NATURAL RESOURCE PARTNERS LP - Quarter Report: 2017 September (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 September 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 November 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	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	52
Part II. Other Information
Item 1.	Legal Proceedings	53
Item 1A.	Risk Factors	53
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
Item 3.	Defaults Upon Senior Securities	53
Item 4.	Mine Safety Disclosure	53
Item 5.	Other Information	53
Item 6.	Exhibits	54
	Signatures	55

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)



	September 30,			December 31,
	2017			2016
ASSETS
Current assets:
Cash and cash equivalents	$	121,244		$	40,371
Accounts receivable, net	48,788			43,202
Accounts receivable—affiliates, net	243			6,658
Inventory	7,671			6,893
Prepaid expenses and other	7,525			7,271
Current assets of discontinued operations (see Note 7)	991			991
Total current assets	186,462			105,386
Land	25,261			25,252
Plant and equipment, net	47,584			49,443
Mineral rights, net	890,610			908,192
Intangible assets, net	50,370			3,236
Intangible assets, net—affiliate	—			49,811
Equity in unconsolidated investment	245,382			255,901
Long-term contracts receivable	41,211			—
Long-term contracts receivable—affiliate	—			43,785
Other assets	7,741			6,625
Other assets—affiliate	892			1,018
Total assets	$	1,495,513		$	1,448,649
LIABILITIES AND CAPITAL
Current liabilities:
Accounts payable	$	5,812		$	6,234
Accounts payable—affiliates	670			940
Accrued liabilities	28,659			41,587
Current portion of long-term debt, net	174,138			140,037
Current liabilities of discontinued operations (see Note 7)	458			353
Total current liabilities	209,737			189,151
Deferred revenue	106,391			44,931
Deferred revenue—affiliates	—			71,632
Long-term debt, net	762,441			990,234
Other non-current liabilities	2,727			4,565
Total liabilities	1,081,296			1,300,513
Commitments and contingencies (see Note 15)
Convertible Preferred Units (255,019 units issued and outstanding at $1,000 par value per unit; liquidation preference of $1,500 per unit)	169,606			—
Partners’ capital:
Common unitholders’ interest (12,232,006 units issued and outstanding)	182,760			152,309
General partner’s interest	1,508			887
Warrant holders interest	66,816			—
Accumulated other comprehensive loss	(3,079		)	(1,666		)
Total partners’ capital	248,005			151,530
Non-controlling interest	(3,394		)	(3,394		)
Total capital	244,611			148,136
Total liabilities and capital	$	1,495,513		$	1,448,649

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues and other income:
Coal royalty and other	$	49,078		$	27,504		$	120,986		$	116,336
Coal royalty and other—affiliates	335			21,434			29,191			49,508
Construction aggregates	34,710			31,757			95,486			88,081
Equity in earnings of Ciner Wyoming	8,993			10,753			27,676			30,742
Gain (loss) on asset sales, net	171			6,426			3,576			27,280
Total revenues and other income	$	93,287		$	97,874		$	276,915		$	311,947

Operating expenses:
Operating and maintenance expenses	$	32,441		$	31,242		$	93,089		$	87,824
Operating and maintenance expenses—affiliates, net	2,154			4,062			6,928			9,948
Depreciation, depletion and amortization	8,306			11,929			26,195			32,181
Amortization expense—affiliate	—			902			1,008			2,328
General and administrative	2,648			4,268			10,757			10,676
General and administrative—affiliates	1,207			867			3,183			2,670
Asset impairments	—			5,697			1,778			7,681
Total operating expenses	$	46,756		$	58,967		$	142,938		$	153,308

Income from operations	$	46,531		$	38,907		$	133,977		$	158,639

Other income (expense)
Interest expense	$	(20,080	)	$	(22,491	)	$	(63,598	)	$	(66,742	)
Interest expense—affiliate	—			—			—			(523		)
Debt modification expense	—			—			(7,939		)	—
Loss on extinguishment of debt	—			—			(4,107		)	—
Interest income	48			3			134			29
Other expense, net	$	(20,032	)	$	(22,488	)	$	(75,510	)	$	(67,236	)

Net income from continuing operations	$	26,499		$	16,419		$	58,467		$	91,403
Income (loss) from discontinued operations (see Note 7)	(433		)	7,112			(507		)	2,001
Net income	$	26,066		$	23,531		$	57,960		$	93,404
Less: income attributable to preferred unitholders	(7,650		)	—			(17,688		)	—
Net income attributable to common unitholders and general partner	$	18,416		$	23,531		$	40,272		$	93,404

Income from continuing operations per common unit (see Note 5)
Basic	$	1.51		$	1.32		$	3.27		$	7.34
Diluted	$	1.08		$	1.32		$	2.67		$	7.34

Net income per common unit (see Note 5)
Basic	$	1.48		$	1.89		$	3.23		$	7.50
Diluted	$	1.07		$	1.89		$	2.65		$	7.50

Net income	$	26,066		$	23,531		$	57,960		$	93,404
Add: comprehensive income (loss) from unconsolidated investment and other	(268		)	(609		)	(1,413		)	(692		)
Comprehensive income	$	25,798		$	22,922		$	56,547		$	92,712

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			Warrant Holders		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⁾	—	56,801			1,159			—		—			57,960			—			57,960
Distributions to common unitholders and general partner	—	(16,513		)	(337		)	—		—			(16,850		)	—			(16,850		)
Distributions to preferred unitholders	—	(9,837		)	(201		)	—		—			(10,038		)	—			(10,038		)
Issuance of Warrants	—	—			—			66,816		—			66,816			—			66,816
Comprehensive loss from unconsolidated investment and other	—	—			—			—		(1,413		)	(1,413		)	—			(1,413		)
Balance at September 30, 2017	12,232	$	182,760		$	1,508		$	66,816	$	(3,079	)	$	248,005		$	(3,394	)	$	244,611


(1)	Net income includes $17.7 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)



	Nine Months Ended September 30,
	2017			2016
Cash flows from operating activities:
Net income	$	57,960		$	93,404
Adjustments to reconcile net income to net cash provided by operating activities of continuing operations:
Depreciation, depletion and amortization	26,195			32,181
Amortization expense—affiliates	1,008			2,328
Return on earnings from unconsolidated investment	31,104			34,300
Equity earnings from unconsolidated investment	(27,676		)	(30,742		)
Gain on asset sales, net	(3,576		)	(27,280		)
Debt modification expense	7,939			—
Loss on extinguishment of debt	4,107			—
Gain (loss) from discontinued operations	507			(2,001		)
Asset impairments	1,778			7,681
Amortization of debt issuance costs and other	5,459			6,694
Other, net—affiliates	88			848
Change in operating assets and liabilities:
Accounts receivable	1,607			(341		)
Accounts receivable—affiliates	(777		)	(712		)
Accounts payable	730			635
Accounts payable—affiliates	(270		)	29
Accrued liabilities	(12,452		)	7,287
Accrued liabilities—affiliates	—			(456		)
Deferred revenue	(5		)	(40,762		)
Deferred revenue—affiliates	(10,166		)	(8,190		)
Other items, net	(2,166		)	(356		)
Net cash provided by operating activities of continuing operations	$	81,394		$	74,547
Net cash provided by (used in) operating activities of discontinued operations	(607		)	8,173
Net cash provided by operating activities	$	80,787		$	82,720

Cash flows from investing activities:
Return of equity from unconsolidated investment	$	5,646		$	—
Proceeds from sale of assets	1,419			55,364
Return of long-term contract receivables	1,807			—
Return of long-term contract receivables—affiliate	804			2,577
Acquisition of plant and equipment and other	(6,236		)	(4,431		)
Net cash provided by investing activities of continuing operations	$	3,440		$	53,510
Net cash provided by investing activities of discontinued operations	206			106,821
Net cash provided by investing activities	$	3,646		$	160,331

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	69,000			20,000
Repayments of loans	(356,292		)	(106,174		)
Distributions to common unitholders and general partner	(16,850		)	(16,849		)
Distributions to preferred unitholders	(5,019		)	—
Proceeds from (contributions to) discontinued operations	(401		)	40,226
Debt issue costs and other	(40,187		)	(14,072		)
Net cash used in financing activities of continuing operations	$	(3,961	)	$	(76,869	)
Net cash provided by (used in) financing activities of discontinued operations	401			(125,564		)
Net cash used in financing activities	$	(3,560	)	$	(202,433	)

Net increase in cash and cash equivalents	$	80,873		$	40,618

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	$	121,244		$	92,391
Less: cash and cash equivalents of discontinued operations at end of period	—			—
Cash and cash equivalents of continuing operations at end of period	$	121,244		$	92,391

Supplemental cash flow information:
Cash paid during the period for interest from continuing operations	$	61,857		$	54,749
Cash paid during the period for interest from discontinued operations	$	—		$	1,906
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.

Recently Adopted 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 and early adoption is permitted. The Partnership early adopted this guidance in the third quarter of 2017. Refer to Note 2. Change in Method of Accounting for NRP's Warrants for disclosure of the effects of adoption on its consolidated financial statements.

