—			843
Add: proceeds from sale of mineral rights	44,149		—		—			—			44,149
Add: return on long-term contract receivables—affiliate	2,180		—		—			—			2,180
Less: maintenance capital expenditures	—		—		(3,329		)	—			(3,329		)
Distributable Cash Flow	$	103,523	$	22,050	$	9,018		$	(52,102	)	$	82,489

DCF decreased $25.6 million, or 31%, from $82.5 million in the six months ended June 30, 2016 to $56.9 million in the six months ended June 30, 2017. This decrease is due primarily to the $44.1 million in asset sales proceeds received in the first quarter of 2016, partially offset by an increase in cash provided by operating activities in our Coal Royalty and Other segment as a result of the increase in revenues discussed above. See "—Results of Operations—Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016" for an explanation of Distributable Cash Flow.

Liquidity and Capital Resources

Current Liquidity

As of June 30, 2017, we had a total of $40.8 million of cash and cash equivalents in addition to $180.0 million in borrowing capacity under our Opco Credit Facility. During the six months ended June 30, 2017, we reduced our debt by approximately $244.1 million by repaying $210.0 million of the Opco Credit Facility in full, redeeming $90.0 million of our 2018 Senior Notes, repaying $48.1 million of the Opco Private Placement Notes (as defined below) and repaying $0.2 million on the Opco utility local improvement obligation. In addition, the remaining balance of Opco's utility local improvement obligation was transfered as part of the sale of the underlying aggregates property during the second quarter of 2017. These repayments were partially offset by the issuance of $105.0 million of 2022 Notes (in addition to the $241 million of 2022 Notes issued in exchange for $241 million of 2018 Notes). In addition, we plan to redeem the remaining outstanding 2018 Senior Notes in October 2017 using cash on hand and borrowings under the Opco Credit Facility.

The March 2017 recapitalization transactions increased our liquidity and extended the majority of our 2018 debt maturities to 2020 and 2022. Even with these meaningful improvements to our liquidity and balance sheet, we continue to have substantial debt outstanding and intend to continue to use cash from operations to deleverage our balance sheet over time. While we have a diversified portfolio of assets, we face challenges in coal and other commodity markets. However, we expect that we will meet all of our obligations, including scheduled principal and interest payments on our debt and required distributions on the preferred units and remain in compliance with all covenants contained in our debt agreements within one year after the issuance date of these financial statements.

Capital Expenditures

A portion of the capital expenditures associated with our construction aggregates segment are maintenance capital expenditures, which are capital expenditures made to maintain the long-term production capacity of those businesses. Expansion capital expenditures are made to increase productive capacity. We deduct maintenance capital expenditures when calculating DCF.

Cash Flows

Cash flow provided by operating activities increased $10.6 million, from $44.5 million in the six months ended June 30, 2016 to $55.1 million in the six months ended June 30, 2017. Operating cash flow from continuing operations increased $17.0 million primarily as a result of increased cash flows provided by operating activities within our Coal Royalty and Other segment as a result of an increase in coal royalty revenues period-over-period. Cash flows from discontinued operations decreased $6.3 million year-over-year primarily as a result of completing the sale of our non-operating oil and gas working interest assets in July 2016 that had an effective date of April 1, 2016.

Cash flow provided by investing activities decreased $38.5 million, from $39.4 million in the six months ended June 30, 2016 to $0.9 million in the six months ended June 30, 2017. Investing cash flows from discontinued operations increased $4.0 million primarily as a result of capital expenditures made in 2016 on our non-operated working interest assets that were sold in July 2016. Investing cash flows from continuing operations decreased $42.6 million primarily as a result of the proceeds received in 2016 from the sales of our oil and gas and aggregates royalty properties.

Cash flows used in financing activities decreased $56.8 million, from $112.3 million in the six months ended June 30, 2016 to $55.5 million in the six months ended June 30, 2017. This decrease in cash flow used is primarily due to the proceeds received from the issuance of convertible preferred units and warrants and 2022 Senior Notes. These proceeds were partially offset by additional debt repayments year-over-year and the fees paid related to the March 2017 recapitalization transactions.

