Edgar Filing: NATURAL RESOURCE PARTNERS LP

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________________________________

FORM 10-Q



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

For the quarterly period ended June 30, 2016



¨	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 or a smaller reporting company. See definition of "accelerated filer", "large accelerated filer", and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):



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

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

At August 1, 2016 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	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 4.	Controls and Procedures	48
Part II. Other Information
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 3.	Defaults Upon Senior Securities	49
Item 4.	Mine Safety Disclosure	49
Item 5.	Other Information	49
Item 6.	Exhibits	50
	Signatures	51

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)



	June 30, 2016			December 31, 2015
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	21,391		$	41,204
Accounts receivable, net	40,815			43,633
Accounts receivable—affiliates	8,616			6,345
Inventory	7,832			7,835
Prepaid expenses and other	4,777			4,268
Current assets of discontinued operations (see Note 3)	113,218			17,844
Total current assets	196,649			121,129
Land	25,020			25,022
Plant and equipment, net	55,763			60,675
Mineral rights, net	946,355			984,522
Intangible assets, net	3,470			3,930
Intangible assets, net—affiliate	51,570			52,997
Equity in unconsolidated investment	259,778			261,942
Long-term contracts receivable—affiliate	44,572			47,359
Other assets	863			1,173
Other assets—affiliate	1,046			1,124
Non-current assets of discontinued operations (see Note 3)	—			110,162
Total assets	$	1,585,086		$	1,670,035
LIABILITIES AND CAPITAL
Current liabilities:
Accounts payable	$	5,260		$	5,022
Accounts payable—affiliates	779			801
Accrued liabilities	33,837			44,997
Accrued liabilities—affiliates	—			456
Current portion of long-term debt, net	157,996			80,745
Current liabilities of discontinued operations (see Note 3)	79,947			4,388
Total current liabilities	277,819			136,409
Deferred revenue	42,608			80,812
Deferred revenue—affiliates	78,793			82,853
Long-term debt, net	1,050,562			1,186,681
Long-term debt, net—affiliate	—			19,930
Other non-current liabilities	3,670			5,171
Non-current liabilities of discontinued operations (see Note 3)	—			85,237
Commitments and contingencies (see Note 11)
Partners’ capital:
Common unitholders’ interest (12,232,006 units outstanding)	136,695			79,094
General partner’s interest	568			(606		)
Accumulated other comprehensive loss	(2,235		)	(2,152		)
Total partners’ capital	135,028			76,336
Non-controlling interest	(3,394		)	(3,394		)
Total capital	131,634			72,942
Total liabilities and capital	$	1,585,086		$	1,670,035

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						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Revenues and other income:
Coal and hard mineral royalty and other	$	58,892		$	34,752		$	87,368		$	69,201
Coal and hard mineral royalty and other—affiliates	17,504			32,342			28,074			51,403
VantaCore	31,642			40,643			56,324			67,442
Oil and gas royalty	1,091			892			1,464			2,507
Equity in earnings of Ciner Wyoming	10,188			11,599			19,989			24,122
Gain (loss) on asset sales	(1,071		)	3,455			20,854			5,070
Total revenues and other income	118,246			123,683			214,073			219,745

Operating expenses:
Operating and maintenance expenses	29,797			36,781			56,582			68,592
Operating and maintenance expenses—affiliates, net	2,402			3,479			5,886			6,346
Depreciation, depletion and amortization	10,472			18,170			20,252			28,846
Amortization expense—affiliate	704			907			1,426			1,745
General and administrative	3,173			1,918			6,408			4,205
General and administrative—affiliates	866			301			1,803			1,385
Asset impairments	91			3,803			1,984			3,803
Total operating expenses	47,505			65,359			94,341			114,922

Income from operations	70,741			58,324			119,732			104,823

Other income (expense)
Interest expense	(22,054		)	(21,474		)	(44,251		)	(43,147		)
Interest expense—affiliate	(61		)	(462		)	(523		)	(924		)
Interest income	7			1			26			16
Other expense, net	(22,108		)	(21,935		)	(44,748		)	(44,055		)

Net income from continuing operations	48,633			36,389			74,984			60,768
Loss from discontinued operations (see Note 3)	(2,187		)	(3,811		)	(5,111		)	(10,701		)
Net income	46,446			32,578			69,873			50,067
Less: net income attributable to non-controlling interest	—			(1,244		)	—			(1,244		)
Net income attributable to NRP	$	46,446		$	31,334		$	69,873		$	48,823

Net income (loss) attributable to limited partners:
Continuing operations	$	47,726		$	34,442		$	73,616		$	58,334
Discontinued operations	(2,143		)	(3,735		)	(5,009		)	(10,487		)
Total	$	45,583		$	30,707		$	68,607		$	47,847

Net income (loss) attributable to the general partner:
Continuing operations	$	907		$	703		$	1,368		$	1,190
Discontinued operations	(44		)	(76		)	(102		)	(214		)
Total	$	863		$	627		$	1,266		$	976

Basic and diluted net income (loss) per common unit:
Continuing operations	$	3.90		$	2.82		$	6.02		$	4.77
Discontinued operations	(0.18		)	(0.31		)	(0.41		)	(0.86		)
Total	$	3.72		$	2.51		$	5.61		$	3.91

Weighted average number of common units outstanding	12,232			12,232			12,232			12,232

Net income	$	46,446		$	32,578		$	69,873		$	50,067
Add: comprehensive income (loss) from unconsolidated investment and other	462			210			(83		)	(755		)
Less: comprehensive income attributable to non-controlling interest	—			(1,244		)	—			(1,244		)
Comprehensive income	$	46,908		$	31,544		$	69,790		$	48,068

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

(Unaudited)



	Common Unitholders				General Partner			Accumulated Other Comprehensive Loss			Partners' Capital Excluding Non-Controlling Interest			Non-Controlling Interest			Total Capital
	Common Unitholders
	Units	Amounts
Balance at December 31, 2015	12,232	$	79,094		$	(606	)	$	(2,152	)	$	76,336		$	(3,394	)	$	72,942
Distributions to unitholders	—	(11,006		)	(226		)	—			(11,232		)	—			(11,232		)
Net income	—	68,607			1,266			—			69,873			—			69,873
Non-cash contributions	—	—			134			—			134			—			134
Comprehensive loss from unconsolidated investment and other	—	—			—			(83		)	(83		)	—			(83		)
Balance at June 30, 2016	12,232	$	136,695		$	568		$	(2,235	)	$	135,028		$	(3,394	)	$	131,634

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Six Months Ended
	June 30,
	2016			2015
Cash flows from operating activities:
Net income	$	69,873		$	50,067
Adjustments to reconcile net income to net cash provided by operating activities of continuing operations:
Depreciation, depletion and amortization	20,252			28,846
Amortization expense—affiliates	1,426			1,745
Distributions from equity earnings from unconsolidated investment	22,050			21,805
Equity earnings from unconsolidated investment	(19,989		)	(24,122		)
Gain on asset sales	(20,854		)	(5,070		)
Loss from discontinued operations	5,111			10,701
Asset impairment	1,984			3,803
Gain on reserve swap	—			(9,290		)
Other, net	4,094			(10,049		)
Other, net—affiliates	212			(352		)
Change in operating assets and liabilities:
Accounts receivable	3,922			6,620
Accounts receivable—affiliates	(2,271		)	1,302
Accounts payable	150			686
Accounts payable—affiliates	(25		)	(41		)
Accrued liabilities	(3,131		)	63
Accrued liabilities—affiliates	(456		)	—
Deferred revenue	(38,204		)	7,499
Deferred revenue—affiliates	(4,060		)	63
Other items, net	(2,045		)	741
Other items, net—affiliates	607			—
Net cash provided by operating activities of continuing operations	38,646			85,017
Net cash provided by operating activities of discontinued operations	5,815			21,093
Net cash provided by operating activities	44,461			106,110
Cash flows from investing activities:
Proceeds from sale of oil and gas royalty properties	34,347			—
Proceeds from sale of coal and hard mineral royalty properties	9,802			1,845
Return of long-term contract receivables—affiliate	2,180			1,137
Proceeds from sale of plant and equipment and other	843			5,255
Acquisition of plant and equipment and other	(3,919		)	(5,073		)
Acquisition of mineral rights	—			(400		)
Net cash provided by investing activities of continuing operations	43,253			2,764
Net cash used in investing activities of discontinued operations	(3,814		)	(25,285		)
Net cash provided by (used in) investing activities	39,439			(22,521		)
Cash flows from financing activities:
Proceeds from loans	20,000			25,000
Repayments of loans	(98,482		)	(58,483		)
Distributions to partners	(11,232		)	(54,910		)
Distributions to non-controlling interest	—			(2,744		)
Contributions to discontinued operations	—			(31,725		)
Debt issue costs and other	(11,998		)	(5,086		)
Net cash used in financing activities of continuing operations	(101,712		)	(127,948		)
Net cash provided by (used in) financing activities of discontinued operations	(10,570		)	21,808
Net cash used in financing activities	(112,282		)	(106,140		)
Net decrease in cash and cash equivalents	(28,382		)	(22,551		)
Cash and cash equivalents of continuing operations at beginning of period	41,204			48,971
Cash and cash equivalents of discontinued operations at beginning of period	10,569			1,105
Cash and cash equivalents at beginning of period	51,773			50,076
Cash and cash equivalents at end of period	23,391			27,525
Less: cash and cash equivalents of discontinued operations at end of period	2,000			18,721
Cash and cash equivalents of continuing operations at end of period	$	21,391		$	8,804

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, oil and gas, construction aggregates, frac sand 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. Certain reclassifications have been made to prior period amounts to conform to the current period financial statement presentation.

As described in Note 2. Segment Information, we reclassified certain prior period amounts to conform to the way we internally manage and monitor segment performance. In particular, prior year general and administrative charges that were allocated to operating segments have been reclassified to Operating and maintenance expenses and Operating and maintenance expenses—affiliates on the Consolidated Statements of Comprehensive Income. The prior period reclassifications for new segments had no impact on the Partnership's consolidated financial position, net income (loss) or cash flows.

As described in Note 3. Discontinued Operations, we reclassified the operations of the Partnership's non-operated oil and gas working interest assets to discontinued operations and reclassified its related assets and liabilities to assets and liabilities held for sale for all periods presented in the accompanying consolidated financial statements.

On January 1, 2016, the Partnership adopted a new accounting standard using a retrospective approach that required the presentation of the Partnership's debt issuance costs as a direct deduction from the related debt liability, rather than recorded as an asset. The adoption resulted in a reclassification that reduced other current assets and short-term debt by $0.2 million and reduced other assets and long-term debt (including affiliate) by $13.8 million on the Partnership’s Consolidated Balance Sheet at December 31, 2015.

On January 26, 2016, the board of directors of our general partner approved a 1-for-10 reverse split on our common units, effective following market close on February 17, 2016. Pursuant to the authorization provided, the Partnership completed the 1-for-10 reverse unit split and its common units began trading on a reverse unit split-adjusted basis on the New York Stock Exchange on February 18, 2016. As a result of the reverse unit split, every 10 outstanding common units were combined into one common unit. The reverse unit split reduced the number of common units outstanding from 122.3 million units to 12.2 million units. All unit and per unit data included in these consolidated financial statements has been retroactively restated to reflect the reverse unit split.

In the second quarter of 2016, the Partnership determined its net cash provided by operating activities and net cash used by financing activities were understated by $8.0 million for the three months ended March 31, 2016. The Consolidated Statement of Cash Flows for the six months ended June 30, 2016 has been corrected for this error.

In our opinion, all adjustments considered necessary for a fair presentation have been included. The interim financial statements should be read in conjunction with the audited financial statements and related notes included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015. Interim results are not necessarily indicative of the results for a full year.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Management’s Forecast, Strategic Plan and Going Concern Analysis

While NRP has a diversified portfolio of assets and a history and continued forecast of profitable operations with positive operating cash flows, its operating results and credit metrics continue to be impacted by demand challenges for coal. As described in Note 8. Debt and Debt—Affiliate, NRP Operating LLC ("Opco"), a wholly owned subsidiary of NRP, has debt agreements that contain customary financial covenants, including maintenance covenants, and other covenants. In addition, NRP has issued $425 million of 9.125% Senior Notes due October 2018 that are governed by an indenture (the "Indenture") containing customary incurrence-based financial covenants and other covenants, but not maintenance covenants. In July 2016, NRP Oil and Gas LLC, a wholly owned subsidiary, sold all of its non-operated oil and gas working interest assets and used a portion of the proceeds to repay the NRP Oil and Gas reserve based lending facility (the "RBL Facility") in full. The following discussion presents management’s going concern analysis in light of management’s outlook and strategic plan to address its debt covenant compliance and maturities.

As of June 30, 2016, Opco had $260.0 million of indebtedness outstanding under its revolving credit facility (the "Opco Credit Facility") with scheduled commitment reductions of $50.0 million on December 31, 2016, $30.0 million on June 30, 2017, $30.0 million on December 31, 2017 and the remaining $150 million on June 30, 2018. In addition, as of June 30, 2016 Opco had $537.6 million outstanding under several series of Private Placement Notes with scheduled principal payments of $80.8 million through June 30, 2017 (the "Opco Private Placement Notes") (collectively referred to as the "Opco Debt agreements"). The maximum leverage ratio under the Opco Debt agreements is required not to exceed 4.0x. In addition, the Opco Debt agreements contain 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. Opco's leverage ratio was 2.84x at June 30, 2016.