Recently Issued Accounting Standards

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 for its various segments. The Partnership anticipates utilizing the modified retrospective adoption method.

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

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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. Change in Method of Accounting for NRP's Warrants

On March 2, 2017, NRP issued 4.0 million warrants (the "Warrants") to purchase common units as described in further detail in Note 3. Convertible Preferred Units and Warrants. As of March 31, 2017 and June 30, 2017, the Warrants were accounted for on the Partnership's consolidated balance sheet as a liability because of a down-round anti-dilution price protection provision that would reduce the Warrant holders' strike price if the Partnership were to sell common units at a price less than the current strike price (subject to certain exceptions). Upon issuance, the Warrants were initially recognized at a fair value of $78.0 million. As a result of the liability classification, the Warrants were remeasured at March 31, 2017 and June 30, 2017, and the change in the estimated fair value of the Warrants resulted in the recognition of $16.6 million other income during the three months ended March 31, 2017 and $24.0 million and $40.5 million other income during the three and six months ended June 30, 2017, respectively. In addition, Warrant transaction costs of $5.7 million were expensed during the three months ended March 31, 2017.

As referenced in Note 1. Basis of Presentation, the Partnership adopted the FASB's new accounting standard for financial instruments with down-round features because the accounting more appropriately reflects the economics of the down-round feature and to remove unnecessary income statement volatility resulting from the period end remeasurement associated with changes in value of NRP's unit price. As a result of the adoption of this guidance, the Warrants are now accounted for on the Partnership's consolidated balance sheet as equity because they are indexed to NRP's common units and they meet all other equity classification requirements. As of September 30, 2017, the Warrants and the associated issuance costs have been reclassified and are presented within the Partners' Capital section of the Partnership's Consolidated Balance Sheet at their initial fair value, net of issuance costs. The Partnership will recognize the value of the effect of the down-round feature in the Warrants each time it is triggered. When triggered, the effect of the down-round feature will be treated as a deemed dividend and would reduce the income available to common unitholders for computing basic earnings per unit.

The Partnership applied the guidance retrospectively to the Warrants for each prior reporting period presented. As a result, first and second quarter 2017 financial statements have been adjusted to apply the new method retrospectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The following table (in thousands) shows the effect of the change in method of accounting for the Warrants on the Partnership's originally reported Consolidated Balance Sheet at March 31, 2017:



	March 31, 2017
	As Originally Reported			As Adjusted			Effect of Change
Total assets	$	1,509,250		$	1,509,250		$	—

Total current liabilities	$	305,049		$	305,049		$	—
Deferred revenue	46,008			46,008			—
Deferred revenue—affiliates	68,735			68,735			—
Long-term debt, net	707,424			707,424			—
Warrant liabilities	61,417			—			(61,417		)
Other non-current liabilities	3,102			3,102			—
Total liabilities	1,191,735			1,130,318			(61,417		)

Convertible Preferred Units	159,292			164,753			5,461

Partners' capital:
Common unitholders' interest	163,304			152,661			(10,643		)
General partner's interest	1,111			894			(217		)
Warrant holders interest	—			66,816			66,816
Accumulated other comprehensive loss	(2,798		)	(2,798		)	—
Total partners' capital	161,617			217,573			55,956
Non-controlling interest	(3,394		)	(3,394		)	—
Total capital	158,223			214,179			55,956
Total liabilities and capital	$	1,509,250		$	1,509,250		$	—

The following table (in thousands) shows the effect of the change in method of accounting for the Warrants on the Partnership's originally reported Consolidated Balance Sheet at June 30, 2017:



	June 30, 2017
	As Originally Reported			As Adjusted			Effect of Change
Total assets	$	1,429,052		$	1,429,052		$	—

Total current liabilities	$	217,411		$	217,411		$	—
Deferred revenue	110,885			110,885			—
Long-term debt, net	700,252			700,252			—
Warrant liabilities	37,457			—			(37,457		)
Other non-current liabilities	2,699			2,699			—
Total liabilities	1,068,704			1,031,247			(37,457		)

Convertible Preferred Units	160,377			165,838			5,461

Partners' capital:
Common unitholders' interest	204,230			170,106			(34,124		)
General partner's interest	1,946			1,250			(696		)
Warrant holders interest	—			66,816			66,816
Accumulated other comprehensive loss	(2,811		)	(2,811		)	—
Total partners' capital	203,365			235,361			31,996
Non-controlling interest	(3,394		)	(3,394		)	—
Total capital	199,971			231,967			31,996
Total liabilities and capital	$	1,429,052		$	1,429,052		$	—

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The following table (in thousands, except per unit data) shows the effect of the change in method of accounting for the Warrants on the Partnership's originally reported Consolidated Statement of Comprehensive Income for the three months ended March 31, 2017:



	Three Months Ended March 31, 2017
	As Originally Reported			As Adjusted			Effect of Change
Other income (expense)
Interest expense	$	(23,141	)	$	(23,141	)	$	—
Debt modification expense	(7,807		)	(7,807		)	—
Warrant issuance expense	(5,709		)	—			5,709
Fair value adjustments for warrant liabilities	16,569			—			(16,569		)
Interest income	17			17			—
Other expense, net	$	(20,071	)	$	(30,931	)	$	(10,860	)

Net income from continuing operations	$	16,971		$	6,111		$	(10,860	)
Net income	16,764			5,904			(10,860		)
Net income attributable to common unitholders and general partner	14,264			3,404			(10,860		)

Income from continuing operations per common unit
Basic	$	1.17		$	0.30		$	(0.87	)
Diluted	0.03			0.30			0.27

Net income per common unit
Basic	$	1.15		$	0.28		$	(0.87	)
Diluted	0.02			0.28			0.26

Comprehensive income	$	15,632		$	4,772		$	(10,860	)



	Three Months Ended June 30, 2017
	As Originally Reported			As Adjusted			Effect of Change
Other income (expense)
Interest expense	$	(20,377	)	$	(20,377	)	$	—
Debt modification expense	(132		)	(132		)	—
Loss on extinguishment of debt	(4,107		)	(4,107		)	—
Fair value adjustments for warrant liabilities	23,960			—			(23,960		)
Interest income	69			69			—
Other expense, net	$	(587	)	$	(24,547	)	$	(23,960	)

Net income from continuing operations	$	49,817		$	25,857		$	(23,960	)
Net income	49,950			25,990			(23,960		)
Net income attributable to common unitholders and general partner	42,412			18,452			(23,960		)

Income from continuing operations per common unit
Basic	$	3.38		$	1.46		$	(1.92	)
Diluted	1.13			1.13			—

Net income per common unit
Basic	$	3.39		$	1.47		$	(1.92	)
Diluted	1.13			1.13			—

Comprehensive income	$	49,937		$	25,977		$	(23,960	)

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)



	Six Months Ended June 30, 2017
	As Originally Reported			As Adjusted			Effect of Change
Other income (expense)
Interest expense	$	(43,518	)	$	(43,518	)	$	—
Debt modification expense	(7,939		)	(7,939		)	—
Loss on extinguishment of debt	(4,107		)	(4,107		)	—
Warrant issuance expense	(5,709		)	—			5,709
Fair value adjustments for warrant liabilities	40,529			—			(40,529		)
Interest income	86			86			—
Other expense, net	$	(20,658	)	$	(55,478	)	$	(34,820	)

Net income from continuing operations	$	66,788		$	31,968		$	(34,820	)
Net income	66,714			31,894			(34,820		)
Net income attributable to common unitholders and general partner	56,676			21,856			(34,820		)

Income from continuing operations per common unit
Basic	$	4.55		$	1.76		$	(2.79	)
Diluted	1.35			1.64			0.29

Net income per common unit
Basic	$	4.54		$	1.75		$	(2.79	)
Diluted	1.34			1.64			0.30

Comprehensive income	$	65,569		$	30,749		$	(34,820	)

3. 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

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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 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 equity. Prior to July 1, 2017, the Warrants were previously classified as a liability because of a "down-round" anti-dilution price protection provision that would reduce the Warrant holders' exercise price if NRP were to sell common units at a price less than the current strike price (subject to certain exceptions). Refer to Note 2. Change in Method of Accounting for NRP's Warrants for further discussion of the reclassification of the Warrants in the Consolidated Balance sheet.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Initial Measurement

The net transaction price as shown below was allocated to the Preferred Units and Warrants based on their relative fair values at inception date. 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 as follows (in thousands):



	March 2, 2017
Transaction price, gross	$	250,000
Structuring, origination and other fees to Preferred Purchasers	(7,900		)
Transaction costs to other third parties	(10,697		)
Transaction price, net	$	231,403
Allocation of net transaction price
Preferred Units, net	$	164,587
Warrant holders interest, net	66,816
Transaction price, net	$	231,403

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 Units can first be converted or redeemed.

