Edgar Filing: NATURAL RESOURCE PARTNERS LP

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________________________________

FORM 10-Q



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

For the quarterly period ended March 31, 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 May 1, 2016 there were 12.2 million 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 Cash Flows	3
	Consolidated Statements of Partners’ Capital	3
	Notes to Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4.	Controls and Procedures	37
Part II. Other Information
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 3.	Defaults Upon Senior Securities	39
Item 4.	Mine Safety Disclosure	39
Item 5.	Other Information	39
Item 6.	Exhibits	40
	Signatures	41

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except per unit data)



	March 31, 2016			December 31, 2015
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	52,097		$	51,773
Accounts receivable, net	48,154			50,167
Accounts receivable—affiliates	7,525			6,864
Inventory	7,406			7,835
Prepaid expenses and other	3,835			4,490
Total current assets	119,017			121,129
Land	25,022			25,022
Plant and equipment, net	57,444			61,239
Mineral rights, net	1,060,829			1,094,027
Intangible assets, net	3,701			3,930
Intangible assets, net—affiliate	52,274			52,997
Equity in unconsolidated investment	258,939			261,942
Long-term contracts receivable—affiliate	45,931			47,359
Other assets	1,204			1,266
Other assets—affiliate	532			1,124
Total assets	$	1,624,893		$	1,670,035
LIABILITIES AND CAPITAL
Current liabilities:
Accounts payable	$	7,595		$	8,465
Accounts payable—affiliates	1,227			1,464
Accrued liabilities	40,004			45,735
Current portion of long-term debt, net	154,441			80,745
Total current liabilities	203,267			136,409
Deferred revenue	76,750			80,812
Deferred revenue—affiliates	81,868			82,853
Long-term debt, net	1,146,958			1,270,281
Long-term debt, net—affiliate	19,936			19,930
Other non-current liabilities	5,839			6,808
Commitments and contingencies (see Note 10)
Partners’ capital:
Common unitholders’ interest (12.2 million units outstanding)	96,615			79,094
General partner’s interest	(249		)	(606		)
Accumulated other comprehensive loss	(2,697		)	(2,152		)
Total partners’ capital	93,669			76,336
Non-controlling interest	(3,394		)	(3,394		)
Total capital	90,275			72,942
Total liabilities and capital	$	1,624,893		$	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
	March 31,
	2016			2015
Revenues and other income:
Coal, hard mineral royalty and other	$	28,476		$	34,449
Coal, hard mineral royalty and other—affiliates	10,569			19,061
VantaCore	24,682			26,799
Oil and gas	7,298			14,779
Equity in earnings of Ciner Wyoming	9,801			12,523
Gain on asset sales	21,925			2,066
Total revenues and other income	102,751			109,677

Operating expenses:
Operating and maintenance expenses	30,902			37,421
Operating and maintenance expenses—affiliates, net	3,748			3,076
Depreciation, depletion and amortization	14,021			24,554
Amortization expense—affiliate	722			838
General and administrative	3,235			2,287
General and administrative—affiliates	937			1,084
Asset impairments	2,030			—
Total operating expenses	55,595			69,260

Income from operations	47,156			40,417

Other income (expense)
Interest expense	(23,748		)	(22,943		)
Interest income	19			15
Other expense, net	(23,729		)	(22,928		)

Net income	$	23,427		$	17,489

Net income attributable to partners:
Limited partners	23,024			17,139
General partner	403			350

Basic and diluted net income per common unit	$	1.88		$	1.40

Weighted average number of common units outstanding	12,230			12,230

Net income	$	23,427		$	17,489
Add: comprehensive loss from unconsolidated investment and other	(545		)	(965		)
Comprehensive income	$	22,882		$	16,524

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	12,230	$	79,094		$	(606	)	$	(2,152	)	$	76,336		$	(3,394	)	$	72,942
Distributions to unitholders	—	(5,503		)	(113		)	—			(5,616		)	—			(5,616		)
Net income	—	23,024			403			—			23,427			—			23,427
Non-cash contributions	—	—			67			—			67			—			67
Comprehensive loss from unconsolidated investment and other	—	—			—			(545		)	(545		)	—			(545		)
Balance at March 31, 2016	12,230	$	96,615		$	(249	)	$	(2,697	)	$	93,669		$	(3,394	)	$	90,275

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)