Our going concern analysis includes an evaluation of relevant conditions and events including the Partnership's ability to meet its obligations and remain in compliance with its debt covenants over the next twelve months. We currently forecast that we will meet the Partnership's obligations, that we will be in compliance with all of the covenants under the Opco Debt agreements and that we will continue as a going concern. However, our forecast is sensitive to commodity pricing and counterparty risk. Breaches of the Opco Debt agreement covenants that are not waived or cured, to the extent possible, would result in an event of default under the Opco Debt agreements, and if such debt is accelerated by the lenders thereunder, such acceleration would also result in a cross-default under the Indenture. We are currently pursuing or considering a number of actions in order to mitigate the effects of adverse market developments which could otherwise cause us to breach financial covenants under the Opco Debt agreements. These actions include (i) dispositions of assets, (ii) actively managing our debt capital structure through a number of potential alternatives, including exchange offers and non-traditional debt and equity financing, (iii) minimizing our capital expenditures, (iv) obtaining waivers or amendments from our lenders, (v) effectively managing our working capital, (vi) improving our cash flows from operations and (vii) engaging legal and financial advisers to assist us in this process.

Recently Issued Accounting Standards Not Yet Adopted

The Financial Accounting Standards Board ("FASB") amended its guidance on revenue recognition. The core principle of this amendment 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 is currently evaluating the provisions of this guidance and has not determined the impact this guidance may have on its consolidated financial statements and related disclosure or decided upon the method of adoption.

The FASB issued guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The new guidance will require a formal assessment of going concern by management based on criteria prescribed in the new guidance, but will not impact the Partnership's financial position or results of operations. This guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter. Early adoption is permitted for annual or interim reporting periods for which the financial statements have not previously been issued. The Partnership is evaluating the impact this guidance will have on its consolidated financial statements and related disclosure and reviewing its policies and processes to ensure compliance with this new guidance upon adoption.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The FASB issued authoritative guidance which intended to simplify the measurement of inventory. This guidance requires an entity to measure inventory at the lower of cost or net realizable value, and defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This guidance is effective for annual and interim periods ending after December 15, 2016. The Partnership is currently evaluating the impact of this guidance on its consolidated financial statements.

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 is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.

2. Segment Information

Due to acquisitions that diversified our natural resource asset base, effective for the quarter ended December 31, 2015, management revised the Partnership's operating segments to align with its management structure and organizational responsibilities and revised the information that its chief operating decision maker regularly reviews for purposes of allocating resources and assessing performance. As a result, effective for the quarter ended December 31, 2015, we reported our financial performance based on the new segments as described below.

The Partnership's 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 four operating segments:

Coal and Hard Mineral Royalty and Other—consists primarily of coal royalty, coal related transportation and processing assets, aggregate and industrial minerals royalty assets 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. In February 2016, we sold reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee.

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, 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.

VantaCore—consists of our construction materials business acquired in October 2014 that operates hard rock quarries, an underground limestone mine, sand and gravel plants, asphalt plants and marine terminals. VantaCore operates in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.

Oil and Gas—consists of our royalty interests and overriding royalty interests in oil and natural gas properties. We own fee mineral, royalty and overriding royalty interests in oil and gas properties in Oklahoma and Louisiana. In February 2016, we sold royalty and overriding royalty interests in several producing properties located in the Appalachian Basin. In July 2016, we completed the sale of all of our Williston Basin non-operated working interest assets in North Dakota and Montana. See Note 3. Discontinued Operations for additional details about our discontinued operations. During the third quarter of 2016, the Partnership plans to transition the management responsibilities and reporting of its remaining oil and gas royalty assets into the Coal and Hard Minerals Royalty and Other operating segment.

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 on the Consolidated Statements of Comprehensive Income. Prior year general and administrative charges that are allocated

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

to the operating segments have been reclassified to operating and maintenance expenses. 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
	Coal and Hard Mineral Royalty and Other		Soda Ash		VantaCore			Oil and Gas			Corporate and Financing			Total

For the Three Months Ended June 30, 2016
Revenues (including affiliates)	$	76,396	$	10,188	$	31,642		$	1,091		$	—		$	119,317
Intersegment revenues (expenses)	30		—		(30		)	—			—			—
Gain (loss) on asset sales	67		—		9			(1,147		)	—			(1,071		)
Operating and maintenance expenses (including affiliates)	7,419		—		24,492			288			—			32,199
Depreciation, depletion and amortization	7,308		—		3,690			178			—			11,176
Asset impairment	91		—		—			—			—			91
Interest expense, net	—		—		—			—			22,108			22,108
Net income (loss) from continuing operations	61,675		10,188		3,439			(522		)	(26,147		)	48,633
Net loss from discontinued operations	—		—		—			(257		)	(1,930		)	(2,187		)
For the Three Months Ended June 30, 2015
Revenues (including affiliates)	$	67,094	$	11,599	$	40,643		$	892		$	—		$	120,228
Gain on asset sales	3,056		—		399			—			—			3,455
Operating and maintenance expenses (including affiliates)	7,070		—		32,564			626			—			40,260
Depreciation, depletion and amortization	12,749		—		4,865			1,463			—			19,077
Asset impairment	3,803		—		—			—			—			3,803
Interest expense, net	—		—		—			—			21,935			21,935
Net income (loss) from continuing operations	46,528		11,599		3,613			(1,197		)	(24,154		)	36,389
Net loss from discontinued operations	—		—		—			(2,404		)	(1,407		)	(3,811		)
For the Six Months Ended June 30, 2016
Revenues (including affiliates)	$	115,442	19,989		56,324			1,464			—			193,219
Intersegment revenues (expenses)	52		—		(52		)	—			—			—
Gain on asset sales	1,656		—		9			19,189			—			20,854
Operating and maintenance expenses (including affiliates)	14,820		—		46,627			1,021			—			62,468
Depreciation, depletion and amortization	14,069		—		7,252			357			—			21,678
Asset impairment	1,984		—		—			—			—			1,984
Interest expense, net	—		—		—			—			44,748			44,748
Net income (loss) from continuing operations	86,277		19,989		2,402			19,275			(52,959		)	74,984
Net loss from discontinued operations	—		—		—			(2,092		)	(3,019		)	(5,111		)
For the Six Months Ended June 30, 2015
Revenues (including affiliates)	120,604		24,122		67,442			2,507			—			214,675
Gain on asset sales	4,671		—		399			—			—			5,070
Operating and maintenance expenses (including affiliates)	15,484		—		57,998			1,456			—			74,938
Depreciation, depletion and amortization	22,765		—		8,721			(895		)	—			30,591
Asset impairment	3,803		—		—			—			—			3,803
Interest expense, net	—		—		—			—			44,055			44,055
Net income (loss) from continuing operations	83,223		24,122		1,122			1,946			(49,645		)	60,768
Net loss from discontinued operations	—		—		—			(8,486		)	(2,215		)	(10,701		)
Total Assets
June 30, 2016	996,714		259,778		199,187			128,903			504			1,585,086
December 31, 2015	1,047,922		261,942		200,348			158,862			961			1,670,035

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

3. Discontinued Operations

In June 2016, the Partnership determined it met held for sale criteria for its non-operated oil and gas working interest assets. In June 2016, NRP Oil and Gas signed a definitive agreement to sell these assets for $116.1 million, subject to customary closing conditions and purchase price adjustments. In July 2016, NRP Oil and Gas closed this transaction, which had an effective date of April 1, 2016.

The Partnership's exit from its non-operated oil and gas working interest business represents a strategic shift to reduce debt and focus on its aggregates, soda ash and coal and hard minerals business segments. As a result, we have classified the operating results and cash flows of our non-operated oil and gas working interest assets as discontinued operations in our consolidated statements of comprehensive income and consolidated statements of cash flows for all periods presented. Additionally, the related assets and liabilities associated with discontinued operations are classified as held for sale in our consolidated balance sheets. The assets and liabilities of our non-operated oil and gas working interest assets as of June 30, 2016 are classified as current in our consolidated balance sheet as we closed on the transaction in July 2016. Remaining in the Oil and Gas segment is our investments in royalty interests in oil and natural gas properties that the Partnership plan to transition into the Coal Hard Minerals Royalty and Other operating segement during the third quarter of 2016.

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						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
	(Unaudited)						(Unaudited)
Revenues and other income:
Oil and gas	$	9,511		$	13,947		$	16,435		$	27,111
Gain (loss) on asset sales	(184		)	—			(184		)	451
Total revenues and other income	9,327			13,947			16,251			27,562

Operating expenses:
Operating and maintenance expenses (including affiliates)	5,871			4,768			10,252			10,587
Depreciation, depletion and amortization	3,286			11,583			7,527			25,461
Asset impairments	427			—			564			—
Total operating expenses	9,584			16,351			18,343			36,048

Interest expense	(1,930		)	(1,407		)	(3,019		)	(2,215		)
Loss from discontinued operations	$	(2,187	)	$	(3,811	)	$	(5,111	)	$	(10,701	)

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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



	June 30, 2016		December 31, 2015
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,000	$	10,569
Accounts receivable, net (including affiliates) (1)	6,845		7,053
Mineral rights, net	103,962		—
Other	411		222
Total current assets	113,218		17,844
Mineral rights, net	—		109,505
Other non-current assets	—		657
Total assets of discontinued operations	$	113,218	$	128,006

LIABILITIES
Current liabilities:
Current portion of long-term debt, net (2)	$	74,783	$	—
Other (including affiliates) (1)	5,164		4,388
Total current liabilities	79,947		4,388
Long-term debt, net (2)	—		83,600
Other non-current liabilities	—		1,637
Total liabilities of discontinued operations	$	79,947	$	89,625


(1)	See Note 10. Related Party Transactions for additional information on the Partnership's related party assets and liabilities.


(2)	The Partnership identified the RBL Facility as specifically attributed to its non-operated oil and gas working interest assets and included the interest from this debt in discontinued operations. See Note 8. Debt and Debt—Affiliate for additional information on the Partnership's debt related to discontinued operations.

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



	Six Months Ended
	June 30,
	2016		2015
	(Unaudited)
Cash paid for interest	$	1,489	$	1,435

Capital expenditures related to the Partnership's discontinued operations were $3.8 million and $28.7 million during the six months ended June 30, 2016 and 2015, respectively.

4. Equity Investment

We account for our 49% investment in Ciner Wyoming LLC ("Ciner Wyoming", and formerly "OCI Wyoming LLC") using the equity method of accounting. Ciner Wyoming distributed $22.1 million and $21.8 million to us in the six months ended June 30, 2016 and 2015, 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 $152.1 million and $154.8 million as of June 30, 2016 and December 31, 2015, 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. Our equity in the earnings of Ciner Wyoming is summarized as follows (in thousands):

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(Unaudited)						(Unaudited)
Income allocation to NRP’s equity interests	$	11,388		$	12,786		$	22,384		$	26,513
Amortization of basis difference	(1,200		)	(1,187		)	(2,395		)	(2,391		)
Equity in earnings of unconsolidated investment	$	10,188		$	11,599		$	19,989		$	24,122

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(Unaudited)				(Unaudited)
Sales	$	116,698	$	122,200	$	231,082	$	242,630
Gross profit	28,732		31,091		56,983		63,815
Net Income	23,241		26,094		45,682		54,108

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



	June 30, 2016		December 31, 2015
	(Unaudited)
Current assets	$	134,053	$	144,695
Noncurrent assets	231,926		233,845
Current liabilities	43,772		43,018
Noncurrent liabilities	102,437		116,808

The purchase agreement for the acquisition of the Partnership’s interest in Ciner Wyoming required the Partnership to pay additional contingent consideration to Anadarko to the extent certain performance criteria described in the purchase agreement were met by Ciner Wyoming in any of the years 2013, 2014 or 2015. During the first quarters of 2014, 2015 and 2016, the Partnership paid contingent consideration of $0.5 million, $3.8 million and $7.2 million, respectively, in contingent consideration to Anadarko for performance criteria met by Ciner Wyoming in 2013, 2014 and 2015, respectively. The Partnership has no further contingent consideration payments due to Anadarko under the purchase agreement.

5. Plant and Equipment

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



	June 30, 2016			December 31, 2015
	(Unaudited)
Plant and equipment at cost	$	79,009		$	92,049
Construction in process	1,031			646
Less accumulated depreciation	(24,277		)	(32,020		)
Total plant and equipment, net	$	55,763		$	60,675

Depreciation expense related to the Partnership's plant and equipment totaled $3.0 million and $4.5 million for the three months ended June 30, 2016 and 2015, respectively. Depreciation expense related to the Partnership's plant and equipment totaled $6.5 million and $9.0 million for the six months ended June 30, 2016 and 2015, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

6. Mineral Rights

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



	June 30, 2016
	(Unaudited)
	Carrying Value		Accumulated Depletion			Net Book Value
Coal and Hard Mineral Royalty and Other	$	1,268,661	$	(443,259	)	$	825,402
VantaCore	112,700		(4,017		)	108,683
Oil and Gas	18,098		(5,828		)	12,270
Total	$	1,399,459	$	(453,104	)	$	946,355



	December 31, 2015
	Carrying Value		Accumulated Depletion			Net Book Value
Coal and Hard Mineral Royalty and Other	$	1,278,274	$	(432,260	)	$	846,014
VantaCore	112,700		(3,082		)	109,618
Oil and Gas	38,884		(9,994		)	28,890
Total	$	1,429,858	$	(445,336	)	$	984,522

Depletion expense related to the Partnership’s mineral rights totaled $7.2 million and $13.3 million for the three months ended June 30, 2016 and 2015, respectively. Depletion expense related to the Partnership's mineral rights totaled $13.3 million and $19.3 million for the six months ended June 30, 2016 and 2015, respectively.

Sales of Royalty Properties

As discussed in Note 1. "Basis of Presentation," we are currently pursuing or considering a number of actions, including dispositions of assets, in order to mitigate the effects of adverse market developments which could otherwise cause us to breach financial covenants under our debt agreements. As part of this plan, the Partnership sold the following assets during the six months ended June 30, 2016:

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

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

7. Intangible Assets (Including Affiliate)

The Partnership's intangible assets—affiliate relate to above market coal transportation contracts with subsidiaries of Foresight Energy LP ("Foresight Energy") in which we receive throughput fees for the handling and transportation of coal.