Subsequent adjustment of the Warrants will not occur until the Warrants are exercised, at which time, NRP may, at its option, elect to settle the Warrants in common units or cash, each on a net basis. The net basis will be equal to the difference between the Partnership's common unit price and the strike price of the Warrant. Once Warrant exercise occurs, the difference between the carrying amount of the Warrants and the net settlement amount will be allocated on a pro-rata basis to the common unitholders and general partner.

Certain embedded features within the Preferred Unit and Warrant purchase agreement are accounted for at fair value and are remeasured each quarter. See Note 13. Fair Value Measurements for further information regarding valuation of these embedded derivatives.

4. Common and Preferred Unit Distributions

The Partnership makes cash distributions to common unit holders on a quarterly basis, subject to approval by the Board of Directors. The Partnership also makes distributions to the preferred unitholders 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"), subject to approval by the Board of Directors. NRP recognizes both Common and Preferred Unit distributions on the date the distribution is declared.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Common Unit Distributions

The following table shows the cash distributions paid to common unitholders and the general partner by the Partnership during the nine months ended September 30, 2017 and 2016 (in thousands except unit unit data):



				Total Distributions
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
August 14, 2017	April 1 - June 30, 2017	$	0.45	$	5,504	$	112	$	5,616

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
August 12, 2016	April 1 - June 30, 2016	$	0.45	$	5,505	$	112	$	5,617

Preferred Unit Distributions

The following table shows the cash and paid-in-kind distributions declared and paid to Preferred Unitholders by the Partnership during the nine months ended September 30, 2017 (in thousands except per unit data):



Date Paid	Period Covered by Distribution	Distribution per Preferred Unit		Paid-in-Kind Preferred Units	Cash Distributions		Total Distribution Declared
May 30, 2017	March 2 - March 31, 2017	$	5.00	1,250	$	1,250	$	2,500
August 29, 2017	April 1 - June 30, 2017	$	15.00	3,769	3,769		7,538
				5,019	$	5,019	$	10,038

The following table shows the financial position of the Preferred Units from initial measurement at March 2, 2017 to September 30, 2017 (in thousands):



Balance at December 31, 2016	$	—
Issuance of Preferred Units, net	164,587
Distribution paid-in-kind	5,019
Balance at September 30, 2017	$	169,606

Income available to common unitholders and the general partner is reduced by Preferred Unit distributions that accumulated during the period. During the three and nine months ended September 30, 2017, NRP reduced net income attributable to common unitholders and the general partner by $7.7 million and $17.7 million, respectively, as a result of accumulated Preferred Unit distributions.

5. 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 3. Convertible Preferred Units and Warrants), if the inclusion of these items is dilutive.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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 nine months ended September 30, 2017, did not include the net settlement of Warrants to purchase 2.25 million 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 net income per unit 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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The following table reconciles net income and weighted average units used in computing basic and diluted net income per common unit is as follows (in thousands, except per unit data):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2017			2016		2017			2016
Allocation of net income:
Net income from continuing operations	$	26,499		$	16,419	$	58,467		$	91,403
Less: income attributable to preferred unitholders	7,650			—		17,688			—
Less: net income from continuing operations and income attributable to preferred unitholders allocated to the general partner	379			264		816			1,632
Net income from continuing operations attributable to common unitholders	$	18,470		$	16,155	$	39,963		$	89,771

Net income (loss) from discontinued operations	$	(433	)	$	7,112	$	(507	)	$	2,001
Less: net income (loss) from discontinued operations attributable to the general partner	(9		)	142		(10		)	40
Net income (loss) from discontinued operations attributable to common unitholders	$	(424	)	$	6,970	$	(497	)	$	1,961

Net income	$	26,066		$	23,531	$	57,960		$	93,404
Less: income attributable to preferred unitholders	7,650			—		17,688			—
Less: net income and income attributable to preferred unitholders allocated to the general partner	370			406		806			1,672
Net income attributable to common unitholders	$	18,046		$	23,125	$	39,466		$	91,732

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	$	1.51		$	1.32	$	3.27		$	7.34
Basic net income (loss) from discontinued operations per common unit	(0.03		)	0.57		(0.04		)	0.16
Basic net income per common unit	$	1.48		$	1.89	$	3.23		$	7.50

Diluted Income (Loss) per Unit:
Weighted average common units—basic	12,232			12,232		12,232			12,232
Plus: dilutive effect of Warrants	225			—		330			—
Plus: dilutive effect of Preferred Units	11,523			—		8,909			—
Weighted average common units—diluted	23,980			12,232		21,471			12,232

Net income from continuing operations	$	26,499		$	16,419	$	58,467		$	91,403
Less: net income from continuing operations allocated to the general partner	530			264		1,169			1,632
Diluted net income from continuing operations attributable to common unitholders	$	25,969		$	16,155	$	57,298		$	89,771

Diluted net income (loss) from discontinued operations attributable to common unitholders	$	(424	)	$	6,970	$	(497	)	$	1,961

Net income	$	26,066		$	23,531	$	57,960		$	93,404
Less: net income allocated to the general partner	521			406		1,159			1,672
Diluted net income attributable to common unitholders	$	25,545		$	23,125	$	56,801		$	91,732

Diluted net income from continuing operations per common unit	$	1.08		$	1.32	$	2.67		$	7.34
Diluted net income (loss) from discontinued operations per common unit	(0.02		)	0.57		(0.02		)	0.16
Diluted net income per common unit	$	1.07		$	1.89	$	2.65		$	7.50

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

6. 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
September 30, 2017
Revenues (including affiliates)	$	49,413	$	8,993	$	34,710		$	—		$	93,116
Intersegment revenues (expenses)	78		—		(78		)	—			—
Gain on asset sales	154		—		17			—			171
Operating and maintenance expenses (including affiliates)	6,348		—		28,247			—			34,595
General and administrative (including affiliates)	—		—		—			3,855			3,855
Depreciation, depletion and amortization (including affiliates)	5,305		—		3,001			—			8,306
Asset impairment	—		—		—			—			—
Other expense, net	—		—		59			19,973			20,032
Net income (loss) from continuing operations	37,992		8,993		3,342			(23,828		)	26,499
Net income from discontinued operations	—		—		—			—			(433		)

September 30, 2016
Revenues (including affiliates)	$	48,938	$	10,753	$	31,757		$	—		$	91,448
Intersegment revenues (expenses)	45		—		(45		)	—			—
Gain on asset sales	6,425		—		1			—			6,426
Operating and maintenance expenses (including affiliates)	8,391		—		26,913			—			35,304
General and administrative (including affiliates)	—		—		—			5,135			5,135
Depreciation, depletion and amortization (including affiliates)	9,070		—		3,761			—			12,831
Asset impairment	5,697		—		—			—			5,697
Other expense, net	—		—		—			22,488			22,488
Net income (loss) from continuing operations	32,250		10,753		1,039			(27,623		)	16,419
Net loss from discontinued operations	—		—		—			—			7,112

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)



	Operating Segments
For the Nine Months Ended	Coal Royalty and Other		Soda Ash		Construction Aggregates			Corporate and Financing			Total
September 30, 2017
Revenues (including affiliates)	$	150,177	$	27,676	$	95,486		$	—		$	273,339
Intersegment revenues (expenses)	208		—		(208		)	—			—
Gain on asset sales	3,367		—		209			—			3,576
Operating and maintenance expenses (including affiliates)	19,151		—		80,866			—			100,017
General and administrative (including affiliates)	—		—		—			13,940			13,940
Depreciation, depletion and amortization (including affiliates)	17,653		—		9,550			—			27,203
Asset impairment	1,778		—		—			—			1,778
Other expense, net	—		—		632			74,878			75,510
Net income (loss) from continuing operations	115,170		27,676		4,439			(88,818		)	58,467
Net loss from discontinued operations	—		—		—			—			(507		)

September 30, 2016
Revenues (including affiliates)	$	165,844	$	30,742	$	88,081		$	—		$	284,667
Intersegment revenues (expenses)	97		—		(97		)	—			—
Gain on asset sales	27,270		—		10			—			27,280
Operating and maintenance expenses (including affiliates)	24,232		—		73,540			—			97,772
General and administrative (including affiliates)	—		—		—			13,346			13,346
Depreciation, depletion and amortization (including affiliates)	23,496		—		11,013			—			34,509
Asset impairment	7,681		—		—			—			7,681
Other expense, net	—		—		—			67,236			67,236
Net income (loss) from continuing operations	137,802		30,742		3,441			(80,582		)	91,403
Net loss from discontinued operations	—		—		—			—			2,001

Total assets at September 30, 2017:
Continuing operations	$	952,415	$	245,382	$	190,818		$	105,907		$	1,494,522
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

7. 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues and other income:
Oil and gas	$	16		$	41		$	38		$	16,476
Gain (loss) on asset sales	(346		)	8,468			(289		)	8,284
Total revenues and other income	$	(330	)	$	8,509		$	(251	)	$	24,760

Operating expenses:
Operating and maintenance expenses (including affiliates)	$	103		$	928		$	256		$	11,180
Depreciation, depletion and amortization	—			—			—			7,527
Asset impairments	—			—			—			564
Total operating expenses	$	103		$	928		$	256		$	19,271