Capital Resources and Obligations

Indebtedness

As of June 30, 2017 and December 31, 2016, we had the following indebtedness (in thousands):



	June 30, 2017		December 31, 2016
Current portion of long-term debt, net	$	173,901	$	138,903
Long-term debt, net	700,252		987,400
Total debt, net	$	874,153	$	1,126,303

We were and continue to be in compliance with the terms of the financial covenants contained in our debt agreements. For additional information regarding our debt and the agreements governing our debt, including the covenants contained therein, see Note 10. Debt to the consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q.

Shelf Registration Statements

In September 2015, we filed a registration statement on Form S-3 with the SEC that is available for registered offerings of common units. In April 2017, we filed a shelf registration statement on Form S-3 with the SEC to register the common units issuable upon conversion of the warrants, as described above.

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

The information required set forth under Note 12. Related Party Transactions to the consolidated financial statements is incorporated herein by reference.

Summary of Critical Accounting Estimates

The preparation of consolidated financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. There have been no significant changes to our critical accounting estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.

Recent Accounting Standards

The information set forth under Note 1. Basis of Presentation to the consolidated financial statements is incorporated herein by reference.

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 of the coal mined by our lessees. Our lessees sell the coal under various long-term and short-term contracts as well as on the spot market. Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts with terms of one year or more. Our lessees’ failure to negotiate long-term contracts could adversely affect the stability and profitability of our lessees’ operations and adversely affect our coal royalty revenues. If more coal is sold on the spot market, coal royalty revenues may become more volatile due to fluctuations in spot coal prices.

We have market risk related to prices for our aggregates products. Aggregates prices are primarily driven by economic conditions in the local markets in which the products are sold.

The market price of soda ash directly affects the profitability of Ciner Wyoming’s operations. If the market price for soda ash declines, Ciner Wyoming’s sales will decrease. Historically, the global market and, to a lesser extent, the domestic market for soda ash have been volatile, and those markets are likely to remain volatile in the future.

Interest Rate Risk

Our exposure to changes in interest rates results from our borrowings under the Opco Credit Facility, which is subject to variable interest rates based upon LIBOR. At June 30, 2017, we did not have any borrowings outstanding under the Opco Credit Facility.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure 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.

Changes in the Partnership’s Internal Control Over Financial Reporting

There were no changes in the Partnership’s internal control over financial reporting during the first six months of 2017 that materially affected, or were reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

PART II

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, we believe these claims will not have a material effect on our financial position, liquidity or operations.

For more information regarding certain other legal proceedings involving the Partnership, including the lawsuits involving Anadarko and Foresight, see Note 13. Commitments and Contingencies to the consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q, which is incorporated herein by reference.

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 Annual Report on Form 10-K for the year ended December 31, 2016.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

The information concerning mine safety violations or other regulatory matters required by SEC regulations is included in Exhibit 95.1 to this Quarterly Report on Form 10-Q.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS



Exhibit Number		Description
2.1		Purchase Agreement, dated as of January 23, 2013, by and among Anadarko Holding Company, Big Island Trona Company, NRP Trona LLC and NRP (Operating) LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on January 25, 2013).
2.2		Purchase and Sale Agreement dated as of June 13, 2016 by and between NRP Oil and Gas LLC and Lime Rock Resources IV-A, L.P (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on June 15, 2016).
3.1		Fifth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of March 2, 2017 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on March 6, 2017).
3.2		Fifth Amended and Restated Agreement of Limited Partnership of NRP (GP) LP, dated as of December 16, 2011 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on December 16, 2011).
3.3		Fifth Amended and Restated Limited Liability Company Agreement of GP Natural Resource Partners LLC, dated as of October 31, 2013 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on October 31, 2013).
3.4		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).
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.
95.1*		Mine Safety Disclosure.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

*		Filed herewith
**		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 8, 2017
	By:	/s/ CORBIN J. ROBERTSON, JR.
		Corbin J. Robertson, Jr.
		Chairman of the Board and
		Chief Executive Officer
		(Principal Executive Officer)



Date: August 8, 2017
	By:	/s/ CHRISTOPHER J. ZOLAS
		Christopher J. Zolas
		Chief Financial Officer and Treasurer
		(Principal Financial and Accounting Officer)