	June 30, 2016			December 31, 2015
	(Unaudited)
Intangible assets—affiliate	$	81,109		$	81,109
Less accumulated amortization—affiliate	(29,539		)	(28,112		)
Total intangible assets, net—affiliate	$	51,570		$	52,997

Amortization expense related to the Partnership's intangible assets—affiliate totaled $0.7 million and $0.9 million for the three months ended June 30, 2016 and 2015, respectively. Amortization expense related to the Partnership's intangible assets—affiliate totaled $1.4 million and $1.8 million for the six months ended June 30, 2016 and 2015, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The Partnership's intangible assets consist of permits, aggregate-related trade names and other agreements as follows (in thousands):



	June 30, 2016			December 31, 2015
	(Unaudited)
Intangible assets	$	5,077		$	5,076
Less accumulated amortization	(1,607		)	(1,146		)
Total intangible assets, net	$	3,470		$	3,930

Amortization expense related to the Partnership's intangible assets totaled $0.3 million for both the three months ended June 30, 2016 and 2015 and $0.5 million both the six months ended June 30, 2016 and 2015.

8. Debt and Debt—Affiliate

As of June 30, 2016 and December 31, 2015, debt and debt—affiliate consisted of the following (in thousands):



	June 30, 2016			December 31, 2015
	(Unaudited)
NRP LP debt:
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%	$	425,000		$	425,000
Opco debt (1):
$300 million floating rate revolving credit facility, due June 2018	260,000			290,000
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018	9,233			13,850
8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2019	64,286			85,714
5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020	38,462			38,462
5.31% utility local improvement obligation, with annual principal and interest payments in February, due March 2021	961			1,153
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023	18,900			21,600
4.73% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023	60,000			60,000
5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024	120,000			135,000
8.92% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024	36,364			40,909
5.03% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026	148,077			148,077
5.18% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026	42,308			42,308
NRP Oil and Gas debt:
Reserve-based revolving credit facility due November 2019	75,000			85,000
Total debt at face value	$	1,298,591		$	1,387,073
Net unamortized debt discount	(1,700		)	(2,077		)
Net unamortized debt issuance costs (1)	(13,550		)	(14,040		)
Total debt, net	$	1,283,341		$	1,370,956
Less: current portion of long-term debt	157,996			80,745
Less: debt classified as liabilities of discontinued operations	74,783			83,600
Total long-term debt	$	1,050,562		$	1,206,611

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)


(1)	See Note 1. Basis of Presentation for discussion of debt issuance costs reclassification upon adoption of new accounting standard on January 1, 2016.

NRP Debt

NRP Senior Notes

In September 2013, NRP, together with NRP Finance Corporation ("NRP Finance"), a wholly owned subsidiary of NRP, as co-issuer, issued $300.0 million of 9.125% Senior Notes at an offering price of 99.007% of par (the "NRP Senior Notes"). Net proceeds after expenses from the issuance of NRP Senior Notes were approximately $289.0 million. The NRP Senior Notes call for semi-annual interest payments on April 1 and October 1 of each year, and will mature on October 1, 2018.

In October 2014, NRP, together with NRP Finance as co-issuer, issued an additional $125.0 million of the NRP Senior Notes at an offering price of 99.5% of par. The additional issuance constituted the same series of securities as the existing NRP Senior Notes. Net proceeds of $122.6 million from the additional issuance of the NRP Senior Notes were used to fund a portion of the purchase price of NRP’s acquisition of non-operated working interests in oil and gas assets located in the Williston Basin in North Dakota.

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

Opco Debt

All of Opco’s debt is guaranteed by its wholly owned subsidiaries and is secured by certain of the assets of Opco and its wholly owned subsidiaries other than NRP Trona LLC, as further described below. As of June 30, 2016 and December 31, 2015, Opco was in compliance with the terms of the financial covenants contained in its debt agreements.

Opco Credit Facility

In June 2016, Opco entered into an amendment (the "First Amendment") to its $300.0 million Amended and Restated Credit Agreement ("Opco Credit Facility") that is guaranteed by all of Opco’s wholly owned subsidiaries, and is secured by liens on certain of the assets of Opco and its subsidiaries, as further described below. Under the First Amendment:


•	The maturity date of the Opco Credit Facility was extended from October 1, 2017 to June 30, 2018;


•	The maximum leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the Opco Credit Facility) has been amended to remain at 4.0x for the remaining term of the Opco Credit Facility, including for the period ending June 30, 2016; and


•	The asset sale covenant was amended to allow asset sales of up to $300.0 million from and after the effective date of the First Amendment; provided, however, that 75% of the net cash proceeds of any such asset sales must be used to repay the Opco Credit Facility (without any corresponding commitment reduction) and/or NRP Opco’s Senior Notes described below.

On the effective date of the First Amendment, the total commitment under the Opco Credit Facility was reduced from $300.0 million to $260.0 million. In addition, Opco and the lenders agreed to further reduce commitments under the Opco Credit Facility to (a) $210.0 million on December 31, 2016, (b) $180.0 million on June 30, 2017 and (c) $150.0 million on December 31, 2017. Opco will have the right to delay any of these commitment reductions by up to 90 days each upon the agreement of the lenders holding 66.7% of the then-existing commitments. To the extent any such commitment reduction is extended under the terms of the A&R Revolving Credit Facility, Opco's ability to make distributions to the Partnership will be limited to amounts necessary for the Partnership to pay taxes and other general partnership expenses and make interest payments on its 9.125% Senior Notes due 2018.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

In addition to the 4.0x leverage ratio described above, the Opco Credit Facility requires Opco to maintain a 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. As of June 30, 2016, Opco's leverage ratio was 2.84x, and fixed charge coverage ratio was 5.67x.

Effective on the date of the First Amendment, 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 the three months ended June 30, 2016 and 2015 were 4.11% and 2.19%, respectively. The weighted average interest rates for the borrowings outstanding under the Opco Credit Facility for the six months ended June 30, 2016 and 2015 were 3.95% and 2.07%, respectively.

Opco will incur a commitment fee on the unused portion of the revolving credit facility at a rate of 0.50% per annum. Opco may prepay all amounts outstanding under the Opco Credit Facility at any time without penalty.

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. The Opco Credit Facility also contains customary events of default, including cross-defaults under Opco’s senior notes (as described below).

The Opco Credit Facility is collateralized and secured by liens on certain of Opco’s assets with a carrying values of $691.2 million and $709.9 million classified as Land, Mineral rights and Plant and equipment on the Partnership’s Consolidated Balance Sheet as of June 30, 2016 and December 31, 2015, 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 VantaCore’s construction aggregates mining operations, and (5) certain of Opco’s coal-related infrastructure assets.

Opco Senior Notes

Opco has issued several series of private placement senior notes (the "Opco Senior Notes") with various interest rates and principal due dates. As of June 30, 2016, and December 31, 2015, the Opco Senior Notes had cumulative principal balances of $537.6 million and $585.9 million, respectively. Opco made principal payments of $48.3 million on the Opco Senior Notes during each of the six months ended June 30, 2016 and 2015.

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.

The 8.38% and 8.92% Opco Senior Notes also provide that in the event that Opco’s leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the Note Purchase Agreements) exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00. Opco has not exceeded the 3.75 to 1.00 ratio at the end of any fiscal quarter through June 30, 2016.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

In connection with the entry into an amendment to the Opco Credit Facility in June 2015, Opco entered into the Third Amendment to the Note Purchase Agreements (the "NPA Amendment") that provides for the security of the Opco Senior Notes by the same collateral package pledged by Opco and its subsidiaries to secure the A&R Revolving Credit Facility, as described above. In addition, the NPA Amendment includes a covenant that provides that, in the event Opco or any of its subsidiaries is subject to any additional or more restrictive covenants under the agreements governing its material indebtedness (including the A&R Revolving Credit Facility, and all renewals, amendments or restatements thereof), such covenants shall be deemed to be incorporated by reference in the Opco Senior Notes and the holders of the Opco Senior Notes shall receive the benefit of such additional or more restrictive covenants to the same extent as the lenders under such material indebtedness agreement. Certain holders of the Opco Senior Notes have communicated to us that they believe they are entitled to consideration under this provision in connection with the First Amendment to the Opco Credit Facility. We are evaluating the noteholders’ assertions and are in active discussions with them. We are unable to estimate the outcome of these discussions at this time.

NRP Oil and Gas Debt Classified as Liabilities of Discontinued Operations

The RBL Facility

In August 2013, NRP Oil and Gas entered into the RBL Facility, a senior secured, reserve-based revolving credit facility, in order to fund capital expenditure requirements related to the development of the oil and gas assets in which it owned non-operated working interests. The RBL Facility was secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. NRP Oil and Gas was the sole obligor under the RBL Facility, and neither the Partnership nor any of its other subsidiaries was a guarantor of the RBL Facility.

At June 30, 2016 and December 31, 2015, there was $75.0 million and $85.0 million respectively, outstanding under the RBL Facility. As described in Note 3. Discontinued Operations, the Partnership included this debt and its related interest expense in discontinued operations. In July 2016, NRP Oil and Gas LLC closed the sale of its Williston Basin non-operated working interest assets and used a portion of the proceeds to repay the RBL Facility in full.

In March 2016, the Company entered into an amendment to the RBL Facility (the "Fourth Amendment"). Per the Fourth Amendment, the borrowing base would have been reduced to $70.0 million on August 1, 2016, and to $50.0 million on October 1, 2016, with any outstanding amounts under the RBL Facility in excess of the reduced principal amounts due and payable on their respective day. The next scheduled redetermination of the borrowing base under the RBL Facility would have occured in November 2016.

The Fourth Amendment amended the financial covenants contained in the RBL Facility as follows:


•	The maximum total leverage ratio (defined as the ratio of the total debt to EBITDAX) was increased from 3.5x to 4.0x at March 31, 2016 and 4.5x at June 30, 2016. Thereafter, the total leverage ratio would have decreased to 3.5x for the remainder of the term of the RBL Facility.


•	The minimum current ratio decreased from 1.0x to 0.75x at March 31, 2016 and June 30, 2016 and would have reverted to 1.0x thereafter for the remainder of the term of the RBL Facility.

As of June 30, 2016, NRP Oil and Gas' leverage ratio was 3.98x, and current ratio was 2.61x. NRP Oil and Gas was in compliance with the terms of the covenants contained in the RBL Facility as of both June 30, 2016 and December 31, 2015.

Effective on the date of the Fourth Amendment, indebtedness under the RBL Facility bore interest, at the Company'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 4.0%; or


•	a rate equal to LIBOR, plus an applicable margin of 4.0%.

The commitment fee on the unused portion of the borrowing base under the RBL Facility was also amended to be a flat 0.50% fee.

The Fourth Amendment contained several other amendments, including a requirement for NRP Oil and Gas to pay down the RBL Facility each month with excess cash flow (which amounts may not be reborrowed and will result in a corresponding reduction

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

in the borrowing base) and a requirement to use the net proceeds of any asset sales to repay the RBL Facility (which amounts may not be reborrowed and will result in a corresponding reduction in the borrowing base). In addition, the Fourth Amendment waived the delivery of 2015 audited financial statements containing an audit opinion containing "a "going concern" or like qualification or exception" as an event of default under the RBL Facility.

9. Fair Value Measurements

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

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



	June 30, 2016				December 31, 2015
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
	(Unaudited)
Debt and debt—affiliate:
NRP Senior Notes (2)	$	418,696	$	318,750	$	417,296	$	277,313
Opco Senior Notes and utility local improvement obligation (1)	536,527		403,943		584,890		383,065
Opco Revolving Credit Facility (3)	253,335		260,000		285,170		290,000
NRP Oil and Gas RBL Facility (3)	74,783		75,000		83,600		85,000

Assets:
Contracts receivable—affiliate, current and long-term (1)	$	47,542	$	32,861	$	49,948	$	34,498


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


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


(3)	The Level 3 fair value approximates the carrying 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.

10. Related Party Transactions

Reimbursements to Affiliates of our General Partner

The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for services provided to the Partnership and for expenses incurred on the Partnership’s behalf. Employees of Quintana Minerals Corporation ("QMC") and Western Pocahontas Properties Limited Partnership ("WPPLP"), affiliates of the Partnership, provide their services to manage the Company'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. In addition, the Partnership receives non-cash equity contributions from its general partner related to compensation paid directly by the general partner and not reimbursed by the Partnership. These amounts are presented as non-cash equity contributions on the Partnership's Consolidated Statements of Partners' Capital and were $0.1 million during the six months ended June 30, 2016. 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 legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by 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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The Partnership had Accounts payable—affiliates to Quintana Minerals Corporation of $0.5 million and $1.1 million including $0.2 million and $0.7 million related to discontinued operations at June 30, 2016 and December 31, 2015, respectively, for services provided by Quintana Minerals Corporation to the Partnership. The Partnership had Accounts payable—affiliates to WPPLP of $0.5 million and $0.3 million at June 30, 2016 and December 31, 2015, respectively.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(Unaudited)				(Unaudited)
Operating and maintenance expenses—affiliates, net	$	2,099	$	3,235	$	4,611	$	5,937
General and administrative—affiliates	866		301		1,803		1,385

Included in Income (loss) from discontinued operations are $0.5 million and $0.7 million and $0.2 million and $0.4 million of operating and maintenance expenses charged by Quintana Minerals Corporation for the three and six months ended June 30, 2016 and 2015, respectively.

Cline Affiliates

Various companies controlled by Chris Cline, including Foresight Energy LP ("Foresight Energy"), lease coal reserves from the Partnership, and the Partnership also leases coal transportation assets to these companies for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest in the NRP's general partner, as well as approximately 0.5 million of NRP's common units at June 30, 2016.