	Three Months Ended
	March 31,
	2016			2015
Cash flows from operating activities:
Net income	$	23,427		$	17,489
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	14,021			24,554
Amortization expense—affiliates	722			838
Distributions from equity earnings from unconsolidated investments	12,250			10,903
Asset impairment	2,030			—
Gain on asset sales	(21,925		)	(2,066		)
Equity earnings from unconsolidated investment	(9,801		)	(12,523		)
Other, net	1,887			1,056
Other, net—affiliates	664			7
Change in operating assets and liabilities:
Accounts receivable	5,782			15,110
Accounts receivable—affiliates	(661		)	3,643
Accounts payable	(48		)	(2,642		)
Accounts payable—affiliates	(237		)	(14		)
Accrued liabilities	(5,900		)	(5,354		)
Deferred revenue	(4,063		)	5,845
Deferred revenue—affiliates	(985		)	(738		)
Other items, net	1,146			103
Other items, net—affiliates	1,119			(739		)
Net cash provided by operating activities	19,428			55,472
Cash flows from investing activities:
Acquisition of mineral rights	(2,725		)	(16,788		)
Acquisition of plant and equipment and other	(2,221		)	(1,365		)
Proceeds from sale of plant and equipment and other	3			905
Proceeds from sale of oil and gas properties	32,848			3,395
Proceeds from sale of coal and hard mineral royalty properties	9,802			866
Return of long-term contract receivables—affiliate	309			1,137
Net cash provided by (used in) investing activities	38,016			(11,850		)
Cash flows from financing activities:
Proceeds from loans	—			25,000
Repayments of loans	(51,166		)	(41,166		)
Distributions to partners	(5,616		)	(43,678		)
Distributions to non-controlling interest	—			(662		)
Debt issue costs and other	(338		)	83
Net cash used in financing activities	(57,120		)	(60,423		)

Net increase (decrease) in cash and cash equivalents	324			(16,801		)
Cash and cash equivalents at beginning of period	51,773			50,076
Cash and cash equivalents at end of period	$	52,097		$	33,275

Supplemental cash flow information:
Cash paid during the period for interest	$	13,812		$	14,344
Plant, equipment and mineral rights funded with accounts payable or accrued liabilities	811			3,761

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 recasted 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. 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.

In our opinion, all adjustments, consisting only of normal recurring adjustments 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.

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 and excess worldwide supply of oil and gas. In particular, as described in Note 7. Debt and Debt—Affiliate, NRP Oil and Gas LLC ("NRP Oil and Gas") and NRP Operating LLC ("Opco"), both wholly owned subsidiaries of NRP, have 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. 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.

Opco

As of March 31, 2016, Opco had $290.0 million of indebtedness outstanding under its revolving credit facility due October 2017 (the "Opco Credit Facility") and $544.9 million outstanding under several series of Private Placement Notes (the "Opco Private Placement Notes") (collectively referred to as the "Opco Debt agreements"). The maximum leverage ratio under the Opco Debt agreements is required to be below 4.0x through March 31, 2016. Commencing with respect to the period ending June 30, 2016, the maximum leverage ratio reduces to 3.75x and reduces again to 3.5x commencing with respect to the period ending June 30, 2017. 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 3.09x at March 31, 2016.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

While we forecast that we will be in compliance with all of the covenants under the Opco Debt agreements through March 31, 2017, 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 further commodity price and market deterioration 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 financing, (iii) minimizing our capital expenditures, (iv) obtaining waivers or amendments from our lenders, (v) effectively managing our working capital and (vi) improving our cash flows from operations.

NRP Oil and Gas

NRP Oil and Gas had $75.0 million outstanding under its senior secured, reserve-based revolving credit facility (the "RBL Facility") as of March 31, 2016. The facility is secured by a first priority lien on substantially all of NRP Oil and Gas' assets and is not guaranteed by NRP or any other subsidiary of NRP.

In March 2016, NRP Oil and Gas entered into an amendment to the RBL Facility (the “Fourth Amendment”) that included a $10.0 million repayment of principal, a $13.0 million reduction in borrowing capacity, and the easing or temporary easing of certain covenant requirements. Please see "Note 7. Debt and Debt—Affiliate" for further detail of the Fourth Amendment. While the Fourth Amendment alleviated certain covenant compliance issues, it did not change the fact that our current forecast indicates that NRP Oil and Gas may not be able to meet its leverage ratio during the next 12 months and that the borrowing base under the RBL Facility will be reduced by an amount greater than what NRP Oil and Gas would have the ability to pay within the required period of time. As a result, we believe there is substantial doubt about the ability of NRP Oil and Gas to continue as a going concern through March 31, 2017. In order to address this issue, we have initiated a process to sell all of NRP Oil and Gas' non-operating working interest properties in the Williston Basin within the next twelve months. As of March 31, 2016, we have classified the RBL Facility as Current portion of long-term debt, net on the Partnership's Consolidated Balance Sheets.

An event of default under the RBL Facility and subsequent acceleration of that debt by the lenders thereunder would not result in a cross-default under the Indenture. NRP Oil and Gas is designated as an "Unrestricted Subsidiary" for purposes of the Indenture, which prevents an event of default under the RBL Facility and subsequent acceleration of that debt from triggering an event of default under the Indenture. In addition, there are no cross-defaults under the Opco Debt agreements as a result of a default under the RBL Facility. As a result, there would be no default or acceleration of indebtedness under the Indenture or under the Opco Debt agreements in the event NRP Oil and Gas is in default under the RBL Facility.

Reverse Unit Split

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.

Recently Issued Accounting Standards Not Yet Adopted

In May 2014, 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. This guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted for reporting periods beginning after December 15, 2016, including interim reporting periods within that period. This guidance can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial position, results of operations and cash flows.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

In August 2014, 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 guidance is effective for interim and annual periods ending after December 15, 2016 and early adoption is permitted. 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. The Partnership is reviewing its policies and processes to ensure compliance with this new guidance.