Interest expense	—			(469		)	—			(3,488		)
Income (loss) from discontinued operations	$	(433	)	$	7,112		$	(507	)	$	2,001

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



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

Current liabilities:
Other (including affiliates)⁽¹⁾	$	458	$	353
Total liabilities of discontinued operations	$	458	$	353


(1)	See Note 14. 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:



	Nine Months Ended September 30,
	2017		2016
Cash paid for interest	$	—	$	1,906

Capital expenditures related to the Partnership's discontinued operations were $3.1 million during the nine months ended September 30, 2016.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

8. Equity Investment

The Partnership accounts for its 49% investment in Ciner Wyoming using the equity method of accounting. Ciner Wyoming distributed $36.8 million and $34.3 million to the Partnership in the nine months ended September 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 $146.7 million and $150.0 million as of September 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Income allocation to NRP’s equity interests	$	10,171		$	11,973		$	30,925		$	34,357
Amortization of basis difference	(1,178		)	(1,220		)	(3,249		)	(3,615		)
Equity in earnings of unconsolidated investment	$	8,993		$	10,753		$	27,676		$	30,742

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Sales	$	122,575	$	121,003	$	368,885	$	352,085
Gross profit	27,872		30,673		80,788		87,656
Net Income	20,758		24,436		63,112		70,118

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



	September 30,		December 31,
	2017		2016
Current assets	$	168,154	$	134,616
Non-current assets	227,772		235,427
Current liabilities	48,821		55,396
Non-current liabilities	145,719		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 2016, 2015 and 2014, the Partnership paid contingent consideration of $7.2 million, $3.8 million, and $0.5 million respectively, in contingent consideration to Anadarko for performance criteria met by Ciner Wyoming in 2015, 2014 and 2013, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

9. Plant and Equipment

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



	September 30,			December 31,
	2017			2016
Plant and equipment at cost	$	83,808		$	79,171
Construction in process	640			557
Less accumulated depreciation	(36,864		)	(30,285		)
Total plant and equipment, net	$	47,584		$	49,443

Depreciation expense related to the Partnership's plant and equipment totaled $2.4 million and $3.1 million for the three months ended September 30, 2017 and 2016, respectively. Depreciation expense related to the Partnership's plant and equipment totaled $7.8 million and $9.5 million for the nine months ended September 30, 2017 and 2016, respectively.

10. Mineral Rights

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



	September 30, 2017
	Carrying Value		Accumulated Depletion			Net Book Value
Coal properties	$	1,170,700	$	(432,701	)	$	737,999
Aggregates properties	151,236		(15,797		)	135,439
Oil and gas royalty properties	12,395		(6,941		)	5,454
Other	13,168		(1,450		)	11,718
Total	$	1,347,499	$	(456,889	)	$	890,610



	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 $8.6 million for the three months ended September 30, 2017 and 2016, respectively. Depletion expense related to the Partnership’s mineral rights totaled $16.7 million and $21.9 million for the nine months ended September 30, 2017 and 2016, respectively.

2016 Sale of Royalty Properties

The Partnership completed the sale of the following assets during the nine months ended September 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 $18.6 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 $1.5 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)

In addition to the two asset sales described above, during the nine months ended September 30, 2016, the Partnership sold mineral reserves in multiple sale transactions for cumulative $9.8 million of gross sales proceeds and recorded $6.8 million of cumulative gain from these sale transactions that are included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income. The substantial majority of these amounts relate to eminent domain transactions with governmental agencies.

11. 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. As of May 9, 2017, Foresight Energy is no longer deemed a related party. Refer to Note 14. Related Party Transactions for additional details. 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):



	September 30,			December 31,
	2017			2016
Intangible assets (including affiliate)	$	86,336		$	86,336
Less: accumulated amortization (including affiliate)	(35,966		)	(33,289		)
Total intangible assets, net (including affiliate)	$	50,370		$	53,047

Amortization expense related to the Partnership's intangible assets—affiliate totaled $0.9 million for the three months ended September 30, 2016. Amortization expense related to the Partnership's intangible assets—affiliate totaled $1.0 million and $2.3 million for the nine months ended September 30, 2017 and 2016, respectively. Amortization expense related to the Partnership's intangible assets totaled $0.9 million and $0.2 million for the three months ended September 30, 2017 and 2016, respectively. Amortization expense related to the Partnership's intangible assets totaled $1.7 million and $0.7 million for the nine months ended September 30, 2017 and 2016, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

12. Debt

The Partnership's debt consisted of the following (in thousands):



	September 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	69,000			210,000
Senior notes
4.91% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018	4,586			9,187
8.38% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2019	42,669			64,029
5.05% with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020	22,945			30,633
5.55% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023	16,115			18,825
4.73% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023	52,142			52,204
5.82% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024	104,520			119,524
8.92% with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024	31,733			36,272
5.03% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026	133,941			134,035
5.18% with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026	38,218			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	$	955,869		$	1,138,932
Net unamortized debt discount	(1,759		)	(1,322		)
Net unamortized debt issuance costs	(17,531		)	(7,339		)
Total debt, net	$	936,579		$	1,130,271
Less: current portion of long-term debt	174,138			140,037
Total long-term debt, net	$	762,441		$	990,234

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 redeemed the remaining outstanding 2018 Senior Notes at par (and paid accrued and unpaid interest thereon) within 60 days after October 1, 2017. NRP made this redemption on October 2, 2017 using a combination of cash on hand and borrowings from its Opco Credit Facility. Refer to Note 18. Subsequent Events for further discussion.

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 September 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 of September 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. 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 September 30, 2017 and 2016 were 5.49% and 4.87%, respectively. The weighted average interest rates for the borrowings outstanding under the Opco Credit Facility for nine months ended September 30, 2017 and 2016 were 5.22% and 4.24%, respectively. Debt issue cost related to the OpCo credit facility are $6.1 million at September 30, 2017 and have been capitalized and included in other assets on our consolidated balance sheet. 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 September 30, 2017, Opco had $69 million of 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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)


•	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.

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 $653.5 million and $673.0 million classified as Land, Plant and equipment and Mineral rights on the Partnership’s Consolidated Balance Sheet as of September 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 September 30, 2017 and December 31, 2016, the Opco Senior Notes had cumulative principal balances of $446.9 million and $503.0 million, respectively. Opco made mandatory principal payments of $56.1 million and $56.0 million during the nine months ended September 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 September 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.

13. 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:



	September 30, 2017				December 31, 2016
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Debt:
NRP 2018 Senior Notes ⁽¹⁾	$	94,362	$	95,070	$	420,097	$	412,250
NRP 2022 Senior Notes ⁽¹⁾	329,732		366,376		—		—
Opco Senior Notes and utility local improvement obligation ⁽²⁾	443,485		473,683		500,174		488,814
Opco Revolving Credit Facility ⁽³⁾	69,000		69,000		210,000		210,000

Assets:
Contracts receivable, current and long-term ⁽²⁾	$	44,217	$	30,807	$	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

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 September 30, 2017.

14. 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.

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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Coal royalty and other revenue	$	18,781	$	—	$	23,611	$	—
Coal royalty and other—affiliates revenue	—		20,635		27,216		47,648
Total	$	18,781	$	20,635	$	50,827	$	47,648

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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Operating and maintenance expense	$	415	$	—	$	700	$	—
Operating and maintenance expense—affiliates, net	—		392		452		973
Total	$	415	$	392	$	1,152	$	973

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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 other transactions with subsidiaries of Foresight Energy reflected on NRP's Consolidated Balance Sheets:



	September 30,		December 31,
	2017		2016
Sugar Camp rail load out direct financing lease amounts
Projected remaining payments	$	72,531	$	76,424
Unearned income	29,213		31,803

ASSETS
Accounts receivable	$	6,828	$	—
Accounts receivable—affiliates, net	—		6,496
Long-term contracts receivable	41,211		—
Long-term contracts receivable—affiliate	—		43,785
LIABILITIES
Deferred revenue	$	59,009	$	—
Deferred revenue—affiliates	—		71,632

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 $0.5 million and $0.4 million, including less than $0.1 million and less than $0.1 million related to discontinued operations at September 30, 2017 and December 31, 2016, respectively, for services provided by QMC to the Partnership. The Partnership had Accounts payable—affiliates to WPPLP of $0.2 million and $0.6 million at September 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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Operating and maintenance expenses—affiliates, net	$	2,154	$	1,980	$	6,477	$	6,591
General and administrative—affiliates	1,207		867		3,183		2,670

Included in loss from discontinued operations are $0.0 million and $0.4 million of operating and maintenance expenses charged by QMC for the three months ended September 30, 2017 and 2016, respectively. Included in loss from discontinued operations are less than $0.1 million and $1.2 million of operating and maintenance expenses charged by QMC for the nine months ended September 30, 2017 and 2016, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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 September 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 $0.3 million and $0.8 million for the three months ended September 30, 2017 and 2016, respectively. Coal related revenues from Corsa totaled $1.0 million and $1.9 million for the nine months ended September 30, 2017 and 2016, respectively. The Partnership had Accounts receivable—affiliates totaling $0.2 million and $0.2 million from Corsa at September 30, 2017 and December 31, 2016, respectively.