Coal related revenues from Foresight Energy totaled $16.9 million and $31.6 million for the three months ended June 30, 2016 and 2015, respectively. Coal related revenues from Foresight Energy totaled $27.0 million and $49.9 million for the six months ended June 30, 2016 and 2015, respectively. As of June 30, 2016 and December 31, 2015, the Partnership had Accounts receivable—affiliates from Foresight Energy of $8.4 million and $6.4 million, respectively. The Partnership had recorded $78.5 million and $82.6 million in minimum royalty payments as Deferred revenue—affiliates at June 30, 2016 and December 31, 2015, respectively.

The Partnership owns and leases rail load out and associated facilities to Foresight Energy at Foresight Energy's Sugar Camp mine. The lease agreement is accounted for as a direct financing lease. Total projected remaining payments under the lease at June 30, 2016 were $78.9 million with unearned income of $33.6 million, and the net amount receivable was $45.3 million, of which $2.0 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets. Total projected remaining payments under the lease at December 31, 2015 were $81.2 million with unearned income of $35.3 million and the net amount receivable was $45.9 million, of which $2.0 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliates on the accompanying Consolidated Balance Sheets.

The Partnership holds a contractual overriding royalty interest from a subsidiary of Foresight Energy that provides for payments based upon production from specific tons at Foresight Energy's Sugar Camp operations. This overriding royalty was accounted for as a financing arrangement and is reflected as an affiliate receivable. The net amount receivable under the agreement as of June 30, 2016 was $2.8 million, of which $1.5 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate. The net amount receivable under the agreement as of December 31, 2015 was $4.9 million, of which $1.5 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets.

Long-Term Debt—Affiliate

Donald R. Holcomb, one of the Partnership’s former directors, is a manager of Cline Trust Company, LLC, which owns approximately 0.5 million of the Partnership’s common units and $20.0 million in principal amount of the Partnership’s 9.125% Senior Notes due 2018. The members of the Cline Trust Company are four trusts for the benefit of the children of Chris Cline,

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

each of which owns an approximately equal membership interest in the Cline Trust Company. Mr. Holcomb also serves as trustee of each of the four trusts. Cline Trust Company, LLC purchased the $20.0 million of the Partnership’s 9.125% Senior Notes due 2018 in the Partnership’s offering of $125.0 million additional principal amount of such notes in October 2014 at the same price as the other purchasers in that offering. The balance on this portion of the Partnership’s 9.125% Senior Notes due 2018 was $19.9 million as of December 31, 2015 and is included in Long-term debt, net—affiliate on the accompanying Consolidated Balance Sheet as of December 31, 2015. In April 2016, Mr. Holcomb resigned from the Partnership's board of directors and as a result the $19.9 million debt balance held by Cline Trust Company was included in Long-term debt, net on the accompanying Consolidated Balance Sheet as of June 30, 2016.

Quintana Capital Group GP, Ltd.

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

At June 30, 2016, a fund controlled by Quintana Capital owned a majority 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, is Chairman of the Board of Corsa. Coal related revenues from Corsa totaled $0.6 million and $0.8 million for the three months ended June 30, 2016 and 2015, respectively and $1.1 million and $1.5 million for the six months ended June 30, 2016 and 2015, respectively. The Partnership had recorded $0.3 million in minimum royalty payments as Deferred revenue—affiliates at both June 30, 2016 and December 31, 2015. The Partnership also had Accounts receivable—affiliates totaling $0.2 million from Corsa at both June 30, 2016 and December 31, 2015.

WPPLP Production Royalty and Overriding Royalty

The Partnership recorded $0.1 million and $0.7 million 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 for the three and six months ended June 30, 2016, respectively. These charges were zero for both the three and six months ended June 30, 2015. The Partnership had Other assets—affiliate from WPPLP of $1.0 million and $1.1 million at June 30, 2016 and December 31, 2015, respectively related to a non-production royalty receivable from WPPLP for overriding royalty interest on a mine.

11. Commitments and Contingencies

Legal

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

Since 2013, several citizen group lawsuits have been filed against landowners alleging ongoing discharges of pollutants, including selenium and conductivity, from valley fills located at reclaimed mountaintop removal mining sites in West Virginia. In each case, the mine on the subject property had been closed, the property had been reclaimed, and the state reclamation bond had been released. Any determination that a landowner or lessee has liability for discharges from a previously reclaimed mine site could result in substantial compliance costs or fines and would result in uncertainty as to continuing liability for completed and reclaimed coal mine operations. A subsidiary of the Partnership has been named as a defendant in one of these lawsuits. The Partnership currently cannot reasonably estimate a range of potential loss, if any, related to this matter.

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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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 2015 and the first half of 2016 resulted in a cumulative $31.0 million negative cash impact to us. Such amount will increase for each quarter during which mining operations continue to be idled. We do not currently have an estimate as to when the mine will resume coal production. If the mine remains idled for an extended period or if the mine is permanently closed, our financial condition could be adversely affected.

In April, 2016, we filed a lawsuit against Macoupin Energy, LLC ("Macoupin"), a subsidiary of Foresight Energy, in Macoupin County, Illinois. The lawsuit alleges that Macoupin has failed to comply with the terms of its coal mining, rail loadout and rail loop leases by incorrectly recouping previously paid minimum royalties. Foresight Energy’s failure to properly calculate its recoupable balance and failure to make payments in accordance with these lease agreements with respect to the third and fourth quarters of 2015 and the first half of 2016 resulted in a cumulative $4.7 million negative cash impact to us. While the Partnership plans to pursue its claim, a valuation allowance for the receivable amount has been recorded. It is possible that the Partnership’s current estimate of the valuation allowance related to this matter could change, perhaps materially, in the future.

12. Major Customers

Revenues from customers that exceeded ten percent of total revenues and other income for either the three or six months ended June 30, 2016 and 2015 are as follows (in thousands except for percentages):



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(Unaudited)						(Unaudited)
	Revenues		Percent	Revenues		Percent	Revenues		Percent	Revenues		Percent
Foresight Energy	$	16,935	14%	$	31,581	26%	$	27,013	13%	$	49,879	23%

13. Unit-Based Compensation

At the time of our initial public offering, GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the "Long-Term Incentive Plan") for directors of GP Natural Resource Partners LLC and employees of its affiliates who perform services for the Partnership. The Compensation, Nominating and Governance Committee ("CNG Committee") of GP Natural Resource Partners LLC’s board of directors administers the Long-Term Incentive Plan and has historically approved annual awards of phantom units that vest four years from the date of grant. In February 2016, the CNG Committee adopted and the Board approved a new cash-based long-term incentive plan to the employees of its affiliates who perform services for the Partnership.

Subject to the rules of the exchange upon which the common units are listed at the time, the board of directors and the compensation committee of the board of directors have the right to alter or amend the Long-Term Incentive Plan or any part of the Long-Term Incentive Plan from time to time. Except upon the occurrence of unusual or nonrecurring events, no change in any outstanding grant may be made that would materially reduce the benefit intended to be made available to a participant without the consent of the participant.

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

In connection with the phantom unit awards, the Compensation, Nominating and Governance Committee also granted tandem Distribution Equivalent Rights ("DERs"), which entitle the holders to receive distributions equal to the distributions paid on the

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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

A summary of activity in the outstanding grants during 2016 is as follows (in thousands):



	Phantom Units
Outstanding grants at January 1, 2016	126
Grants during the period	—
Grants vested and paid during the period	(28	)
Forfeitures during the period	(6	)
Outstanding grants at June 30, 2016	92

Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The Partnership recorded expenses related to its Long-Term Incentive Plan of $0.2 million for both the three and six months ended June 30, 2016. The Partnership also recorded a credit to expenses related to its Long-Term Incentive plan of $1.4 million and $1.5 million for the three and six months ended June 30, 2015, respectively due to the decline in the market price of the Partnership's common units during the period.

In connection with the Long-Term Incentive Plan, payments are typically made during the first quarter of the year. Payments of $1.5 million and $4.4 million were made during the six months ended June 30, 2016 and 2015, respectively. The unaccrued cost associated with unvested outstanding grants and related DERs at June 30, 2016 and December 31, 2015, was $0.5 million and $0.7 million, respectively.

14. Cash Distributions

The following table shows the distributions paid by the Partnership during the six months ended June 30, 2016 and 2015:



				Total Distributions (In thousands)
Date Paid	Period Covered by Distribution	Distribution per Common Unit		Common Units		GP Interest		Total
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

2015
February 13, 2015	October 1 - December 31, 2014	$	3.50	$	42,804	$	874	$	43,678
May 14, 2015	January 1 - March 31, 2015	0.90		11,007		225		11,232

15. Supplemental Cash Flow Information

The Partnership's supplemental cash flow information of continuing operations is summarized as follows (in thousands):



	Six Months Ended June 30,
	2016		2015
	(Unaudited)
Cash paid for interest	$	42,671	$	42,739
Plant, equipment and mineral rights funded with accounts payable or accrued liabilities	—		4,452

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

16. Supplementary Unrestricted Subsidiary Information

The following is presented as supplementary data as required by the Indenture governing the NRP Senior Notes. As described in Note 1. Basis of Presentation, in February 2016, the Partnership designated NRP Oil and Gas as an Unrestricted Subsidiary for purposes of the Indenture. In addition, the Partnership has designated BRP LLC, a joint venture in which the Partnership owns a 51% interest, and Coval Leasing Company, LLC, a wholly owned subsidiary of BRP LLC, as Unrestricted Subsidiaries for purposes of the Indenture. The information below may not necessarily be indicative of the results of operations, or financial position had the subsidiaries operated as independent entities. There were no transactions between the Partnership's Restricted Subsidiaries and its Unrestricted Subsidiaries. In accordance with the requirements of the Indenture, the following condensed consolidating financial information presents the financial condition and results of operations of the Partnership and its Restricted Subsidiaries and its Unrestricted Subsidiaries:

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS

(in thousands)



	June 30, 2016
	Unrestricted Subsidiaries of NRP			NRP and its Restricted Subsidiaries		Eliminations			Total
ASSETS
Current assets of discontinued operations	$	113,218		$	—	$	—		$	113,218
Current assets (including affiliates)	3,621			79,810		—			83,431
Mineral rights, net	24,570			921,785		—			946,355
Equity in unconsolidated investment	—			259,778		—			259,778
Other non-current assets (including affiliates)	230			182,074		—			182,304
Total assets	$	141,639		$	1,443,447	$	—		$	1,585,086
LIABILITIES AND CAPITAL
Current portion of long-term debt, net	$	—		$	157,996	$	—		$	157,996
Current liabilities of discontinued operations	79,947			—		—			79,947
Other current liabilities (including affiliates)	2,672			37,207		(3		)	39,876
Long-term debt, net	—			1,050,562		—			1,050,562
Other non-current liabilities (including affiliates)	3,086			121,985		—			125,071
Partners' capital	59,379			75,646		3			135,028
Non-controlling interest	(3,445		)	51		—			(3,394		)
Total liabilities and capital	$	141,639		$	1,443,447	$	—		$	1,585,086

	December 31, 2015
	Unrestricted Subsidiaries of NRP			NRP and its Restricted Subsidiaries		Eliminations			Total
ASSETS
Current assets of discontinued operations	$	17,844		$	—	$	—		17,844
Current assets (including affiliates)	3,696			100,178		(589		)	103,285
Mineral rights, net	24,940			959,582		—			984,522
Equity in unconsolidated investment	—			261,942		—			261,942
Non-current assets of discontinued operations	110,162			—		—			110,162
Other non-current assets (including affiliates) (1)	230			192,050		—			192,280
Total assets	$	156,872		$	1,513,752	$	(589	)	$	1,670,035
LIABILITIES AND CAPITAL
Current portion of long-term debt, net (1)	$	—		$	80,745	$	—		$	80,745
Current liabilities of discontinued operations	4,388			—		—			4,388
Other current liabilities (including affiliates)	2,963			48,356		(43		)	51,276
Long-term debt, net (including affiliate) (1)	—			1,206,611		—			1,206,611
Non-current liabilities of discontinued operations	85,237			—		—			85,237
Other non-current liabilities (including affiliates)	3,066			165,770		—			168,836
Partners' capital	64,663			12,219		(546		)	76,336
Non-controlling interest	(3,445		)	51		—			(3,394		)
Total liabilities and capital	$	156,872		$	1,513,752	$	(589	)	$	1,670,035


(1)	See Note 1. Basis of Presentation for discussion of debt issuance costs reclassification upon adoption of new accounting standard on January 1, 2016.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)



	Three Months Ended June 30, 2016
	Unrestricted Subsidiaries of NRP			NRP and its Restricted Subsidiaries		Total
Revenues	$	644		$	117,602	$	118,246
Operating expenses	572			46,933		47,505
Income from operations	72			70,669		70,741
Other expense, net	—			22,108		22,108
Net income from continuing operations	72			48,561		48,633
Net loss from discontinued operations	(2,187		)	—		(2,187		)
Net income (loss)	(2,115		)	48,561		46,446
Add: comprehensive income from unconsolidated investment and other	—			462		462
Comprehensive income (loss)	$	(2,115	)	$	49,023	$	46,908

	Three Months Ended June 30, 2015
	Unrestricted Subsidiaries of NRP			NRP and its Restricted Subsidiaries		Total
Revenues	$	3,834		$	119,849	$	123,683
Operating expenses	1,280			64,079		65,359
Income from operations	2,554			55,770		58,324
Other expense, net	—			21,935		21,935
Net income from continuing operations	2,554			33,835		36,389
Net loss from discontinued operations	(3,811		)	—		(3,811		)
Net income (loss)	(1,257		)	33,835		32,578
Add: comprehensive income from unconsolidated investment and other	—			210		210
Less: comprehensive loss attributable to non-controlling interest	(1,244		)	—		(1,244		)
Comprehensive income (loss)	$	(2,501	)	$	34,045	$	31,544