In July 2015, 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. The amendments do not apply to inventory that is measured using last-in, first-out or the retail inventory method. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with early adoption permitted. This guidance should be applied on a prospective basis. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial position, results of operations and cash flows.

In February 2016, the FASB issued authoritative lease guidance that establishes a right-of-use ("ROU") model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The main difference between the current requirement under GAAP and the ROU model is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial position, results of operations and cash flows.

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, 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 aggregates 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 non-operated working interests, royalty interests and overriding royalty interests in oil and natural gas properties. Our primary interests in oil and natural gas producing properties are non-operated working interests located in the Williston Basin in North Dakota and Montana. We also own fee mineral, royalty or 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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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 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.

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



	Operating Segments
For the Three Months Ended	Coal, Hard Mineral Royalty and Other		Soda Ash		VantaCore			Oil and Gas			Corporate and Financing			Total
For the three months ended March 31, 2016
Revenues (including affiliates)	$	39,045	$	9,801	$	24,682		$	7,298		$	—		$	80,826
Intersegment revenues (expenses)	21		—		(21		)	—			—			—
Gain on asset sales	1,590		—		—			20,335			—			21,925
Operating and maintenance expenses (including affiliates)	7,380		—		22,156			5,114			—			34,650
Depreciation, depletion and amortization	6,762		—		3,562			4,419			—			14,743
Asset impairment	1,893		—		—			137			—			2,030
Interest expense, net	—		—		—			—			(23,729		)	(23,729		)
Net income (loss)	24,600		9,801		(1,036		)	17,963			(27,901		)	23,427

For the three months ended March 31, 2015
Revenues (including affiliates)	$	53,510	$	12,523	$	26,799		$	14,779		$	—		$	107,611
Gain on asset sales	1,615		—		—			451			—			2,066
Operating and maintenance expenses (including affiliates)	8,414		—		25,434			6,649			—			40,497
Depreciation, depletion and amortization	10,016		—		3,856			11,520			—			25,392
Interest expense, net	—		—		—			—			(22,928		)	(22,928		)
Net income (loss)	36,695		12,523		(2,491		)	(2,939		)	(26,299		)	17,489

Total assets
March 31, 2016	1,016,827		258,939		196,720			132,324			20,083			1,624,893
December 31, 2015	1,047,922		261,942		200,348			158,862			961			1,670,035

3. 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 $12.3 million and $10.9 million to us in the three months ended March 31, 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 $153.6 million and $154.8 million as of March 31, 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

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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):



	Three Months Ended March 31,
	2016			2015
	(Unaudited)
Income allocation to NRP’s equity interests	$	10,996		$	13,727
Amortization of basis difference	(1,195		)	(1,204		)
Equity in earnings of unconsolidated investment	$	9,801		$	12,523

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



	Three Months Ended March 31,
	2016		2015
	(Unaudited)
Sales	$	114,384	$	120,430
Gross profit	28,251		32,724
Net Income	22,441		28,014

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



	March 31, 2016		December 31, 2015
	(Unaudited)
Current assets	$	139,185	$	144,695
Noncurrent assets	233,236		233,845
Current liabilities	46,881		43,018
Noncurrent liabilities	110,518		116,808

The purchase agreement for the acquisition of the Partnership’s interest in Ciner Wyoming, formerly OCI 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.

4. Plant and Equipment

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



	March 31, 2016			December 31, 2015
	(Unaudited)
Plant and equipment at cost	$	77,565		$	92,203
Construction in process	1,323			1,074
Less accumulated depreciation	(21,444		)	(32,038		)
Total plant and equipment, net	$	57,444		$	61,239

Depreciation expense related to the Partnership's plant and equipment totaled $3.4 million and $4.5 million for the three months ended March 31, 2016 and 2015, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

5. Mineral Rights

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



	March 31, 2016
	(Unaudited)
	Carrying Value		Accumulated Depletion			Net Book Value
Coal, Hard Mineral Royalty and Other	$	1,269,633	$	(437,628	)	$	832,005
VantaCore	112,700		(3,475		)	109,225
Oil and Gas	136,392		(16,793		)	119,599
Total	$	1,518,725	$	(457,896	)	$	1,060,829



	December 31, 2015
	Carrying Value		Accumulated Depletion			Net Book Value
Coal, Hard Mineral Royalty and Other	$	1,278,274	$	(432,260	)	$	846,014
VantaCore	112,700		(3,082		)	109,618
Oil and Gas	155,293		(16,898		)	138,395
Total	$	1,546,267	$	(452,240	)	$	1,094,027

Depletion expense related to the Partnership’s mineral rights totaled $10.3 million and $19.9 million for the three months ended March 31, 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 further commodity price and market deterioration 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 three months ended March 31, 2016:

1)Oil and gas royalty and overriding royalty interests in several producing properties located in the Appalachian Basin for $37.5 million. The effective date of the sale was January 1, 2016, and the Partnership recorded a $20.3 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.