WPPLP Production Royalty and Overriding Royalty

During the three months ended September 30, 2017 and 2016, the Partnership recorded $0.4 million and $0.0 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 $0.7 million and $0.7 million during the nine months ended September 30, 2017 and 2016, respectively. The Partnership had Other assets—affiliate from WPPLP of $0.9 million and $1.0 million at September 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 Partners LP ("Quinwood"), an entity controlled 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 the subsidiary of Alpha as Coal royalty and other—affiliates revenue during the nine months ended September 30, 2017, respectively. There were no deferred minimum payments received in prior periods from the subsidiary of Alpha recognized as Coal royalty and other—affiliates revenue during the three months ended September 30, 2017.

15. 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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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.

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 three quarters of 2017 has resulted in a cumulative $68.5 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 $8.5 million negative cash impact to us. While the Partnership is pursuing its claim, a valuation allowance for the receivable amount has been recorded.

16. 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 September 30,								Nine months ended September 30,
	2017				2016				2017				2016
	Revenues		Percent		Revenues		Percent		Revenues		Percent		Revenues		Percent
Foresight Energy ⁽¹⁾	$	18,781	20.1	%	$	20,635	21.1	%	$	50,827	18.4	%	$	47,648	15.3	%

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

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):



	September 30, 2017		December 31, 2016
Deferred revenue	$	106,391	$	44,931
Deferred revenue—affiliate	—		71,632
Total deferred revenue (including affiliate)	$	106,391	$	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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Coal royalty and other	$	9,717	$	3,662	$	8,406	$	48,705
Coal royalty and other—affiliates	—		6,093		14,055		11,750
Total coal royalty and other (including affiliates)	$	9,717	$	9,755	$	22,461	$	60,455

Lease Modifications, Termination and Forfeitures of Minimum Royalty Balances

During the nine months ended September 30, 2017 and 2016, the Partnership entered into agreements with certain lessees to either modify or terminate existing coal related leases that resulted in the Partnership recognizing $3.4 million and $40.4 million of deferred revenue as revenue, respectively.

18. Subsequent Events

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

Distributions Declared

On October 26, 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 November 14, 2017 to common unitholders of record on November 7, 2017. In addition, the Board declared a distribution on NRP's 12.0% Class A Convertible Preferred Units with respect to the third quarter. One-half of the distribution on the Preferred Units will be paid in $3.8 million of cash and the other half will be paid-in-kind through the issuance of 3,825 additional Preferred Units.

Redemption of 2018 Senior Notes

On October 2, 2017, the Partnership redeemed in full the $94.4 million remaining principal amount of the 2018 Notes at a redemption price of 100.000% and paid all accrued and unpaid interest thereon.

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

The following review of operations for the three and nine month periods ended September 30, 2017 and 2016 should be read in conjunction with our Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Natural Resource Partners LP Annual Report on Form 10-K for the year ended December 31, 2016.

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.

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.

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance. 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

•Summary of Critical Accounting Estimates

•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 and other natural resources and operating a construction aggregates business. 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 primarily 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 nine months ended September 30, 2017, our financial results included (in thousands):



Revenues and other income	$	276,915
Net income from continuing operations	58,467
Adjusted EBITDA ⁽¹⁾	172,166

Operating cash flow provided by continuing operations	$	81,394
Investing cash flow used in continuing operations	3,440
Financing cash flow used in continuing operations	(3,961		)
Distributable Cash Flow ("DCF") ⁽¹⁾	85,760


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

2017 Recapitalization Transactions and Debt Reduction

During the first quarter of 2017, we completed the recapitalization transactions that improved our liquidity and strengthened our balance sheet. These recapitalization transactions included the issuance of $250 million of Preferred Units and the issuance of Warrants to purchase Common Units, and the extension of the majority of our 2018 debt maturities to 2020 and 2022. For more information on these transactions, see Note 3. Convertible Preferred Units and Warrants and Note 12. Debt to the consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q, which is incorporated herein by reference.

As of the filing date of this report, we have reduced our debt by $294.4 million from December 31, 2016. A summary of our 2017 debt reduction through the filing date of this report is summarized in the table below (in thousands):



	As of the Filing Date of this Report		December 31, 2016		YTD 2017 Debt Reduction
NRP LP Debt
2018 Senior Notes	$	—	$	425,000	$	425,000
2022 Senior Notes	345,638		—		(345,638		)
Opco debt
Revolving credit facility	52,000		210,000		158,000
Senior Notes	446,869		502,971		56,102
Other	—		961		961
Total	$	844,507	$	1,138,932	$	294,425

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



Revenues and other income	$	153,544
Net income from continuing operations	115,170
Adjusted EBITDA ⁽¹⁾	134,601

Operating cash flow provided by continuing operations	$	120,588
Investing cash flow provided by continuing operations	3,570
Financing cash flow provided by continuing operations	517
DCF⁽¹⁾	124,158


(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 59% of our coal royalty revenues and approximately 46% of the related production from metallurgical coal during the nine months ended September 30, 2017. NRP continued to benefit from higher metallurgical coal prices relative to 2016, with prices stabilizing at higher levels than in the comparable period in 2016. Most recently, metallurgical coal prices have increased substantially since the post-Cyclone Debbie period of mid-June as a result of increased imports into China and a lower than expected supply from Australia.

Illinois Basin and Appalachian thermal coal prices have also improved over the prior year as utilities continue to work down inventories and export demand has increased. Mild weather and natural gas prices that remain around $3/mcf continue to create a challenging environment for thermal coal competitiveness domestically. Internationally, API2 coal prices continue to improve, settling around $90 per metric ton at the end of September 2017, compared to prices in the low $60s in the same period in 2016. Higher seaborne prices, as well as a weaker U.S. Dollar, have combined to increase the competitiveness of thermal coal exports and have helped to maintain sales volumes from our low cost Illinois Basin properties.

Soda Ash Business Segment

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



Revenues and other income	$	27,676
Net income from continuing operations	27,676
Adjusted EBITDA⁽¹⁾	36,750

Operating cash flow provided by continuing operations	$	31,104
Investing cash flow provided by continuing operations	5,646
DCF⁽¹⁾	36,750


(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 third 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 nine months ended September 30, 2017 compared to the prior year due to temporary production issues. However, our earnings from Ciner Wyoming increased 7% in the three months ended September 30, 2017 compared to the previous quarter as a result of the progress made to improve production at the facility.

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



Revenues and other income	$	95,695
Net income from continuing operations	4,439
Adjusted EBITDA ⁽¹⁾	14,621

Operating cash flow provided by continuing operations	$	11,677
Investing cash flow used in continuing operations	(5,776		)
Financing cash flow used in continuing operations	(1,096		)
DCF ⁽¹⁾	6,827


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

Our overall construction aggregates performance in the nine months ended September 2017 was in line with performance compared to the same period in 2016. Our construction aggregates business is largely dependent on the strength of the local markets that it serves. During 2017, improved energy related and infrastructure spending in the Louisiana market was offset by reduced natural gas drilling in the Marcellus shale, reduced infrastructure spending in northern West Virginia and cutbacks in military spending in the Clarksville, Tennessee area.

Discontinued Operations

In July 2016, NRP Oil and Gas sold 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 September 30, 2017 Compared to Three Months Ended September 30, 2016

Revenues and Other Income

Revenues and other income decreased $4.6 million, or 5%, from $97.9 million in the three months ended September 30, 2016 to $93.3 million in the three months ended September 30, 2017. The following table shows our diversified sources of natural resource revenues and other income by business segment for the three months ended September 30, 2017 and 2016 (in thousands except for percentages):



	Coal Royalty and Other			Soda Ash			Construction Aggregates			Total
September 30, 2017
Revenues and other income	$	49,567		$	8,993		$	34,727		$	93,287
Percentage of total	53		%	10		%	37		%
September 30, 2016
Revenues and other income	$	55,363		$	10,753		$	31,758		$	97,874
Percentage of total	57		%	11		%	32		%

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 $5.8 million, or 10%, from $55.4 million in the three months ended September 30, 2016 to $49.6 million in the three months ended September 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 September 30,					Increase (Decrease)			Percentage Change
(In thousands, except percent and per ton data)	2017		2016			Increase (Decrease)			Percentage Change
Coal production (tons)
Appalachia
Northern ⁽¹⁾	226		(356		)	582			163	%
Central	3,596		3,348			248			7	%
Southern	468		683			(215		)	(31	)%
Total Appalachia	4,290		3,675			615			17	%
Illinois Basin	794		2,411			(1,617		)	(67	)%
Northern Powder River Basin	849		1,318			(469		)	(36	)%
Total coal production	5,933		7,404			(1,471		)	(20	)%