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)



	Six Months Ended June 30, 2016
	Unrestricted Subsidiaries of NRP			NRP and its Restricted Subsidiaries			Total
Revenues	$	1,043		$	213,030		$	214,073
Operating expenses	1,214			93,127			94,341
Income (loss) from operations	(171		)	119,903			119,732
Other expense, net	—			44,748			44,748
Net income (loss) from continuing operations	(171		)	75,155			74,984
Net loss from discontinued operations	(5,111		)	—			(5,111		)
Net income (loss)	(5,282		)	75,155			69,873
Add: comprehensive loss from unconsolidated investment and other	—			(83		)	(83		)
Comprehensive income (loss)	$	(5,282	)	$	75,072		$	69,790

	Six Months Ended June 30, 2015
	Unrestricted Subsidiaries of NRP			NRP and its Restricted Subsidiaries			Total
Revenues	$	5,119		$	214,626		$	219,745
Operating expenses	(1,669		)	116,591			114,922
Income from operations	6,788			98,035			104,823
Other expense, net	—			44,055			44,055
Net income from continuing operations	6,788			53,980			60,768
Net loss from discontinued operations	(10,701		)	—			(10,701		)
Net income (loss)	(3,913		)	53,980			50,067
Add: comprehensive loss from unconsolidated investment and other	—			(755		)	(755		)
Less: comprehensive loss attributable to non-controlling interest	(1,244		)	—			(1,244		)
Comprehensive income (loss)	$	(5,157	)	$	53,225		$	48,068

17. Deferred Revenue and Deferred Revenue—Affiliate

Most of the Partnership’s coal and aggregates lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue when received. The deferred revenue attributable to the minimum payment is recognized as 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) consist of the following (in thousands):



	June 30, 2016		December 31, 2015
	(Unaudited)
Deferred revenue	$	42,608	$	80,812
Deferred revenue—affiliate	78,793		82,853
Total deferred revenue (including affiliate)	$	121,401	$	163,665

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The Partnership recognized the following amounts of deferred revenue (including affiliate) attributable to previously paid minimums as Coal and hard mineral royalty and other revenue (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(Unaudited)				(Unaudited)
Coal and hard mineral royalty and other	$	38,740	$	706	$	44,835	$	1,769
Coal and hard mineral royalty and other—affiliates	4,787		4,000		5,657		7,477
Total coal and hard mineral royalty and other (including affilaites)	$	43,527	$	4,706	$	50,492	$	9,246

Lease Modifications, Termination and Forfeitures of Minimum Royalty Balances

In April 2016, the Partnership entered into agreements with certain lessees to either modify or terminate existing coal related leases that resulted in the Partnership recognizing approximately $35 million of deferred revenue in April 2016 as follows:

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

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

18. Subsequent Events

The following represents material events that have occurred subsequent to June 30, 2016 through the time of the Partnership’s filing of its Quarterly Report on Form 10-Q with the SEC:

Distribution Declared

On July 20, 2016 the Board of Directors of GP Natural Resource Partners LLC declared a distribution of $0.45 per unit to be paid by the Partnership on August 12, 2016 to unitholders of record on August 5, 2016.

Sale of Non-Operated Oil and Gas Working Interest Assets and Repayment of RBL Facility

In July, NRP Oil and Gas sold its non operated oil and gas working interest assets located in the Williston Basin for $116.1 million in gross cash proceeds, subject to customary closing conditions and purchase price adjustments, and recorded a gain of approximately $6 million. The effective date of the sale was April 1, 2016. A portion of these net proceeds were used to repay the NRP Oil and Gas RBL Facility in full.

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

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

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

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


•	our business strategy;


•	our liquidity and access to capital and financing sources;


•	our financial strategy;


•	prices of and demand for coal, trona and soda ash, construction aggregates, crude oil and natural gas, frac sand and other natural resources;


•	estimated revenues, expenses and results of operations;


•	the amount, nature and timing of capital expenditures;


•	our ability to consummate planned asset sales and execute on our long-term strategic plan;


•	projected production levels by our lessees, VantaCore Partners LLC ("VantaCore"), and the operators of our oil and gas working interests;


•	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 therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

You should not put undue reliance on any forward-looking statements. See "Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2015 for important factors that could cause our actual results of operations or our actual financial condition to differ.

As used herein, unless the context otherwise requires: "we," "our," "us" and the "Partnership" refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to "NRP" and "Natural Resource Partners" refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to "Opco" refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries. References to "NRP Oil and Gas" refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP. NRP Finance Corporation ("NRP Finance") is a wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes.

Introduction

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

•Executive Overview

•Results of Operations

•Liquidity and Capital Resources

•Unrestricted Subsidiary Information

•Off-Balance Sheet Transactions

•Related Party Transactions

•Recent Accounting Standards

Executive Overview

We are a diversified natural resource company engaged principally in the business of owning, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal, trona and soda ash, construction aggregates, frac sand, crude oil and natural gas, and other natural resources. Our business is organized into four operating segments:

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.

Oil and Gas—consists of our royalty interests and overriding royalty interests in oil and natural gas properties. We own fee mineral, royalty and overriding royalty interests in oil and gas properties in Oklahoma and Louisiana. In February 2016, we sold royalty and overriding royalty interests in several producing properties located in the Appalachian Basin. In July 2016, we completed the sale of all of our Williston Basin non-operated working interest assets in North Dakota and Montana. During the third quarter of 2016, we plan to transition the management responsibilities and reporting of its remaining oil and gas royalty assets into the Coal and Hard Minerals Royalty and Other operating segment.

For the six months end June 30, 2016, our financial results included (in thousands):



Revenues and other income	$	214,073
Net income from continuing operations	$	74,984
Adjusted EBITDA (1)	$	145,481

Operating cash flow provided by continuing operations	$	38,646
Investing cash flow provided by continuing operations	$	43,253
Financing cash flow used by continuing operations	$	(101,712	)
Distributable Cash Flow ("DCF") (1)	$	82,489


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

Current Liquidity Position

As of June 30, 2016, we had $21.4 million of cash and cash equivalents as well as $2.0 million in cash related to our discontinued operations. During the six months ended June 30, 2016, we repaid approximately $108.5 million of debt including $48.5 million of the Opco’s senior notes and utility local improvement obligation, $50.0 million under Opco’s revolving credit facility and $10.0 million under the NRP Oil and Gas RBL facility, each discussed below. In July 2016, we repaid the remaining balance of $75.0 million under the NRP Oil and Gas RBL facility in full with a portion of the proceeds from the sale of all of our non-operated oil and gas working interests assets.

We have significant debt service requirements, including $80.8 million in principal payments on Opco's senior notes (the "Opco Senior Notes") due each year through 2018, and scheduled commitment reductions under Opco’s $260.0 million revolving credit facility (the "Opco Credit Facility") by $50 million at December 31, 2016, an additional $30 million at June 30, 2017, and

an additional $30.0 million at December 31, 2017. In addition, our operating results continue to be impacted by the adverse conditions in the commodity markets. We continue to implement our long-term plan to strengthen our balance sheet, reduce debt and enhance liquidity in order to reposition the Partnership for future growth. As part of this plan, we reduced our cash distributions during 2015 by over 87%. The cash savings resulting from the distribution reductions are being used primarily to repay debt. We also reduced general and administrative and other overhead costs in connection with these efforts.

However, we have determined that the cash savings from the distribution cuts and our cost reduction efforts will not be sufficient to meet our deleveraging objectives and have determined to sell certain assets and pursue alternative financing arrangements to help meet these objectives. In February 2016, we sold the aggregates reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee for $10.0 million in cash. In February 2016, we also sold royalty and overriding royalty interests in several producing properties located in the Appalachian Basin, including our overriding royalty interests in the Marcellus Shale, for $37.5 million in cash. The sale included royalty and overriding royalty interests in approximately 765 gross producing wells as of December 31, 2015. In July 2016, we completed the sale of NRP Oil and Gas LLC's non-operated working interest oil and gas assets in the Williston Basin for $116.1 million in cash, subject to customary post-closing purchase price adjustments, and used a portion of the proceeds to repay the $75.0 million of outstanding borrowings on the NRP Oil and Gas RBL Facility in full. This sale had an effective date of April 1, 2016.

While we have closed several asset sale transactions, if we are unable to complete additional asset sales and/or pursue alternative financing transactions and conditions in the commodity markets do not improve, our liquidity and our ability to comply with the financial and other restrictive covenants contained in our debt agreements will be adversely affected. See "—Management's Forecast and Strategic Plan" below for further discussion.

Current Results/Market Outlook

Coal and Hard Mineral Royalty and Other Business Segment

For the six months ended June 30, 2016, our Coal and Hard Mineral Royalty and Other business segment financial results included the following (in thousands):



Revenues and other income	$	117,098
Net income from continuing operations	$	86,277
Adjusted EBITDA (1)	$	102,330

Operating cash flow provided by continuing operations	$	55,908
Investing cash flow provided by continuing operations	$	12,796
Financing cash flow used by continuing operations	$	(93,161	)
Distributable Cash Flow ("DCF") (1)	$	68,709


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

Although the thermal and metallurgical coal markets remain challenged in the near term, prices have improved recently for both commodities. As of June 30, 2016, coal production in the United States was down approximately 27% over 2015 production, and warm summer weather has led to drawdowns from inventories. However, there are still significant stockpiles at the utilities, and the strong dollar remains a headwind for exports. We believe that additional tons will come out of the market over the remainder of 2016, but that the market is moving towards an equilibrium that could lead to improved pricing in 2017.

Although the U.S. coal industry is under pressure, we do not know to what extent our properties will be affected. A number of coal producers have filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code, and additional producers may file for bankruptcy. Historically, our leases have generally been assumed and all pre-petition bankruptcy amounts have been cured in full in our lessees’ bankruptcy processes, but we have no assurance this will continue in the future. Alpha Natural Resources ("Alpha"), which is our second largest lessee, filed for Chapter 11 bankruptcy protection in August 2015. Alpha has continued operating and paying royalties to us following the bankruptcy filing. Alpha’s plan of reorganization was approved in July 2016, and the majority of our leases were accepted and assumed by either Contura Energy, which acquired certain core coal assets from Alpha in the bankruptcy, or by the reorganized Alpha. We expect to receive all pre-petition amounts due to us with respect to the leases assumed. We believe that each of Contura and the reorganized Alpha will continue to rationalize coal production until the

coal markets stabilize. We do not know to what extent our properties will be affected. Arch Coal, Inc. ("Arch") and Peabody Energy Corporation ("Peabody") filed for Chapter 11 bankruptcy protection in January 2016 and April 2016, respectively. Our overall exposure to both Arch and Peabody is immaterial; however, we expect our Arch leases to be assumed in the third quarter and to receive all pre-petition amounts due to us.

While producers of Central Appalachian thermal coal have struggled for an extended period due to the high cost nature of their operations, production from our Illinois Basin properties also decreased by 34% in the first six months of 2016 as compared to the same period in 2015. Substantially all of the decrease in production from our Illinois Basin properties is attributable to the idling of Foresight Energy's Deer Run mine (which we also refer to as our Hillsboro property) as a result of elevated carbon monoxide levels at the mine beginning in March 2015. In July 2015, we received a notice from Foresight Energy declaring a resulting force majeure event at the Deer Run mine. While we have filed a lawsuit disputing Foresight Energy’s claim of force majeure, the effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us quarterly minimum deficiency payments with respect to the Deer Run mine until mining resumes. Under the lease for the Deer Run mine, Foresight Energy is required to make minimum deficiency payments to us of $7.5 million per quarter, or $30.0 million per year. The amount payable to us as the minimum deficiency payment with respect to any quarter is reduced by the amount of coal royalties actually paid to us for tonnage sold at the mine with respect to that quarter. We received royalty payments on tonnage sold from coal stockpiles at the Deer Run mine during 2015, but these stockpiles have been depleted. Foresight Energy’s failure to make the deficiency payments with respect to the second, third and fourth quarters of 2015 and the first half of 2016 resulted in a cumulative negative cash impact to us of $31.0 million. Such amount will increase for each quarter during which mining operations continue to be idled. Foresight Energy has temporarily sealed the mine, and is continuing efforts to cure the elevated carbon monoxide levels, but we do not know when, or if, mining activities at the Deer Run mine will recommence.

While the metallurgical coal markets continue to remain depressed, the benchmark pricing has increased over 10% in 2016, and recent spot prices have exceeded $100/ton. We derived approximately 34% of our coal royalty revenues and 38% of the related production from metallurgical coal during the six months ended June 30, 2016. The global metallurgical coal market continues to suffer from oversupply driven in part by reduced demand from China. Domestic coal producers are also burdened by the effects of the relatively strong U.S. dollar, which increases the production cost of domestic coal producers relative to foreign producers.

Soda Ash Business Segment

For the six months ended June 30, 2016, our Soda Ash business segment financial results included the following (in thousands):



Revenues and other income	$	19,989
Net income from continuing operations	$	19,989
Adjusted EBITDA (1)	$	22,050

Operating cash flow provided by continuing operations	$	22,050
Financing cash flow used by continuing operations	$	(22,050	)
Distributable Cash Flow ("DCF") (1)	$	22,050


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

Income from our trona mining and soda ash refinery investment was lower year-over-year for the six months ended June 30, 2016 due to certain operational and production related issues. We believe these issues have been resolved, the market remains firm, and that we expect to see operational improvements from Ciner Wyoming over the remainder of the year. Domestic sales volumes, which are typically sold at higher prices than soda ash sold internationally, have remained relatively stable. Ciner Resources LP., our partner that controls and operates Ciner Wyoming, is a publicly traded master limited partnership that predominantly depends on distributions from Ciner Wyoming in order to make distributions to its public unitholders.