6. 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.



	March 31, 2016			December 31, 2015
	(Unaudited)
Intangible assets—affiliate	$	81,109		$	81,109
Less accumulated amortization—affiliate	(28,835		)	(28,112		)
Total intangible assets, net—affiliate	$	52,274		$	52,997

Amortization expense related to the Partnership's intangible assets—affiliate totaled $0.7 million and $0.8 million for the three months ended March 31, 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):



	March 31, 2016			December 31, 2015
	(Unaudited)
Intangible assets	5,076			5,076
Less accumulated amortization	(1,375		)	(1,146		)
Total intangible assets, net	$	3,701		$	3,930

Amortization expense related to the Partnership's intangible assets totaled $0.2 million for both the three months ended March 31, 2016 and 2015.

7. Debt and Debt—Affiliate

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



	March 31, 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 October 2017	290,000			290,000
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018	13,850			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	960			1,153
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023	21,600			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	$	1,335,907		$	1,387,073
Net unamortized debt discount	(1,889		)	(2,077		)
Net unamortized debt issuance costs (1)	(12,683		)	(14,040		)
Total debt, net	$	1,321,335		$	1,370,956
Less: current portion of long-term debt	154,441			80,745
Total long-term debt	$	1,166,894		$	1,290,211


(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)

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 due 2018 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. As of March 31, 2016 and December 31, 2015, NRP was in compliance with the terms of the covenants contained under the Indenture.

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 March 31, 2016 and December 31, 2015, Opco was in compliance with the terms of the financial covenants contained in its debt agreements.

Revolving Credit Facility

In June 2015, Opco entered into a $300.0 million Third Amended and Restated Credit Agreement (the "A&R Revolving Credit Facility"), which amended and restated Opco’s $300.0 million Second Amended and Restated Credit Agreement due August 2016. The A&R Revolving Credit Facility matures on October 2, 2017, 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.

Initially, indebtedness under the A&R Revolving Credit Facility bore interest, at Opco's option, at a rate of either:


•	the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 1%, in each case plus 2.375%; or


•	a rate equal to LIBOR plus 3.375%

Subsequent to the delivery of financial statements for the year ended December 31, 2015 to the lenders in March 2016, indebtedness under the A&R Revolving Credit Facility bears interest, at Opco's option, at a rate of either:


•	the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 1%, in each case plus an applicable margin ranging from 1.50% to 2.50% or


•	a rate equal to LIBOR plus an applicable margin ranging from 2.50% to 3.50%

The weighted average interest rates for the borrowings outstanding under the A&R Revolving Credit Facility for the three months ended March 31, 2016 and 2015 were 3.80% and 1.94%, 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 A&R Revolving Credit Facility at any time without penalty.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The A&R Revolving Credit Facility contains financial covenants requiring Opco to maintain:


•	a leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the A&R Revolving Credit Facility) not to exceed:


◦	4.0 to 1.0 for each fiscal quarter ending on or before March 31, 2016;


◦	3.75 to 1.0 for each subsequent fiscal quarter ending on or before March 31, 2017; and


◦	3.5 to 1.0 for each fiscal quarter ending on or after June 30, 2017; and


•	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 March 31, 2016, Opco's leverage ratio was 3.09x, and fixed charge coverage ratio was 5.43x.

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

The A&R Revolving Credit Facility is collateralized and secured by liens on certain of Opco’s assets with a carrying values of $698.1 million and $709.9 million classified as Land, Mineral rights and Plant and equipment on the Partnership’s Consolidated Balance Sheet as of March 31, 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 March 31, 2016, and December 31, 2015, the Opco Senior Notes had cumulative principal balances of $544.9 million and $585.9 million, respectively. Opco made principal payments of $41.0 million on the Opco Senior Notes during each of the three months ended March 31, 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 March 31, 2016.

In connection with the entry into the A&R Revolving 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

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

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.

NRP Oil and Gas Debt

The RBL Facility

At March 31, 2016 and December 31, 2015, there was $75.0 million and $85.0 million respectively, outstanding under the RBL Facility. NRP Oil and Gas was in compliance with the terms of the covenants contained in the RBL Facility as of both March 31, 2016 and December 31, 2015.

In August 2013, NRP Oil and Gas entered into the RBL Facility, a 5-year, $100.0 million 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 owns non-operated working interests. In connection with the closing of the Sanish Field acquisition in November 2014, the RBL Facility was amended to increase its size to $500.0 million with an initial borrowing base of $137.0 million, and the maturity date thereof was extended to November 2019. The RBL Facility is secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. NRP Oil and Gas is the sole obligor under the RBL Facility, and neither the Partnership nor any of its other subsidiaries is a guarantor of the RBL Facility.