Coal royalty revenue per ton
Appalachia
Northern ⁽¹⁾	$	3.26	$	1.98		$	1.28		65	%
Central	4.77		3.28			1.49			45	%
Southern	5.73		3.83			1.90			50	%
Illinois Basin	4.32		3.63			0.69			19	%
Northern Powder River Basin	3.47		3.27			0.20			6	%
Combined average coal royalty revenue per ton	4.54		3.40			1.14			34	%

Coal royalty revenues
Appalachia
Northern ⁽¹⁾	$	737	$	370		$	367		99	%
Central	17,154		10,994			6,160			56	%
Southern	2,683		2,618			65			2	%
Total Appalachia	$	20,574	$	13,982		$	6,592		47	%
Illinois Basin	3,431		8,745			(5,314		)	(61	)%
Northern Powder River Basin	2,945		4,314			(1,369		)	(32	)%
Total coal royalty revenue	$	26,950	$	27,041		$	(91	)	—	%

Other revenues
Minimums recognized as revenue	$	9,812	$	9,755		$	57		1	%
Transportation and processing fees	5,570		6,127			(557		)	(9	)%
Property tax revenue	513		2,567			(2,054		)	(80	)%
Wheelage	1,219		919			300			33	%
Coal override revenue	3,059		615			2,444			397	%
Lease assignment fee	1,000		—			1,000			100	%
Hard mineral royalty revenues	817		700			117			17	%
Oil and gas royalty revenues	117		1,283			(1,166		)	(91	)%
Other	356		(69		)	425			(616	)%
Total other revenues	$	22,463	$	21,897		$	566		3	%
Coal royalty and other income	49,413		48,938			475			1	%
Gain on coal royalty and other segment asset sales	154		6,425			(6,271		)	98	%
Total coal royalty and other segment revenues and other income	$	49,567	$	55,363		$	(5,796	)	(10	)%

(1)Northern Appalachia was impacted by a prior period adjustment in 2016 of 0.5 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 royalty revenues were flat in the three months ended September 30, 2017 compared to the same period in 2016 as increased sales prices across all three of our major producing regions resulting in increased coal royalty revenue per ton was

offset by decreased production in the Illinois and Northern Powder River basins. Further discussion of the key drivers for each region follows:


•	Appalachia: Coal royalty revenue increased $6.6 million in this region primarily as a result of increased metallurgical coal prices and production in the third quarter of 2017 as compared to the third quarter of 2016.

•

Illinois Basin: Lower production in this region led to a $5.3 million decrease in coal royalty revenue, despite the increase in thermal coal prices and our royalty revenue per ton in the region. The decreased production in this region was primarily a result of the temporary relocation of certain production off of NRP's coal reserves. However, the decrease in coal royalty revenue was partially offset by a $2.4 million increase in overriding royalty revenue in this region from the mining of non-NRP coal.


•	Northern Powder River Basin: Lower production in this region led to the $1.4 million decrease in coal royalty revenue, despite the modest increase in prices. The lower production was a result of decreased mining on our acreage in this region which has a checkerboard coal reserve ownership pattern.

Total other revenues increased $0.6 million in the three months ended September 30, 2017 compared to the three months ended September 30, 2016 primarily as a result of increased overriding royalty revenue as described above and an increase in lease assignment fees. These increases were partially offset by decreased property tax reimbursement revenue and a decrease in oil and gas operating revenues.

Gain on coal royalty and other segment asset sales decreased $6.3 million, from $6.4 million in the three months ended September 30, 2016 to $0.2 million in the three months ended September 30, 2017. During the three months ended September 30, 2016 and in connection with our strategy to improve liquidity, we sold mineral reserves in multiple sale transactions for cumulative $9.8 million of gross sales proceeds. There has been no individually significant asset sale subsequent to the closing of the Partnership's recapitalization transactions in March 2017.

Soda Ash

Revenues and other income related to our equity investment in Ciner Wyoming decreased $1.8 million, or 17%, from $10.8 million in the three months ended September 30, 2016 to $9.0 million in the three months ended September 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 $2.9 million, or 9%, from $31.8 million in the three months ended September 30, 2016 to $34.7 million in the three months ended September 30, 2017. This increase is primarily due to higher production and sales of crushed stone, gravel and sand quarter-over-quarter.

Operating and Maintenance Expenses (including affiliates)

Operating and maintenance expenses (including affiliates) decreased $0.7 million, or 2%, from $35.3 million in the three months ended September 30, 2016 to $34.6 million in the three months ended September 30, 2017. This decrease is primarily related to the following:

Coal Royalty and Other

Operating and maintenance expenses (including affiliates) in our Coal Royalty and Other segment decreased $2.1 million, or 25% from $8.4 million in the three months ended September 30, 2016 to $6.3 million in the three months ended September 30, 2017. This decrease is primarily related to decreased property tax expense.

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

Construction Aggregates

Operating and maintenance expenses (including affiliates) in our construction aggregates segment increased $1.3 million, or 5% from $26.9 million in the three months ended September 30, 2016 to $28.2 million in the three months ended September 30, 2017. This increase is primarily related to higher materials costs driven by the increase in production.

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

DD&A expense decreased $4.5 million, or 35%, from $12.8 million in three months ended September 30, 2016 to $8.3 million in three months ended September 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 $1.2 million, or 24%, from $5.1 million in the three months ended September 30, 2016 to $3.9 million in the three months ended September 30, 2017. This decrease is primarily due to lower legal, consulting and advisory fees following the completion of the recapitalization transactions in March 2017 and decreased LTIP expense.

Asset Impairments

Asset impairments decreased $5.7 million, or 100%, from $5.7 million in the three months ended September 30, 2016. There was no impairment in the three months ended September 30, 2017. Asset impairments in the three months ended September 30, 2016 included certain coal and hard mineral properties.

Income (Loss) from Discontinued Operations

Income from discontinued operations decreased $7.5 million, or 106%, from $7.1 million income in the three months ended September 30, 2016 to a loss of $0.4 million in the three months ended September 30, 2017. The decrease is primarily a result of the sale of our non-operated oil and gas working interest assets, for which we recognized the gain on sale of the asset in the three months ended September 30, 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 September 30, 2017 and 2016:



	Operating Segments
For the Three Months Ended	Coal Royalty and Other		Soda Ash			Construction Aggregates		Corporate and Financing			Total
September 30, 2017
Net income (loss) from continuing operations	$	37,992	$	8,993		$	3,342	$	(23,828	)	$	26,499
Less: equity earnings from unconsolidated investment	—		(8,993		)	—		—			(8,993		)
Add: distributions from unconsolidated investment	—		12,250			—		—			12,250
Add: interest expense	—		—			59		20,021			20,080
Add: depreciation, depletion and amortization	5,305		—			3,001		—			8,306
Adjusted EBITDA	$	43,297	$	12,250		$	6,402	$	(3,807	)	$	58,142

September 30, 2016
Net income (loss) from continuing operations	$	32,250	$	10,753		$	1,039	$	(27,623	)	$	16,419
Less: equity earnings from unconsolidated investment	—		(10,753		)	—		—			(10,753		)
Add: distributions from unconsolidated investment	—		12,250			—		—			12,250
Add: interest expense	—		—			—		22,491			22,491
Add: depreciation, depletion and amortization	9,070		—			3,761		—			12,831
Add: asset impairments	5,697		—			—		—			5,697
Adjusted EBITDA	$	47,017	$	12,250		$	4,800	$	(5,132	)	$	58,935

Adjusted EBITDA was flat in the three months ended September 30, 2017 compared to the three months ended September 30, 2016 primarily as a result of the following:


•	Coal Royalty and Other segment Adjusted EBITDA decreased $3.7 million. While performance of the Partnership's coal related assets improved as described above, the prior year amount included $6.4 million of gains on asset sales in which the Partnership received $10.3 million of gross cash proceeds.


•	Construction Aggregates segment Adjusted EBITDA increased $1.6 million as a result of increased production and sales volume, increased marine terminal activity and higher margins on road construction and asphalt paving projects.


•	Corporate and Financing segment Adjusted EBITDA increased $1.3 million as a result of lower legal, consulting and advisory fees following the completion of the recapitalization transactions in March 2017 and decreased LTIP expense.