VantaCore Business Segment

For the six months ended June 30, 2016, our VantaCore business segment financial results included the following (in thousands):



Revenues and other income	$	56,333
Net income from continuing operations	$	2,402
Adjusted EBITDA (1)	$	9,654

Operating cash flow provided by continuing operations	$	12,323
Investing cash flow used by continuing operations	$	(3,890	)
Financing cash flow used by continuing operations	$	(3,819	)
Distributable Cash Flow ("DCF") (1)	$	9,018


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

VantaCore’s construction aggregates mining and production business is largely dependent on the strength of the local markets that it serves and is also seasonal, with lower production and sales expected during the first quarter of each year due to winter weather. VantaCore’s Laurel Aggregates operation in southwestern Pennsylvania serves producers and oilfield service companies operating in the Marcellus and Utica Shales and was impacted during the first half of 2016 by the slowing pace of exploration and development of natural gas in those areas due to low natural gas prices. Increased local construction activity partially offset these declines during the six months ended June 30, 2016, but we expect that Laurel’s business will continue to be impacted by decreased natural gas development activities. In June 2015, VantaCore purchased a hard rock quarry operation located on the Tennessee River near Grand Rivers, Kentucky from one of NRP’s aggregates lessees that had previously idled the operation. This operation continues to lease reserves from NRP and sells its produced limestone aggregates in both the local market and downstream to river-based markets. While VantaCore's production and revenues have declined in 2016 compared to 2015, it's effective variable cost management strategies have enabled the business to maintain its 2016 net income within budget.

Oil and Gas Business Segment

On June 14, 2016, NRP Oil and Gas signed a definitive agreement to sell its non-operated oil and gas working interest assets in the Williston Basin for $116.1 million, subject to customary closing conditions and purchase price adjustments. In July 2016, NRP Oil and Gas closed this transaction. 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 aggregates, soda ash and coal and hard minerals business segments. As a result, we have classified the operating results and cash flows of our non-operated oil and gas working interest assets as discontinued operations in our consolidated statements of comprehensive income and consolidated statements of cash flows for all periods presented. Additionally, the related assets and liabilities associated with discontinued operations are classified as held for sale in our consolidated balance sheets. The assets and liabilities as of June 30, 2016 are classified as current in our consolidated balance sheet as we closed on the transaction in July 2016.

Management’s Forecast and Strategic Plan

Opco’s revolving credit facility has scheduled commitment reductions as described above and matures in June 2018 and NRP’s 9.125% Senior Notes mature in October 2018. We believe we need to significantly improve our leverage ratios prior to the maturity thereof in order to be able to refinance or restructure such debt. We remain committed to our strategic plan announced in April 2015 to improve our balance sheet and reduce leverage, and intend to take all necessary steps to execute on that plan, including through asset sales and other means. During the first quarter of 2016, we completed asset sales for $46.3 million in gross proceeds. In July 2016 we closed on the sale of our NRP Oil and Gas non-operated working interest assets in the Williston Basin for $116.1 million in gross proceeds and repaid the NRP Oil and Gas revolving credit facility in full. However, we believe deterioration in the commodity markets will continue to have a negative impact on our results of operations, which in turn may prevent us from achieving our leverage ratio goals including those in our debt agreement financial covenants. Historically, we have accessed the debt and equity capital markets on a regular basis and relied on bank credit facilities to finance our business activities. However, due to the current commodity price environment and the state of the coal markets in particular, we believe we do not currently have the ability to access either the traditional debt or equity capital markets. In addition, the volatility in the energy industry combined with recent bankruptcies and additional perceived credit risks of companies with coal and/or oil and gas exposure has resulted in traditional bank lenders seeking to reduce or eliminate their lending exposure to these companies. Accordingly, we will be required over the near term to run our business and service our debt through cash from operations or asset sales. In addition, we may be required to seek financing from non-traditional sources at unfavorable pricing or with unfavorable terms to run our business or to refinance or restructure our 2018 debt maturities.

While NRP has a diversified portfolio of assets and a history and continued forecast of profitable operations with positive operating cash flows, its operating results and credit metrics continue to be impacted by demand challenges for coal. In particular, as described in Note 8. Debt and Debt—Affiliate, Opco, a wholly owned subsidiary of NRP, has debt agreements that contain customary financial covenants, including maintenance covenants, and other covenants. In addition, NRP has issued $425 million of 9.125% Senior Notes that are governed by an indenture (the "Indenture") containing customary incurrence-based financial covenants and other covenants, but not maintenance covenants. In July 2016, NRP Oil and Gas LLC, a wholly owned subsidiary, closed the sale of its Williston Basin non-operated working interest assets and used a portion of the proceeds to repay the RBL Facility in full. The following discussion presents management’s going concern analysis in light of management’s outlook and strategic plan to address its debt covenant compliance and maturities.

As of June 30, 2016, Opco had $260.0 million of indebtedness outstanding under the Opco Credit Facility with scheduled commitment reductions of $50.0 million on December 31, 2016, $30.0 million on June 30, 2017, $30.0 million on December 31, 2017 and the remaining $150 million on June 30, 2018. In addition, as of June 30, 2016 Opco had $537.6 million outstanding under the Opco Senior Notes with scheduled principal payments of $80.8 million through June 30, 2017 (collectively referred to as the "Opco Debt agreements"). The maximum leverage ratio under the Opco Debt agreements is required not to exceed 4.0x. In addition, the Opco Debt agreements contain 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. Opco's leverage ratio was 2.84x at June 30, 2016. The agreements governing the Opco Senior Notes also include a covenant that provides that, in the event Opco or any of its subsidiaries are subject to any additional or more restrictive covenants under the agreements governing its material indebtedness (including the Opco Credit Facility), such covenants shall be deemed to be incorporated by reference in the Opco Senior notes and the holders of the Opco Senior Notes shall receive the benefit of such additional or more restrictive covenants to the same extent as the lenders under such material indebtedness agreement. Certain holders of the Opco Senior Notes have communicated to us that they believe they are entitled to consideration under this provision in connection with the First Amendment to the Opco Credit Facility. We are evaluating the noteholders’ assertions and are in active discussions with them.

Our going concern analysis includes an evaluation of relevant conditions and events including the Partnership's ability to meet its obligations and remain in compliance with its debt covenants over the next twelve months. We currently forecast that we will meet the Partnership's obligations, that we will be in compliance with all of the covenants under the Opco Debt agreements and that we will continue as a going concern. However, breaches of the Opco Debt agreement covenants that are not waived or cured, to the extent possible, would result in an event of default under the Opco Debt agreements, and if such debt is accelerated by the lenders thereunder, such acceleration would also result in a cross-default under the Indenture. We are currently pursuing or considering a number of actions in order to mitigate the effects of adverse market developments which could otherwise cause us to breach financial covenants under the Opco Debt agreements. These actions include (i) dispositions of assets, (ii) actively managing our debt capital structure through a number of potential alternatives, including exchange offers and non-traditional debt and equity financing, (iii) minimizing our capital expenditures, (iv) obtaining waivers or amendments from our lenders, (v)

effectively managing our working capital, (vi) improving our cash flows from operations and (vii) engaging legal and financial advisers to assist us in this process.

Results of Operations

Three Months Ended June 30, 2016 Compared to Three Months Ended Ended June 30, 2015

Revenues and Other Income

Revenues and other income decreased $5.5 million, or 4%, from $123.7 million in the three months ended June 30, 2015 to $118.2 million in the three months ended June 30, 2016. The following table shows our diversified sources of revenues and other income by business segment for the three months ended June 30, 2016 and 2015 (in thousands except for percentages):



	Coal and Hard Mineral Royalty and Other			Soda Ash			VantaCore			Oil and Gas			Total
2016
Revenues and other income	$	76,463		$	10,188		$	31,651		$	(56	)	$	118,246
Percentage of total	64		%	9		%	27		%	—		%
2015
Revenues and other income	$	70,150		$	11,599		$	41,042		$	892		$	123,683
Percentage of total	57		%	9		%	33		%	1		%

The changes in revenue and other income is discussed for each of the Partnership's business segments below:

Coal and Hard Mineral Royalty and Other

Revenues and other income related to our Coal and Hard Mineral Royalty and Other segment increased $6.3 million, or 9%, from $70.2 million in the three months ended June 30, 2015 to $76.5 million in the three months ended June 30, 2016.

The table below presents coal royalty production and revenues (including affiliates) derived from our major coal producing regions, hard mineral royalty income and the significant categories of other coal and hard mineral royalty and other revenues:



	For the Three Months Ended June 30,					Increase (Decrease)			Percentage Change
	2016			2015		Increase (Decrease)			Percentage Change
	(In thousands, except percent and per ton data) (Unaudited)
Coal royalty production (tons)
Appalachia
Northern (1)	(138		)	4,318		(4,456		)	(103	)%
Central	3,470			4,376		(906		)	(21	)%
Southern	773			1,174		(401		)	(34	)%
Total Appalachia	4,105			9,868		(5,763		)	(58	)%
Illinois Basin	1,909			2,960		(1,051		)	(36	)%
Northern Powder River Basin	442			892		(450		)	(50	)%
Gulf Coast	—			300		(300		)	(100	)%
Total coal royalty production	6,456			14,020		(7,564		)	(54	)%

Average coal royalty revenue per ton
Appalachia
Northern	N/A ⁽¹⁾			$	0.16	N/A ⁽¹⁾			N/A ⁽¹⁾
Central	3.13			4.04		(0.91		)	(23	)%
Southern	3.36			4.60		(1.24		)	(27	)%
Total Appalachia	3.39			2.41		0.98			41	%
Illinois Basin	3.76			3.90		(0.14		)	(4	)%
Northern Powder River Basin	3.05			2.32		0.73			31	%
Gulf Coast	—			3.49		(3.49		)	(100	)%
Combined average coal royalty revenue per ton	3.48			2.74		0.74			27	%

Coal royalty revenues
Appalachia
Northern (1)	$	463		$	708	$	(245	)	(35	)%
Central	10,864			17,670		(6,806		)	(39	)%
Southern	2,598			5,399		(2,801		)	(52	)%
Total Appalachia	13,925			23,777		(9,852		)	(41	)%
Illinois Basin	7,181			11,538		(4,357		)	(38	)%
Northern Powder River Basin	1,348			2,071		(723		)	(35	)%
Gulf Coast	—			1,047		(1,047		)	(100	)%
Total coal royalty revenue	$	22,454		$	38,433	$	(15,979	)	(42	)%

Other Coal and Hard Mineral Royalty and Other revenues
Override revenue	$	657		$	1,071	$	(414	)	(39	)%
Transportation and processing fees	5,302			6,465		(1,163		)	(18	)%
Minimums recognized as revenue	43,527			4,706		38,821			825	%
Gain on reserve swap	—			9,290		(9,290		)	(100	)%
Wheelage	465			939		(474		)	(50	)%
Hard mineral royalty revenues	603			2,261		(1,658		)	(73	)%
Gain on asset sales	67			3,056		(2,989		)	(98	)%
Property tax revenue	3,027			3,070		(43		)	(1	)%
Other	361			859		(498		)	(58	)%
Total other Coal and Hard Mineral Royalty and Other revenue	$	54,009		$	31,717	$	22,292		70	%
Total Coal and Hard Mineral Royalty and Other revenue	$	76,463		$	70,150	$	6,313		9	%

(1) Northern Appalachia was impacted by a prior period adjustment of 0.4 million tons and less than $0.1 million in royalty revenue related to the Hibbs Run mine that ceased production during 2016. Absent this adjustment, production in the Northern Appalachia region was 0.2 million tons, average revenue per ton was $2.08 and revenue was $0.4 million.

Total coal production decreased 7.5 million tons, or 54%, from 14.0 million tons in the three months ended June 30, 2015 to 6.5 million tons in the three months ended June 30, 2016. Total coal royalty revenues decreased $15.9 million, or 42%, from $38.4 million in the three months ended June 30, 2015 to $22.5 million in the three months ended June 30, 2016. Total production decreased in all of our regions, with a corresponding decrease in revenue in all regions. Total revenues and other income within the segment increased as a result of several lease modifications and terminations in the second quarter of 2016 that more than offset the decrease in coal royalty revenues.

Soda Ash

Revenues and other income related to our Soda Ash segment decreased $1.4 million, or 12%, from $11.6 million in the three months ended June 30, 2015 to $10.2 million in the three months ended June 30, 2016. This decrease is primarily related to lower domestic and international prices compared to the prior year.

VantaCore

Revenues and other income related to our VantaCore segment decreased $9.3 million, or 23%, from $41.0 million in the three months ended June 30, 2015 to $31.7 million in the three months ended June 30, 2016. This decrease is primarily due to a reduction in brokered stone revenue as well as reduced delivery and fuel income quarter-over-quarter. This decrease was partially offset by an increase in construction revenue. Tonnage sold by the VantaCore segment decreased 0.2 million tons, or 10% from 2.0 million tons in the three months ended June 30, 2015 to 1.8 million tons in the three months ended June 30, 2016.

Operating and Maintenance Expenses (including affiliates)

Operating and maintenance expenses (including affiliates) decreased $8.1 million, or 20%, from $40.3 million in the three months ended June 30, 2015 to $32.2 million in the three months ended June 30, 2016. This decrease is primarily related to the following:

VantaCore

Operating and maintenance expenses (including affiliates) in our VantaCore segment decreased $8.1 million, or 25% from $32.6 million in the three months ended June 30, 2015 to $24.5 million in the three months ended June 30, 2016. This decrease is primarily due to effective variable cost management and the decline in materials cost as a result of the decrease in brokered stone volume quarter-over-quarter.