The maximum amount available under the RBL Credit Facility is subject to semi-annual redeterminations of the borrowing base in May and November of each year, based on the value of the proved oil and natural gas reserves of NRP Oil and Gas, in accordance with the lenders’ customary procedures and practices. NRP Oil and Gas and the lenders each have a right to one additional redetermination each year. In April 2015, the lenders completed their semi-annual redetermination of the borrowing base under the RBL Credit Facility and the $137.0 million borrowing base was redetermined to $105.0 million. In October 2015, the lenders under the RBL Credit Facility completed their semi-annual redetermination and the $105.0 million borrowing base was redetermined to $88.0 million. The Company repaid $25.0 million of outstanding borrowings under the RBL Credit Facility during the year ended December 31, 2015. At December 31, 2015, there was $85.0 million outstanding under the RBL Credit Facility.

In March 2016, the Company entered into an amendment to the RBL Facility (the “Fourth Amendment”) and repaid $10.0 million thereunder, which reduced the outstanding balance thereunder to $75.0 million. In connection with such repayment, the borrowing base under the RBL Facility was reduced from $88.0 million to $75.0 million in lieu of the May 2016 borrowing base redetermination. Per the Fourth Amendment, the borrowing base will be 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 will occur in November 2016.

The Fourth Amendment amends 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) will be increased from 3.5x to 4.0x at March 31, 2016 and 4.5x at June 30, 2016. Thereafter, the total leverage ratio will decrease to 3.5x for the remainder of the term of the RBL Facility.


•	The minimum current ratio will decrease from 1.0x to 0.75x at March 31, 2016 and June 30, 2016 and revert to 1.0x thereafter for the remainder of the term of the RBL Facility.

As of March 31, 2016, NRP Oil and Gas' leverage ratio was 3.10x, and current ratio was 1.94x.

In addition, effective on the date of the Fourth Amendment, indebtedness under the RBL Facility bears 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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

The Fourth Amendment contains 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 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 waives 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.

8. 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 Partnership used quotations obtained for comparable instruments on the closing trading prices near period end to determine the fair value of its contracts receivable—affiliate, which resulted in a Level 3 fair value measurement. The estimated fair value of the Partnership's contracts receivable—affiliate was $3.7 million and $4.2 million at March 31, 2016 and December 31, 2015, respectively.

The following table (in thousands) shows the face and estimated fair values of the Partnership's debt and debt—affiliate:



	March 31, 2016				December 31, 2015
	Debt at Face Value		Estimated Fair Value		Debt at Face Value		Estimated Fair Value
	(Unaudited)
NRP Senior Notes (1)	$	425,000	$	272,000	$	425,000	$	277,313
Opco Senior Notes and utility local improvement obligation (2)	545,907		349,380		587,073		383,065
Opco Revolving Credit Facility (3)	290,000		290,000		290,000		290,000
NRP Oil and Gas RBL Facility (3)	75,000		75,000		85,000		85,000


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


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


(3)	The Level 3 fair value approximates the 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.

9. Related Party Transactions

Reimbursements to Affiliates of our General Partner

The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for 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. 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

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Comprehensive Income.

The Partnership had Accounts payable—affiliates to Quintana Minerals Corporation of $0.6 million and $1.1 million at March 31, 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 $0.6 million and $0.3 million at March 31, 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 March 31,
	2016		2015
	(Unaudited)
Operating and maintenance expenses—affiliates, net	$	2,776	$	2,702
General and administrative—affiliates	937		1,084

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 them 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 March 31, 2016.

Coal related revenues from Foresight Energy totaled $10.1 million and $18.3 million for the three months ended March 31, 2016 and 2015, respectively. As of March 31, 2016 and December 31, 2015, the Partnership had Accounts receivable—affiliates from Foresight Energy of $7.4 million and $6.4 million, respectively. The Partnership had recorded $81.6 million and $82.6 million in minimum royalty payments as Deferred revenue—affiliates at March 31, 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 March 31, 2016 were $80.2 million with unearned income of $34.5 million, and the net amount receivable was $45.7 million, of which $2.1 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 $35.4 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 March 31, 2016 was $4.5 million, of which $2.2 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

Cline Trust Company, LLC owns approximately 0.54 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, each of which owns an approximately equal membership interest in the Cline Trust Company. 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 March 31, 2016 and is included in Long-term debt, net—affiliate on the accompanying Consolidated Balance Sheet.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Quintana Capital Group GP, Ltd.

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

At March 31, 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 $0.5 million and $0.8 million for the three months ended March 31, 2016 and 2015, respectively. The Partnership had recorded $0.3 million in minimum royalty payments as Deferred revenue—affiliates at both March 31, 2016 and December 31, 2015. The Partnership also had Accounts receivable—affiliates totaling $0.1 million and $0.2 million from Corsa at March 31, 2016 and December 31, 2015, respectively.

WPPLP Production Royalty and Overriding Royalty

For the three months ended March 31, 2016, the Partnership recorded $0.6 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. These charges were zero for the three months ended March 31, 2015. The Partnership had Other assets—affiliate from WPPLP of $0.5 million and $1.1 million at March 31, 2016 and December 31, 2015, respectively related to a non-production royalty receivable from WPPLP for overriding royalty interest on a mine.

10. Commitments and Contingencies

Legal

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

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. Given the early stage of this ongoing litigation, the Partnership currently cannot reasonably estimate a range of potential loss, if any, related to this matter.