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 September 30, 2017 and 2016:



	Operating Segments
For the Three Months Ended	Coal Royalty and Other		Soda Ash		Construction Aggregates			Corporate and Financing			Total
September 30, 2017
Net cash provided by (used in) operating activities of continuing operations	$	44,119	$	8,992	$	2,155		$	(29,466	)	$	25,800
Net cash provided by (used in) investing activities of continuing operations	676		3,258		(1,163		)	—			$	2,771
Net cash provided by (used in) financing activities of continuing operations	484		—		—			51,406			$	51,890

September 30, 2016
Net cash provided by (used in) operating activities of continuing operations	$	34,997	$	12,250	$	4,357		$	(15,703	)	$	35,901
Net cash provided by (used in) investing activities of continuing operations	10,691		—		(434		)	—			10,257
Net cash used in financing activities of continuing operations	—		—		—			24,840			24,840

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 September 30, 2017 and 2016:



	Operating Segments
For the Three Months Ended	Coal Royalty and Other			Soda Ash		Construction Aggregates			Corporate and Financing			Total
September 30, 2017
Net cash provided by (used in) operating activities of continuing operations	$	44,119		$	8,992	$	2,155		$	(29,466	)	$	25,800
Add: return of equity from unconsolidated investment	—			3,258		—			—			3,258
Add: proceeds from sale of PP&E	27			—		75			—			102
Add: proceeds from sale of mineral rights	49			—		—			—			49
Add: return on long-term contract receivables	600			—		—			—			600
Less: maintenance capital expenditures	—			—		(926		)	—			(926		)
Distributable Cash Flow	$	44,795		$	12,250	$	1,304		$	(29,466	)	$	28,883

September 30, 2016
Net cash provided by (used in) operating activities of continuing operations	$	34,997		$	12,250	$	4,357		$	(15,703	)	$	35,901
Add: proceeds from sale of PP&E	265			—		78			—			343
Add: proceeds from sale of mineral rights	10,029			—		—			—			10,029
Add: proceeds from sale of assets included in discontinued operations	—			—		—			—			109,889
Add: return on long-term contract receivables—affiliate	397			—		—			—			397
Less: maintenance capital expenditures	(5		)	—		(342		)	—			(347		)
Distributable Cash Flow	$	45,683		$	12,250	$	4,093		$	(15,703	)	$	156,212

DCF decreased $127.3 million in the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. This decrease is due primarily to the following:


•	$109.9 million net cash proceeds from the sale of assets included in discontinued operations in the three months ended September 30, 2016.


•	Coal Royalty and Other segment: DCF was flat as increased cash flow from improved operations in the three months ended September 30, 2107 was offset by $10.4 million cash flow from segment asset sales in the three months ended September 30, 2016.


•	Construction Aggregates segment: While operating performance increased as described in Adjusted EBITDA above, DCF decreased $2.8 million due to temporary timing differences of cash receipts and disbursements.


•	Corporate and Financing: DCF decreased $13.8 million primarily as a result of a timing difference in the payment of its semi-annual interest payments after the recapitalization transaction in March 2017. In 2016, the Partnership paid interest on its 2018 Bonds in October 2016, while the Partnership paid interest on its 2022 Bonds in September 2017.

Results of Operations

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

Revenues and Other Income

Revenues and other income decreased $35 million, or 11%, from $311.9 million in the nine months ended September 30, 2016 to $276.9 million in the nine months ended September 30, 2017. The following table shows our diversified sources of natural resource revenues and other income by business segment for the nine months ended September 30, 2017 and 2016 (in thousands except for percentages):



	Coal Royalty and Other			Soda Ash			Construction Aggregates			Total
September 30, 2017
Revenues and other income	$	153,544		$	27,676		$	95,695		$	276,915
Percentage of total	55		%	10		%	35		%
September 30, 2016
Revenues and other income	$	193,114		$	30,742		$	88,091		$	311,947
Percentage of total	62		%	10		%	28		%

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 $39.6 million, or 20%, from $193.1 million in the nine months ended September 30, 2016 to $153.5 million in the nine months ended September 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 Nine Months Ended September 30,				Increase (Decrease)			Percentage Change
(In thousands, except percent and per ton data)	2017		2016		Increase (Decrease)			Percentage Change
Coal production (tons)
Appalachia
Northern	1,672		479		1,193			249	%
Central	11,193		10,046		1,147			11	%
Southern	1,721		2,201		(480		)	(22	)%
Total Appalachia	14,586		12,726		1,860			15	%
Illinois Basin	3,545		6,056		(2,511		)	(41	)%
Northern Powder River Basin	2,708		2,734		(26		)	(1	)%
Total coal production	20,839		21,516		(677		)	(3	)%

Coal royalty revenue per ton
Appalachia
Northern	$	1.36	$	4.19	$	(2.83	)	(68	)%
Central	5.09		3.22		1.87			58	%
Southern	5.95		3.37		2.58			77	%
Illinois Basin	3.68		3.57		0.11			3	%
Northern Powder River Basin	2.89		3.04		(0.15		)	(5	)%

Coal royalty revenues
Appalachia
Northern	$	2,279	$	2,005	$	274		14	%
Central	57,027		32,331		24,696			76	%
Southern	10,242		7,419		2,823			38	%
Total Appalachia	69,548		41,755		27,793			67	%
Illinois Basin	13,055		21,611		(8,556		)	(40	)%
Northern Powder River Basin	7,827		8,314		(487		)	(6	)%
Total coal royalty revenue	$	90,430	$	71,680	$	18,750		26	%

Other revenues
Minimums recognized as revenue	$	22,556	$	60,455	$	(37,899	)	(63	)%
Transportation and processing fees	15,729		15,663		66			—	%
Property tax revenue	4,311		8,899		(4,588		)	(52	)%
Wheelage	3,510		1,797		1,713			95	%
Coal override revenue	5,769		1,482		4,287			289	%
Lease assignment fee	1,000		—		1,000			100	%
Gain on reserve swap	—		—		—
Hard mineral royalty revenues	3,513		2,194		1,319			60	%
Oil and gas royalty revenues	2,532		2,538		(6		)	—	%
Other	827		1,136		(309		)	(27	)%
Total other revenues	$	59,747	$	94,164	$	(34,417	)	(37	)%
Coal royalty and other income	150,177		165,844		(15,667		)	(9	)%
Gain on coal royalty and other segment asset sales	3,367		27,270		(23,903		)	(88	)%
Total coal royalty and other segment revenues and other income	$	153,544	$	193,114	$	(39,570	)	(20	)%

Total coal royalty revenues increased $18.8 million, or 26%, from $71.7 million in the nine months ended September 30, 2016 to $90.4 million in the nine months ended September 30, 2017. Further discussion of the key drivers for the increase follows:


•	Appalachia: Coal royalty revenue increased $27.8 million in this region as a result of increased metallurgical coal prices and production.

•

Illinois Basin: Lower production in this region led to an $8.6 million decrease in coal royalty revenue. The decreased production in this region was primarily a result of the temporary relocation of certain production off of NRP's coal reserves. However, the decrease in coal royalty revenue was partially offset by a $4.3 million increase in overriding royalty revenue in this region from the mining of non-NRP coal.

Total other revenues decreased $34.4 million in the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 primarily as a result of a decrease in minimums recognized as revenue due to certain lease modifications and terminations in the second quarter 2016. In addition, total other revenue decrease as a result of lower property tax reimbursements. However, this decrease in property tax revenue was fully offset by lower property tax expenses as described in operating and maintenance expenses below.

Gain on coal royalty and other segment asset sales decreased $23.9 million year-over-year primarily as a result of numerous asset sales completed during the nine months ended September 30, 2016.

Construction Aggregates

Revenues and other income related to our construction aggregates segment increased $7.6 million, or 9%, from $88.1 million in the nine months ended September 30, 2016 to $95.7 million in the nine months ended September 30, 2017. This increase is primarily due to higher production and sales of crushed stone, gravel and sand and increased road construction and asphalt paving projects.

Soda Ash

Revenues and other income related to our equity investment in Ciner Wyoming decreased $3.0 million, or 10%, from $30.7 million in the nine months ended September 30, 2016 to $27.7 million in the nine months ended September 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 $2.2 million, or 2%, from $97.8 million in the nine months ended September 30, 2016 to $100.0 million in the nine months ended September 30, 2017. This increase is primarily related to the following:

Construction Aggregates

Operating and maintenance expenses (including affiliates) in our construction aggregates segment increased $7.4 million, or 10% from $73.5 million in the nine months ended September 30, 2016 to $80.9 million in the nine months ended September 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 $5.0 million, or 21% from $24.2 million in the nine months ended September 30, 2016 to $19.2 million in the nine months ended September 30, 2017. This decrease is primarily related to decreased property tax expense.

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

DD&A expense decreased $7.3 million, or 21%, from $34.5 million in nine months ended September 30, 2016 to $27.2 million in nine months ended September 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 $0.6 million, or 5%, from $13.3 million in the nine months ended September 30, 2016 to $13.9 million in the nine months ended September 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. This increase in G&A expense was partially offset by decreased legal, consulting and advisory fees following the completion of the recapitalization transactions in March 2017.

Asset Impairments

Asset impairments decreased $5.9 million, or 77%, from $7.7 million in the nine months ended September 30, 2016 to $1.8 million in the nine months ended September 30, 2017. Asset impairments in the nine months ended September 30, 2016 included certain coal and hard mineral properties. There were fewer and less significant asset impairments in the nine months ended September 30, 2017.

Debt Modification Expense

Debt modification expense was $7.9 million for the nine months ended September 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 nine months ended September 30, 2017 and related to the 4.563% premium paid to redeem the 2018 Senior Notes in April 2017.