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

DD&A expense decreased $7.9 million, or 41%, from $19.1 million in the three months ended June 30, 2015 to $11.2 million in the three months ended June 30, 2016. This decrease is primarily related to the reduction of the cost basis of our coal and aggregate mineral rights due to the asset impairments recorded in the third and fourth quarters of 2015 and the decline in production quarter-over-quarter.

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

Corporate and financing G&A expense (including affiliates) includes corporate headquarters, financing and centralized treasury and accounting. These costs increased $1.8 million, or 82%, from $2.2 million in the three months ended June 30, 2015 to $4.0 million in the three months ended June 30, 2016. This increase is primarily related to increased legal and advisory fees related to the implementation of our long-term plan to strengthen our balance sheet, reduce debt and enhance liquidity in order to reposition the Partnership for future growth.

Income (Loss) from Discontinued Operations

Loss from discontinued operations decreased $1.6 million, or 42%, from a loss of $3.8 million in the three months ended June 30, 2015 to a loss of $2.2 million in the three months ended June 30, 2016. This decrease is primarily related to less DD&A expense in the three months ended June 30, 2016 as compared to 2015 as a result of the reduction of the cost basis of our oil and gas mineral rights due to the asset impairments recorded in the third and fourth quarters of 2015 and the decline in production quarter-over-quarter. This decrease was partially offset by reduced oil and gas revenue due to decline in production and price quarter-over-quarter.

Adjusted EBITDA (a 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, gain on reserve swaps and income to non-controlling interest; plus distributions from equity earnings in unconsolidated investment, interest 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.

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.

Adjusted EBITDA increased $10.4 million, or 15%, from $71.2 million in the three months ended June 30, 2015 to $81.6 million in the three months ended June 30, 2016. The increase is primarily related to an increase in Coal and Hard Mineral Royalty and Other net income, partially offset by lower depreciation expense within each segment quarter-over-quarter.

The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment for the three months ended June 30, 2016 and 2015:



	Operating Segments
For the Three Months Ended	Coal and Hard Mineral Royalty and Other			Soda Ash			VantaCore		Oil and Gas			Corporate and Financing			Total
June 30, 2016
Net income (loss) from continuing operations	$	61,675		$	10,188		$	3,439	$	(522	)	$	(26,147	)	$	48,633
Less: equity earnings from unconsolidated investment	—			(10,188		)	—		—			—			(10,188		)
Add: distributions from unconsolidated investment	—			9,800			—		—			—			9,800
Add: depreciation, depletion and amortization	7,308			—			3,690		178			—			11,176
Add: asset impairment	91			—			—		—			—			91
Add: interest expense	—			—			—		—			22,115			22,115
Adjusted EBITDA	$	69,074		$	9,800		$	7,129	$	(344	)	$	(4,032	)	$	81,627

June 30, 2015
Net income (loss) from continuing operations	$	46,528		$	11,599		$	3,613	$	(1,197	)	$	(24,154	)	$	36,389
Less: equity earnings from unconsolidated investment	—			(11,599		)	—		—			—			(11,599		)
Less: gain on reserve swap	(9,290		)	—			—		—			—			(9,290		)
Add: distributions from unconsolidated investment	—			10,902			—		—			—			10,902
Add: depreciation, depletion and amortization	12,749			—			4,865		1,463			—			19,077
Add: asset impairment	3,803			—			—		—			—			3,803
Add: interest expense	—			—			—		—			21,936			21,936
Adjusted EBITDA	$	53,790		$	10,902		$	8,478	$	266		$	(2,218	)	$	71,218

Distributable Cash Flow, or "DCF" (a Non-GAAP Financial Measure)

DCF is a non-GAAP financial measure that we define as net cash provided by operating activities of continuing operations, plus returns of unconsolidated equity investments, proceeds from sales of assets, and returns of long-term contract receivables—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.

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 unitholders and our general partner and repay debt.

DCF decreased $19.9 million, or 44%, from $45.2 million in the three months ended June 30, 2015 to $25.3 million in the three months ended June 30, 2016. This decrease is due primarily to lower coal royalty production and less minimum payments received from our coal leases.

The following table (in thousands) presents the three major categories of the statement of cash flows by business segment for the three months ended June 30, 2016 and 2015:



	Operating Segments
For the Three Months Ended	Coal and Hard Mineral Royalty and Other			Soda Ash			VantaCore			Oil and Gas			Corporate and Financing			Total
June 30, 2016
Net cash provided by (used in) operating activities of continuing operations	$	32,610		$	17,032		$	6,210		$	1,110		$	(33,773	)	$	23,189
Net cash provided by (used in) investing activities of continuing operations	$	2,685		$	—		$	(1,672	)	$	1,499		$	—		$	2,512
Net cash provided by (used in) financing activities of continuing operations	$	(47,102	)	$	(17,029	)	$	(2,604	)	$	(2,580	)	$	14,385		$	(54,930	)

June 30, 2015
Net cash provided by (used in) operating activities of continuing operations	$	63,071		$	11,567		$	6,625		$	1,435		$	(39,312	)	$	43,386
Net cash provided by (used in) investing activities of continuing operations	$	5,176		$	—		$	(3,658	)	$	(337	)	$	—		$	1,181
Net cash provided by (used in) financing activities of continuing operations	$	(71,451	)	$	(11,567	)	$	(3,765	)	$	(10,506	)	$	29,847		$	(67,442	)

The following table (in thousands) reconciles net cash provided by operating activities of continuing operations (the most comparable GAAP financial measure) by business segment to DCF for the three months ended June 30, 2016 and 2015:



	Operating Segments
For the Three Months Ended	Coal and Hard Mineral Royalty and Other			Soda Ash		VantaCore			Oil and Gas			Corporate and Financing			Total
June 30, 2016
Net cash provided by (used in) operating activities of continuing operations	$	32,610		$	17,032	$	6,210		$	1,110		$	(33,773	)	$	23,189
Add: return on long-term contract receivables—affiliate	1,871			—		—			—			—			1,871
Add: proceeds from sale of PP&E	819			—		21			—			—			840
Add: proceeds from sale of mineral rights	—			—		—			1,499			—			1,499
Less: maintenance capital expenditures	—			—		(2,079		)	—			—			(2,079		)
DCF	$	35,300		$	17,032	$	4,152		$	2,609		$	(33,773	)	$	25,320

June 30, 2015
Net cash provided by (used in) operating activities of continuing operations	$	63,071		$	11,567	$	6,625		$	1,435		$	(39,312	)	$	43,386
Add: proceeds from sale of PP&E	4,350			—		—			—			—			4,350
Add: proceeds from sale of mineral rights	539			—		—			—			—			539
Less: maintenance capital expenditures	158			—		(1,120		)	—			—			(962		)
Less: distributions to non-controlling interest	(1,041		)	—		—			(1,041		)	—			(2,082		)
DCF	$	67,077		$	11,567	$	5,505		$	394		$	(39,312	)	$	45,231

Results of Operations

Six Months Ended June 30, 2016 Compared to Six Months Ended Ended June 30, 2015

Revenues and Other Income

Revenues and other income decreased $5.6 million, or 3%, from $219.7 million in the six months ended June 30, 2015 to $214.1 million in the six months ended June 30, 2016. The following table shows our diversified sources of revenues and other income by business segment for the six months ended June 30, 2016 and 2015 (in thousands except for percentages):



	Coal and Hard Mineral Royalty and Other			Soda Ash			VantaCore			Oil and Gas			Total
2016
Revenues and other income	$	117,098		$	19,989		$	56,333		$	20,653		$	214,073
Percentage of total	55		%	9		%	26		%	10		%
2015
Revenues and other income	$	125,275		$	24,122		$	67,841		$	2,507		$	219,745
Percentage of total	57		%	11		%	31		%	1		%

The changes in revenue and other income is discussed for each of the Partnership's business segments below:

Coal and Hard Mineral Royalty and Other

Revenues and other income related to our Coal and Hard Mineral Royalty and Other segment decreased $8.2 million, or 7%, from $125.3 million in the six months ended June 30, 2015 to $117.1 million in the three months ended June 30, 2016.



	For the Six Months Ended June 30,					Increase (Decrease)			Percentage Change
	2016		2015			Increase (Decrease)			Percentage Change
	(In thousands, except percent and per ton data) (Unaudited)
Coal royalty production (tons)
Appalachia
Northern	1,292		6,063			(4,771		)	(79	)%
Central	6,698		8,760			(2,062		)	(24	)%
Southern	1,518		2,149			(631		)	(29	)%
Total Appalachia	9,508		16,972			(7,464		)	(44	)%
Illinois Basin	3,637		5,543			(1,906		)	(34	)%
Northern Powder River Basin	1,416		2,196			(780		)	(36	)%
Gulf Coast	—		417			(417		)	(100	)%
Total coal royalty production	14,561		25,128			(10,567		)	(42	)%

Average coal royalty revenue per ton
Appalachia
Northern	$	1.27	$	0.22		$	1.05		477	%
Central	3.19		4.02			(0.83		)	(21	)%
Southern	3.16		4.69			(1.53		)	(33	)%
Total Appalachia	2.92		2.75			0.17			6	%
Illinois Basin	3.54		3.97			(0.43		)	(11	)%
Northern Powder River Basin	2.82		2.54			0.28			11	%
Gulf Coast	—		3.50			(3.50		)	(100	)%
Combined average coal royalty revenue per ton	3.07		3.01			0.06			2	%

Coal royalty revenues
Appalachia
Northern	$	1,635	$	1,342		$	293		22	%
Central	21,337		35,176			(13,839		)	(39	)%
Southern	4,800		10,085			(5,285		)	(52	)%
Total Appalachia	27,772		46,603			(18,831		)	(40	)%
Illinois Basin	12,867		22,005			(9,138		)	(42	)%
Northern Powder River Basin	4,000		5,578			(1,578		)	(28	)%
Gulf Coast	—		1,459			(1,459		)	(100	)%
Total coal royalty revenue	$	44,639	$	75,645		$	(31,006	)	(41	)%

Other Coal and Hard Mineral Royalty and Other revenues
Override revenue	$	867	$	1,762		$	(895	)	(51	)%
Transportation and processing fees	9,536		11,062			(1,526		)	(14	)%
Minimums recognized as revenue	50,492		9,246			41,246			446	%
Gain on reserve swap	—		9,290			(9,290		)	(100	)%
DOH sale	268		1,665			(1,397		)	(84	)%
Wheelage	878		1,716			(838		)	(49	)%
Hard mineral royalty revenues	1,494		4,434			(2,940		)	(66	)%
Gain on asset sales	1,656		4,671			(3,015		)	(65	)%
Property tax revenue	6,332		6,074			258			4	%
Other	936		(290		)	1,226			(423	)%
Total other Coal and Hard Mineral Royalty and Other revenue	$	72,459	$	49,630		$	22,829		46	%
Total Coal and Hard Mineral Royalty and Other revenue	$	117,098	$	125,275		$	(8,177	)	(7	)%

Total coal production decreased 10.5 million tons, or 42%, from 25.1 million tons in the six months ended June 30, 2015 to 14.6 million tons in the six months ended June 30, 2016. Total coal royalty revenues decreased $31.0 million, or 41%, from $75.6 million in the six months ended June 30, 2015 to $44.6 million in the six months ended June 30, 2016. Total production decreased in all of our regions, with a corresponding decrease in revenue in all but the Northern Appalachia region. Revenue in the Northern Appalachia region increased as a result of decreased production on a lease with a lower royalty rate, offset by increased production

on leases with a higher per ton rate. The decrease in coal royalty revenues was partially offset by an increase in minimums recognized as revenues due to several lease modifications and terminations in the second quarter of 2016.

Soda Ash

Revenues and other income related to our Soda Ash segment decreased $4.1 million, or 17%, from $24.1 million in the six months ended June 30, 2015 to $20.0 million in the six months ended June 30, 2016. This decrease is primarily related to lower domestic and international prices compared to the prior year.

VantaCore

Revenues and other income related to our VantaCore segment decreased $11.5 million, or 17%, from $67.8 million in the six months ended June 30, 2015 to $56.3 million in the six months ended June 30, 2016. This decrease is primarily due to a reduction in brokered stone revenue as well as reduced delivery and fuel income quarter-over-quarter. This decrease was partially offset by an increase in construction revenue. Tonnage sold by the VantaCore segment decreased 0.3 million tons, or 9% from 3.5 million tons in the six months ended June 30, 2015 to 3.2 million tons in the six months ended June 30, 2016.

Oil and Gas

Revenues and other income related to our Oil and Gas segment increased $18.2 million from $2.5 million in the six months ended June 30, 2015 to $20.7 million in the six months ended June 30, 2016. This increase was primarily due to a $19.2 million gain recorded on the sale of our oil and gas royalty assets, partially offset by lower royalty revenues year-over-year.

Operating and Maintenance Expenses (including affiliates)

Operating and maintenance expenses (including affiliates) decreased $12.4 million, or 17%, from $74.9 million in the six months ended June 30, 2015 to $62.5 million in the six months ended June 30, 2016. This decrease is primarily related to the following:

VantaCore

Operating and maintenance expenses (including affiliates) in our VantaCore segment decreased $11.4 million, or 20% from $58.0 million in the six months ended June 30, 2015 to $46.6 million in the six months ended June 30, 2016. This decrease is primarily due to the decline in materials cost as a result of the decrease in brokered stone volume year-over-year.

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

DD&A expense decreased $8.9 million, or 29%, from $30.6 million in the six months ended June 30, 2015 to $21.7 million in the six months ended June 30, 2016. This decrease is primarily related to the reduction in the cost basis of our coal and aggregate mineral rights due to the asset impairments recorded in the third and fourth quarters of 2015 and the decline in production.