Foresight Energy Disputes

On November 24, 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. 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 first quarter of 2016 resulted in a $23.6 million 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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

On April 1, 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 quarter of 2016 resulted in a $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 given the early stage of this ongoing litigation. It is possible that the Partnership’s current estimate of the valuation allowance related to this matter could change, perhaps materially, in the future.

11. Major Customers

Revenues from Foresight Energy represented $10.1 million, or 9.8% and $18.3 million, or 16.7% of total revenues and other income for the three months ended March 31, 2016 and 2015, respectively. The revenues from Foresight Energy are spread out over a number of different mining operations and leases. No other customers exceeded ten percent of total revenues and other income during the first quarter of 2016 or 2015.

12. 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 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	(3	)
Outstanding grants at March 31, 2016	95

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The Partnership recorded a credit to general and administrative expenses related to its Long-Term Incentive Plan of less than $0.1 million and $0.1 million for the three months ended March 31, 2016 and 2015, respectively, due to the decline in the market price of the Partnership's common units.

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 three months ended March 31, 2016 and 2015, respectively. The unaccrued cost associated with unvested outstanding grants and related DERs at March 31, 2016 and December 31, 2015, was $0.4 million and $0.7 million, respectively.

13. Cash Distributions

The following table shows the distributions paid by the Partnership during the three months ended March 31, 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
2015
February 13, 2015	October 1 - December 31, 2014	$	3.50	$	42,804	$	874	$	43,678

14. 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)



	March 31, 2016
	Unrestricted Subsidiaries of NRP			NRP and its Restricted Subsidiaries		Eliminations			Total
ASSETS
Current assets (including affiliates)	$	10,101		$	109,133	$	(217	)	$	119,017
Mineral rights, net	131,905			928,924		—			1,060,829
Equity in unconsolidated investment	—			258,939		—			258,939
Other non-current assets (including affiliates)	734			185,374		—			186,108
Total assets	$	142,740		$	1,482,370	$	(217	)	$	1,624,893
LIABILITIES AND CAPITAL
Current portion of long-term debt, net	$	73,696		$	80,745	$	—		$	154,441
Other current liabilities (including affiliates)	6,217			42,636		(27		)	48,826
Long-term debt, net (including affiliate)	—			1,166,894		—			1,166,894
Other non-current liabilities (including affiliates)	4,778			159,679		—			164,457
Partners' capital	61,494			32,365		(190		)	93,669
Non-controlling interest	(3,445		)	51		—			(3,394		)
Total liabilities and capital	$	142,740		$	1,482,370	$	(217	)	$	1,624,893

	December 31, 2015
	Unrestricted Subsidiaries of NRP			NRP and its Restricted Subsidiaries		Eliminations			Total
ASSETS
Current assets (including affiliates)	$	21,540		$	100,178	$	(589	)	$	121,129
Mineral rights, net	134,445			959,582		—			1,094,027
Equity in unconsolidated investment	—			261,942		—			261,942
Other non-current assets (including affiliates) (1)	887			192,050		—			192,937
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
Other current liabilities (including affiliates)	7,351			48,356		(43		)	55,664
Long-term debt, net (including affiliate) (1)	83,600			1,206,611		—			1,290,211
Other non-current liabilities (including affiliates)	4,703			165,770		—			170,473
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 March 31, 2016
	Unrestricted Subsidiaries of NRP			NRP and its Restricted Subsidiaries			Total
Revenues	$	7,323		$	95,428		$	102,751
Operating expenses	9,401			46,194			55,595
Income (loss) from operations	(2,078		)	49,234			47,156
Other expense, net	1,090			22,639			23,729
Net income (loss)	(3,168		)	26,595			23,427
Add: comprehensive loss from unconsolidated investment and other	—			(545		)	(545		)
Comprehensive income (loss)	$	(3,168	)	$	26,050		$	22,882

	Three Months Ended March 31, 2015
	Unrestricted Subsidiaries of NRP			NRP and its Restricted Subsidiaries			Total
Revenues	$	14,900		$	94,777		$	109,677
Operating expenses	16,748			52,512			69,260
Income (loss) from operations	(1,848		)	42,265			40,417
Other expense, net	808			22,120			22,928
Net income (loss)	(2,656		)	20,145			17,489
Add: comprehensive loss from unconsolidated investment and other	—			(965		)	(965		)
Comprehensive income (loss)	$	(2,656	)	$	19,180		$	16,524

15. 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):



	March 31, 2016		December 31, 2015
	(Unaudited)
Deferred revenue	$	76,750	$	80,812
Deferred revenue—affiliate	81,868		82,853
Total deferred revenue (including affiliate)	$	158,618	$	163,665

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



	Three Months Ended March 31,
	2016		2015
	(Unaudited)
Coal, hard mineral royalty and other (1)	$	6,094	$	1,063
Coal, hard mineral royalty and other—affiliates	870		3,477
Total coal, hard mineral royalty and other (including affilaites)	$	6,964	$	4,540


(1)	See "Note 16. Subsequent Events" for description of agreements entered into in April 2016 that resulted in lessee forfeitures of ability to recoup previously paid minimums.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(Unaudited)

16. Subsequent Events

The following represents material events that have occurred subsequent to March 31, 2016 through the time of the Partnership’s filing of its Quarterly Report on Form 10-Q with the SEC:

Distribution Declared

On April 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 May 13, 2016 to unitholders of record on May 5, 2016.