Income (Loss) from Discontinued Operations

Income from discontinued operations decreased $2.5 million, or 125%, from income of $2.0 million in the nine months ended September 30, 2016 to a loss of $0.5 million in the nine months ended September 30, 2017. The decrease is primarily a result of the sale of the our discontinued non-operated oil and gas working interest assets, for which we recognized the gain on sale of the asset in the three months ended September 30, 2016.

Adjusted EBITDA (Non-GAAP Financial Measure)

See "—Results of Operations—Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016" for an explanation of Adjusted EBITDA. 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 nine months ended September 30, 2017 and 2016:



	Operating Segments
For the Nine Months Ended	Coal Royalty and Other		Soda Ash			Construction Aggregates		Corporate and Financing			Total
September 30, 2017
Net income (loss) from continuing operations	$	115,170	$	27,676		$	4,439	$	(88,818	)	$	58,467
Less: equity earnings from unconsolidated investment	—		(27,676		)	—		—			(27,676		)
Less: fair value adjustments for warrant liabilities	—		—			—		—			—
Add: distributions from unconsolidated investment	—		36,750			—		—			36,750
Add: interest expense	—		—			632		62,966			63,598
Add: debt modification expense	—		—			—		7,939			7,939
Add: loss on extinguishment of debt	—		—			—		4,107			4,107
Add: warrant issuance expense	—		—			—		—			—
Add: depreciation, depletion and amortization	17,653		—			9,550		—			27,203
Add: asset impairments	1,778		—			—		—			1,778
Adjusted EBITDA	$	134,601	$	36,750		$	14,621	$	(13,806	)	$	172,166

September 30, 2016
Net income (loss) from continuing operations	$	137,802	$	30,742		$	3,441	$	(80,582	)	$	91,403
Less: equity earnings from unconsolidated investment	—		(30,742		)	—		—			(30,742		)
Add: distributions from unconsolidated investment	—		34,300			—		—			34,300
Add: interest expense	—		—			—		67,265			67,265
Add: depreciation, depletion and amortization	23,496		—			11,013		—			34,509
Add: asset impairments	7,681		—			—		—			7,681
Adjusted EBITDA	$	168,979	$	34,300		$	14,454	$	(13,317	)	$	204,416

Adjusted EBITDA decreased $32.2 million, or 16%, from $204.4 million in the nine months ended September 30, 2016 to $172.2 million in the nine months ended September 30, 2017 primarily as a result of the following:


•	Coal Royalty and Other segment Adjusted EBITDA decreased $34.4 million. While performance of the our coal related assets improved as described above, the prior year amount included $40.4 million of revenue resulting from one-time lease modifications and $23.7 million increased gains on asset sales.


•	Soda Ash segment Adjusted EBITDA increased $2.5 million as a result of increased cash distributions received in the nine months ended September 30, 2017.


•	Construction Aggregates segment Adjusted EBITDA was flat in the nine months ended September 30, 2017 compared to 2016. Increased production and sales volume, increased marine terminal activity and higher margins on road construction and asphalt paving projects were offset by increased production costs and repairs and maintenance expenses.

Distributable Cash Flow (Non-GAAP Financial Measure)

See "—Results of Operations—Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016" for an explanation of Distributable Cash Flow (DCF). The following table (in thousands) presents the three major categories of the statement of cash flows by business segment for the nine months ended September 30, 2017 and 2016:



	Operating Segments
For the Nine Months Ended	Coal Royalty and Other		Soda Ash			Construction Aggregates			Corporate and Financing			Total
September 30, 2017
Net cash provided by (used in) operating activities of continuing operations	$	120,588	$	31,104		$	11,677		$	(81,975	)	$	81,394
Net cash provided by (used in) investing activities of continuing operations	3,570		5,646			(5,776		)	—			3,440
Net cash provided by (used in) financing activities of continuing operations	517		—			(1,096		)	(3,382		)	(3,961		)

September 30, 2016
Net cash provided by (used in) operating activities of continuing operations	$	91,372	$	34,300		$	16,680		$	(67,805	)	$	74,547
Net cash provided by (used in) investing activities of continuing operations	57,834		—			(4,324		)	—			53,510
Net cash used in financing activities of continuing operations	—		(7,229		)	(1,593		)	(68,047		)	(76,869		)

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 nine months ended September 30, 2017 and 2016:



	Operating Segments
For the Nine Months Ended	Coal Royalty and Other			Soda Ash		Construction Aggregates			Corporate and Financing			Total
September 30, 2017
Net cash provided by (used in) operating activities of continuing operations	$	120,588		$	31,104	$	11,677		$	(81,975	)	$	81,394
Add: return of equity from unconsolidated investment	—			5,646		—			—			5,646
Add: proceeds from sale of PP&E	27			—		460			—			487
Add: proceeds from sale of mineral rights	932			—		—			—			932
Add: return on long-term contract receivables (including affiliate)	2,611			—		—			—			2,611
Less: maintenance capital expenditures	—			—		(5,310		)	—			(5,310		)
Distributable Cash Flow	$	124,158		$	36,750	$	6,827		$	(81,975	)	$	85,760

September 30, 2016
Net cash provided by (used in) operating activities of continuing operations	$	91,372		$	34,300	$	16,680		$	(67,805	)	$	74,547
Add: proceeds from sale of PP&E	1,084			—		102			—			1,186
Add: proceeds from sale of mineral rights	54,178			—		—			—			54,178
Add: proceeds from sale of assets included in discontinued operations	—			—		—			—			109,889
Add: return on long-term contract receivables—affiliate	2,577			—		—			—			2,577
Less: maintenance capital expenditures	(5		)	—		(3,671		)	—			(3,676		)
Distributable Cash Flow	$	149,206		$	34,300	$	13,111		$	(67,805	)	$	238,701

DCF decreased $152.9 million in the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016. This decrease is due primarily to the following:


•	$109.9 million net cash proceeds from the sale of assets included in discontinued operations in the three months ended September 30, 2016.


•	Coal Royalty and Other segment: DCF decreased $25.0 million. However, cash flow from asset sales resulted in $54.3 million of additional DCF in the nine months ended September 30, 2016 as compared to 2017. Excluding the DCF impact of these asset sales, improved performance of segment assets resulted in $29.2 million increased DCF in the nine months ended September 30, 2017.


•	Construction Aggregates segment: While operating performance was flat as described in Adjusted EBITDA above, DCF decreased $6.3 million due to temporary timing differences of cash receipts and disbursements and increased maintenance capital expenditures.


•	Corporate and Financing: DCF decreased $14.2 million primarily as a result of a timing difference in the payment of its semi-annual interest payments after the recapitalization transactions in March 2017. In 2016, the Partnership paid interest on its 2018 Notes in October 2016, while the Partnership paid interest on its 2022 Notes in September 2017.

Liquidity and Capital Resources

Current Liquidity

As of September 30, 2017, we had a total of $121.2 million of cash and cash equivalents and $111.0 million in borrowing capacity under our Opco Credit Facility. During the nine months ended September 30, 2017, we reduced our debt by approximately $183.1 million by repaying $210.0 million of the Opco Credit Facility in full, redeeming $90.0 million of our 2018 Senior Notes, repaying $56.1 million of the Opco Private Placement Notes (as defined below) and eliminating the Opco utility local improvement obligation. These reductions of debt 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) and a $69.0 borrowing under the Opco Credit Facility. In addition, we redeemed the remaining $94.4 million 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 decreased $1.9 million, from $82.7 million in the nine months ended September 30, 2016 to $80.8 million in the nine months ended September 30, 2017. Cash flows from discontinued operations represent cash flow from operations of these assets prior to the sale date and resulted in a decrease of $8.8 million year-over-year. This decrease was partially offset by $6.9 million increased operating cash flow from continuing operations primarily from increased operational performance from our Coal Royalty and Other segment assets period-over-period.

Cash flow provided by investing activities decreased $156.7 million, from $160.3 million in the nine months ended September 30, 2016 to $3.6 million in the nine months ended September 30, 2017. Investing cash flows from discontinued operations decreased $106.6 million primarily as a result of the sale of our non-operated oil and gas working interest assets in 2016 for $109.9 million in net cash proceeds. Investing cash flows from continuing operations decreased $50.1 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 $198.8 million, from $202.4 million in the nine months ended September 30, 2016 to $3.6 million in the nine months ended September 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 September 30, 2017 and December 31, 2016, we had the following indebtedness (in thousands):



	September 30, 2017		December 31, 2016
Current portion of long-term debt, net	$	174,138	$	140,037
Long-term debt, net	762,441		990,234
Total debt, net	$	936,579	$	1,130,271

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 12. 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 14. 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 September 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 nine 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 15. 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).
10.1*		Employment Agreement dated August 16, 2017, between Quintana Minerals Corporation and Wyatt L. Hogan.
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: November 8, 2017
	By:	/s/ CORBIN J. ROBERTSON, JR.
		Corbin J. Robertson, Jr.
		Chairman of the Board and
		Chief Executive Officer
		(Principal Executive Officer)



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

Date: November 8, 2017
	By:	/s/ JENNIFER L. ODINET
		Jennifer L. Odinet
		Chief Accounting Officer
		(Principal Accounting Officer)