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 $2.6 million, or 46%, from $5.6 million in the six months ended June 30, 2015 to $8.2 million in the six months ended June 30, 2016. This increase is primarily related to increased legal and consulting fees related to the implementation of our long-term plan to strengthen our balance sheet, reduce debt and enhance liquidity in order to reposition the Partnership for future growth.

Income (Loss) from Discontinued Operations

Loss from discontinued operations decreased $5.6 million, or 52%, from a loss of $10.7 million in the six months ended June 30, 2015 to a loss of $5.1 million in the six months ended June 30, 2016. This decrease is primarily related to less DD&A expense in the six months ended June 30, 2016 as compared to 2015 as a result of the reduction of the cost basis of our oil and gas mineral rights due to the asset impairments recorded in the third and fourth quarters of 2015 and the decline in production year-over-year. This decrease was partially offset by reduced oil and gas revenue due to decline in production and price year-over-year.

Adjusted EBITDA (a Non-GAAP Financial Measure)

Adjusted EBITDA increased $17.9 million, or 14%, from $127.6 million in the six months ended June 30, 2015 to $145.5 million in the six months ended June 30, 2016. The increase is primarily related to the $19.2 million gain on the sale of certain oil and gas royalty properties and was partially offset by lower net income from our Coal and Hard Mineral Royalty and Other segment due to reduced production. See "—Three Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015—Adjusted EBITDA (a Non-GAAP Financial Measure)" for explanation of Adjusted EBITDA.



	Operating Segments
For the Six Months Ended	Coal and Hard Mineral Royalty and Other			Soda Ash			VantaCore		Oil and Gas			Corporate and Financing			Total
June 30, 2016
Net income (loss) from continuing operations	$	86,277		$	19,989		$	2,402	$	19,275		$	(52,959	)	$	74,984
Less: equity earnings from unconsolidated investment	—			(19,989		)	—		—			—			(19,989		)
Add: distributions from unconsolidated investment	—			22,050			—		—			—			22,050
Add: depreciation, depletion and amortization	14,069			—			7,252		357			—			21,678
Add: asset impairment	1,984			—			—		—			—			1,984
Add: interest expense	—			—			—		—			44,774			44,774
Adjusted EBITDA	$	102,330		$	22,050		$	9,654	$	19,632		$	(8,185	)	$	145,481

June 30, 2015
Net income (loss) from continuing operations	$	83,223		$	24,122		$	1,122	$	1,946		$	(49,645	)	$	60,768
Less: equity earnings from unconsolidated investment	—			(24,122		)	—		—			—			(24,122		)
Less: gain on reserve swap	(9,290		)	—			—		—			—			(9,290		)
Add: distributions from unconsolidated investment	—			21,805			—		—			—			21,805
Add: depreciation, depletion and amortization	22,765			—			8,721		(895		)	—			30,591
Add: asset impairment	3,803			—			—		—			—			3,803
Add: interest expense	—			—			—		—			44,071			44,071
Adjusted EBITDA	$	100,501		$	21,805		$	9,843	$	1,051		$	(5,574	)	$	127,626

DCF (a Non-GAAP Financial Measure)

DCF decreased $5.8 million, or 7%, from $88.3 million in the six months ended June 30, 2015 to $82.5 million in the six months ended June 30, 2016. This decrease is due primarily to lower cash provided by operations from our coal and hard mineral royalty and other segment as a result of to lower coal royalty production and less minimum payments received from our coal leases, partially offset by $44.1 million net cash proceeds received from the sales of our oil and gas and aggregates royalty assets. See "—Three Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015—DCF (a Non-GAAP Financial Measure)" for explanation of DCF.

The following table (in thousands) presents the three major categories of the statement of cash flows by business segment for the six months ended June 30, 2016 and 2015:



	Operating Segments
For the Six Months Ended	Coal and Hard Mineral Royalty and Other			Soda Ash			VantaCore			Oil and Gas			Corporate and Financing			Total
June 30, 2016
Net cash provided by (used in) operating activities of continuing operations	$	55,908		$	22,050		$	12,323		$	467		$	(52,102	)	$	38,646
Net cash provided by (used in) investing activities of continuing operations	$	12,796		$	—		$	(3,890	)	$	34,347		$	—		$	43,253
Net cash provided by (used in) financing activities of continuing operations	$	(93,161	)	$	(22,050	)	$	(3,819	)	$	(45,205	)	$	62,523		$	(101,712	)

June 30, 2015
Net cash provided by (used in) operating activities of continuing operations	$	109,250		$	18,016		$	13,942		$	202		$	(56,393	)	$	85,017
Net cash provided by (used in) investing activities of continuing operations	$	7,461		$	—		$	(4,360	)	$	(337	)	$	—		$	2,764
Net cash provided by (used in) financing activities of continuing operations	$	(152,192	)	$	(18,016	)	$	(10,907	)	$	(11,610	)	$	64,777		$	(127,948	)

The following table (in thousands) reconciles net cash provided by operating activities (the most comparable GAAP financial measure) by business segment to DCF for the six months ended June 30, 2016 and 2015:



	Operating Segments
For the Six Months Ended	Coal and Hard Mineral Royalty and Other			Soda Ash		VantaCore			Oil and Gas			Corporate and Financing			Total
June 30, 2016
Net cash provided by (used in) operating activities of continuing operations	$	55,908		$	22,050	$	12,323		$	467		$	(52,102	)	$	38,646
Add: return on long-term contract receivables—affiliate	2,180			—		—			—			—			2,180
Add: proceeds from sale of PP&E	819			—		24			—			—			843
Add: proceeds from sale of mineral rights	9,802			—		—			34,347			—			44,149
Less: maintenance capital expenditures	—			—		(3,329		)	—			—			(3,329		)
DCF	$	68,709		$	22,050	$	9,018		$	34,814		$	(52,102	)	$	82,489

June 30, 2015
Net cash provided by (used in) operating activities of continuing operations	$	109,250		$	18,016	$	13,942		$	202		$	(56,393	)	$	85,017
Add: return on long-term contract receivables—affiliate	1,137			—		—			—			—			1,137
Add: proceeds from sale of PP&E	4,350			—		905			—			—			5,255
Add: proceeds from sale of mineral rights	1,845			—		—			—			—			1,845
Less: maintenance capital expenditures	—			—		(2,238		)	—			—			(2,238		)
Less: distributions to non-controlling interest	(1,372		)	—		—			(1,372		)	—			(2,744		)
DCF	$	115,210		$	18,016	$	12,609		$	(1,170	)	$	(56,393	)	$	88,272

Liquidity and Capital Resources

Overview

While we believe we have sufficient liquidity to meet our current financial needs we have significant debt service requirements as discussed in "—Executive Overview—Current Liquidity Position" above. We believe we need to significantly improve our leverage ratios prior to the maturity of the Opco Senior Notes and Opco's Revolving Credit Facility in order to be able to refinance or restructure such debt. We remain committed to our long-term strategic plan to improve our balance sheet and reduce leverage, and intend to take all necessary steps to execute on that plan, including asset sales and other means. From January 1, 2016 through the date of this filing, we completed asset sales for $156.3 million in net proceeds. However, we believe the adverse conditions in the commodity markets will continue to have a negative impact on our results of operations, which in turn may prevent us from achieving our leverage ratio goals including those included in our debt agreement financial covenants. Historically, we have accessed the debt and equity capital markets on a regular basis and have relied on bank credit facilities to finance our business activities. However, due to the current commodity price environment and the state of the coal markets in particular, we believe we do not currently have the ability to access either the traditional debt or equity capital markets. In addition, the volatility in the energy industry combined with recent bankruptcies and additional perceived credit risks of companies with coal exposure has resulted in traditional bank lenders seeking to reduce or eliminate their lending exposure to these companies. Accordingly, we will be required over the near term to run our business and service our debt through cash from operations or asset sales. In addition, we may be required to seek financing from non-traditional sources at unfavorable pricing or with unfavorable terms to run our business or to refinance or restructure our 2018 debt maturities.

While we have closed several asset sale transactions, if we are unable to complete additional asset sales and conditions in the commodity markets continue to deteriorate, our liquidity and our ability to comply with the financial and other restrictive covenants contained in our debt agreements will be adversely affected. See "—Management's Forecast and Strategic Plan" above.

Generally, we satisfy our working capital requirements with cash generated from operations. Our current liabilities exceeded our current assets by approximately $81.2 million as of June 30, 2016, primarily due to $161.0 million in principal payments on the Opco Senior Notes and in scheduled commitment reductions on the Opco Credit Facility. Excluding these payments, net of their unamortized debt issue costs, our current assets exceeded our current liabilities by approximately $154.8 million as of June 30, 2016.

Capital Expenditures

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

Cash Flows

Operating activities of continuing operations provided $38.6 million and $85.0 million in cash for the six months ended June 30, 2016 and 2015, respectively. The majority of our cash provided by operations of continuing operations is generated from our coal royalty leases. Operating cash flow from continuing operations decreased $53.3 million in our Coal and Hard Mineral Royalty and Other segment primarily as a result of the reduction in coal royalty revenue and reduction of coal royalty minimum cash payments received on certain leases year-over-year. Cash flow provided by continuing operations in the Soda Ash segment increased as a result of increased distributions from Ciner Wyoming when compared to the six months ended June 30, 2015.

Investing activities of continuing operations provided $43.3 million in cash for the six months ended June 30, 2016 and $2.8 million for the six months ended June 30, 2015. During the first half of 2016, our investing activities of continuing operations primarily consisted of $44.1 million in net proceeds received from the sale of certain hard mineral royalty and oil and gas royalty properties. These investing cash inflows of continuing operations were partially offset by $3.9 million in plant and equipment acquisitions within our VantaCore segment. During the first half of 2015, our investing activities of continuing operations primarily consisted of proceeds received from the sale of our cell tower assets within the Coal and Hard Mineral Royalty and Other segment, partially offset by plant and equipment acquisitions within our VantaCore segment.

Net cash flows used in financing activities of continuing operations for the six months ended June 30, 2016 and 2015 was $101.7 million and $127.9 million, respectively. During the first half of 2016 we repaid $108.5 million in debt (including $10.0 million related to discontinued operations), distributed $11.2 million to our unitholders and paid our final contingent consideration payment to Anadarko related to the 2015 operating performance of Ciner Wyoming of $7.2 million. These cash outflows were partially offset by $20.0 million in loan proceeds during the first half of 2016. During the first half of 2015 our financing outflows primarily consisted of loan repayments of $68.5 million (including $10.0 million related to discontinued operations) and unitholder distributions of $54.9 million. These cash outflows were partially offset by $25.0 million in loan proceeds during the first half of 2015.

Capital Resources and Obligations

Indebtedness

As of June 30, 2016 and December 31, 2015 we had the following indebtedness (in thousands):



	June 30, 2016		December 31, 2015
Current portion of long-term debt, net	$	157,996	$	80,745
Long-term debt, net (including affiliate)	1,050,562		1,206,611
Total debt, net (including affiliate)	$	1,208,558	$	1,287,356

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 8. Debt and Debt—Affiliate to the consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q.

Shelf Registration Statement

In September 2015, we filed a registration statement on Form S-3 with the SEC that is available for registered offerings of common units.

Unrestricted Subsidiary Information

In February 2016, NRP designated NRP Oil and Gas as an Unrestricted Subsidiary for purposes of the Indenture. In addition, BRP LLC and its wholly owned subsidiary, Coval Leasing Company, LLC, are also Unrestricted Subsidiaries for purposes of the Indenture. For more information regarding the financial condition and results of operations of NRP and its Restricted Subsidiaries for purposes of the Indenture separate from NRP’s Unrestricted Subsidiaries for purposes of the Indenture, see Note 16. Supplementary Unrestricted Subsidiary Information under the Notes to Consolidated Financial Statements.

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 10. Related Party Transactions to the consolidated financial statements under the caption "Related Party Transactions" 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, 2015.

Recent Accounting Standards

The information set forth under Note 1. Basis of Presentation to the consolidated financial statements under the caption "Basis of Presentation" 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. We estimate that over 65% of our coal is currently sold by our lessees under coal supply contracts that have terms of one year or more. 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 the prices for oil and natural gas, NGLs and condensate. Management expects energy prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, a non-cash write-down of the Partnership’s oil and gas properties may be required if commodity prices experience a significant decline.

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 our revolving credit facility and term loan, which are subject to variable interest rates based upon LIBOR. At June 30, 2016, we had $335.0 million outstanding in variable interest rate debt. If interest rates were to increase by 1%, annual interest expense would increase approximately $3.4 million, assuming the same principal amount remained outstanding during the year.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Changes in the Partnership’s Internal Control Over Financial Reporting

There were no changes in the Partnership’s internal control over financial reporting during the first six months of 2016 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, see Note 11. "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, 2015.

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

None.

ITEM 3. DEFAULTES 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		Certificate of Limited Partnership of Natural Resource Partners L.P.(incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 filed April 19, 2002, File No. 333-86582).
3.2		Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of September 20, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on September 21, 2010).
3.3		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).
4.1		First Amendment, dated March 6, 2012, to the Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P. (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q filed on August 7, 2012).
10.1		First Amendment dated as of June 3, 2016 to Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent. (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 7, 2016).
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.
32.1**		Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.
32.2**		Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.
95.1*		Mine Safety Disclosure.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

*		Filed herewith
**		Furnished herewith

SIGNATURES

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



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

Date: August 4, 2016	By:	/s/ CORBIN J. ROBERTSON, JR.
		Corbin J. Robertson, Jr.
		Chairman of the Board and
		Chief Executive Officer
		(Principal Executive Officer)



Date: August 4, 2016	By:	/s/ CRAIG W. NUNEZ
		Craig W. Nunez
		Chief Financial Officer and
		Treasurer
		(Principal Financial Officer)



Date: August 4, 2016	By:	/s/ CHRISTOPHER J. ZOLAS
		Christopher J. Zolas
		Chief Accounting Officer
		(Principal Accounting Officer)