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 will recognize $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 will recognize approximately $9 million of revenue.

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 "NRP 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, crude oil and natural gas, construction aggregates, frac sand 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.

For the three months end March 31, 2016, we recorded revenues and other income of $102.8 million, net income of $23.4 million, Adjusted EBITDA of $66.4 million, and Distributable Cash Flow of $58.4 million. Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. For a reconciliation of Adjusted EBITDA to net income (loss) and Distributable Cash Flow to net cash provided by (used in) operating activities by business segment see "—Results of Operations—Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015." Management believes that the presentation of Adjusted EBITDA and Distributable Cash Flow provide information useful in assessing our segment financial condition and results of operations. Adjusted EBITDA and Distributable Cash Flow as defined by us may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) and cash provided by (used in) operating activities, respectively.

Current Liquidity Position

As of March 31, 2016, we had $62.1 million of liquidity that consisted of $52.1 million in cash and $10.0 million in borrowing capacity under Opco's Revolving Credit Facility. During the three months ended March 31, 2016, we repaid approximately $51 million of debt that included $41.0 million of the Opco Senior Notes and $10.0 million of the NRP Oil and Gas RBL Facility, both discussed below. As of March 31, 2016, there was $290.0 million of outstanding borrowings under Opco's Revolving Credit Facility that has $300 million of borrowing capacity and matures in October 2017. In connection with the fourth amendment to the RBL Facility in March 2016 described below, the borrowing base of the RBL Facility was reduced from $88.0 million to $75.0 million.

We have significant debt service requirements, including $80.8 million each year through 2018 in principal payments on several series of private placement senior notes (the “Opco Senior Notes"), and $25.0 million in aggregate principal payments on NRP Oil and Gas' reserve-based lending credit facility (the "RBL Facility") through October 1, 2016, and 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 have also taken steps to reduce 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 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, which comprised approximately 0.8%, or $8.2 million of our mineral rights balance as of of December 31, 2015 for $10.0 million in cash. The effective date of the sale was February 1, 2016. In February 2016, we 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 and approximately 1.6%, or $17.1 million of our mineral rights balance as of of December 31, 2015. The effective date of the sale was January 1, 2016.

In March 2016, NRP Oil and Gas entered into an amendment to the RBL Facility (the “Fourth Amendment”), primarily due to the significant and sustained decline in oil prices. While the Fourth Amendment alleviated certain covenant compliance issues, it did not change the fact that our forecast indicated that NRP Oil and Gas may not be able to meet its leverage ratio during the next 12 months and that the RBL Facility will be reduced by an amount greater than what NRP Oil and Gas would have the ability to pay within the required period of time. As a result, we believe there is substantial doubt about the ability of NRP Oil and Gas to continue as a going concern through March 31, 2017. In order to address this issue, we have initiated a process to sell NRP Oil and Gas' non-operating working interest properties in the Williston Basin within the next twelve months.

While we have closed two asset sale transactions, if we are unable to complete additional asset sales 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, Hard Minerals Royalty and Other Business Segment

For the three months ended March 31, 2016, our Coal, Hard Minerals Royalty and Other business segment contributed revenues and other income of $40.6 million, Adjusted EBITDA of $33.3 million, and Distributable Cash Flow of $33.4 million. During the first quarter of 2016, we sold of certain aggregates reserves for $10.0 million and recorded a $1.6 million gain from this asset sale.

Both the thermal and metallurgical coal markets remain severely challenged, and we do not anticipate that either market will recover in the near term. First quarter 2016 coal production in the United States was down 32% as compared to the first quarter of 2015, and we expect that coal producers will continue to cut production and idle additional mines in response to market conditions. In spite of this supply reduction, decreased demand for both thermal and metallurgical coal continues to out-pace supply cuts, and utility stockpiles remain at peak levels.

Although the U.S. coal industry is under extreme 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. In October 2015, Patriot Coal Corporation completed the sale of its assets in accordance with its bankruptcy plan. All of our leases were assumed and assigned in the sale process, and we received full pre-petition cure payments. 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. However, Alpha has reduced production and idled certain mines, and we expect that Alpha will continue to reduce production and/or idle mines during its bankruptcy process. Production cuts and mine idlings by Alpha have resulted in and will continue to result in decreased royalty payments to us to the extent such production cuts or idlings are on our properties. We estimate that Alpha owes us approximately $3.3 million in pre-petition royalties and minimum payments, and we expect to receive pre-petition amounts due to us with respect to any leases that are assumed in the bankruptcy process. Arch Coal, Inc. ("Arch") and Peabody Energy Corporation ("Peabody") filed for Chapter 11 bankruptcy protection in January 2016 and April 2016, respectively. While we do not yet know whether our leases will be assumed or rejected in these bankruptcy processes, our overall exposure to both Arch and Peabody is immaterial.

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 33% in the first three months of 2016 as compared

to the same period in 2015. Part 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 quarter of 2016 resulted in a negative cash impact to us of $23.6 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.

The metallurgical coal markets continue to remain depressed. We derived approximately 32% of our coal royalty revenues and 31% of the related production from metallurgical coal during the first quarter of 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 three months ended March 31, 2016, our Soda Ash business segment contributed revenues and other income of $9.8 million, Adjusted EBITDA of $12.3 million, and Distributable Cash Flow of $5.0 million. Our trona mining and soda ash refinery investment performed slightly below our expectations due to certain operational, production related issues in the first quarter of 2016. We believe these issues have been resolved, the market remains firm, and that we should see 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. The cash we receive from Ciner Wyoming is in part determined by the quarterly distributions declared by Ciner Resources LP. For the three months ended March 31, 2016, we received $12.3 million in cash distributions from Ciner Wyoming.

VantaCore Business Segment

For the three months ended March 31, 2016, our VantaCore business segment contributed revenues and other income of $24.7 million, Adjusted EBITDA of $2.5 million, and Distributable Cash Flow of $4.9 million.

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 quarter 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 three months ended March 31, 2016, but we expect that Laurel’s business will continue to be impacted by decreased natural gas development activities. VantaCore’s operations based in Clarksville, Tennessee and Baton Rouge, Louisiana depend on the pace of commercial and residential construction in those areas. The Clarksville operation performed above expectations during the first quarter of 2016, while the Baton Rouge operation volumes were lower than expected due to weather. 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.

Oil and Gas Business Segment

For the three months ended March 31, 2016, our Oil and Gas business segment contributed revenues and other income of $27.6 million, Adjusted EBITDA of $22.5 million, and Distributable Cash Flow of $33.5 million. During the first quarter of 2016, we sold certain oil and gas royalty and overriding royalty interests for $37.5 million and recorded a $20.3 million gain from this asset sale.

Global oil prices remained at low levels in the first quarter of 2016 and were significantly lower than the first quarter 2015. Although domestic crude oil production has shown signs of decline, inventories remain above the five-year average indicating continued excessive supply. Production of crude is estimated to continue to decline as a result of reduced development drilling activities. Natural gas prices have remained depressed. Our oil and gas revenues will continue to fluctuate with changes in prices for oil and natural gas and are expected to decrease over time due to natural production declines in producing wells and significantly decreased drilling activity. As of the date of this filing, we have not hedged any of our future oil or natural gas production.

As discussed in the Current Liquidity Position section above, we have initiated a process to sell NRP Oil and Gas' non-operating working interest properties in the Williston Basin within the next twelve months, which represents 86% of the total assets of the Partnership's Oil and Gas Business Segment as of March 31, 2016.

Management’s Forecast and Strategic Plan

Opco’s revolving credit facility matures in October 2017 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 $47.5 million in gross proceeds. However, we believe the 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 included in our debt agreement financial covenants. Traditionally, 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 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 2017 and 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 and excess worldwide supply of oil and gas. In particular, as described in Note 7. Debt and Debt—Affiliate, NRP Oil and Gas LLC ("NRP Oil and Gas") and NRP Operating LLC ("Opco"), both wholly owned subsidiaries of NRP, have 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. 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.

Opco

As of March 31, 2016, Opco had $290.0 million of indebtedness outstanding under its revolving credit facility due October 2017 (the "Opco Credit Facility") and $544.9 million outstanding under several series of Private Placement Notes (the "Opco Private Placement Notes") (collectively referred to as the "Opco Debt agreements"). The maximum leverage ratio under the Opco Debt agreements is required to be below 4.0x through March 31, 2016. Commencing with respect to the period ended June 30, 2016, the maximum leverage ratio reduces to 3.75x and reduces again to 3.5x commencing with respect to the period ended June 30, 2017. 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. Our Opco leverage ratio was 3.09x at March 31, 2016.

NRP Oil and Gas

NRP Oil and Gas had $75.0 million outstanding under its RBL Facility as of March 31, 2016. The RBL Facility is secured by a first priority lien on substantially all of NRP Oil and Gas’ assets and is not guaranteed by NRP or any other subsidiary of NRP. As discussed above, we believe there is substantial doubt about the ability of NRP Oil and Gas to continue as a going concern through March 31, 2017. We have initiated a process to sell NRP Oil and Gas' non-operating working interest properties in the Williston Basin within the next twelve months.

Results of Operations

Three Months Ended March 31, 2016 Compared to Three Months Ended Ended March 31, 2015

Adjusted EBITDA (Non-GAAP Financial Measure)

Adjusted EBITDA increased $2.2 million, or 3%, from $64.2 million in the three months ended March 31, 2015 to $66.4 million in the three months ended March 31, 2016. The increase is primarily related to a $20.3 million gain on the sale of certain oil and gas royalty properties was partially offset by lower net income from our coal and oil and gas businesses due to reduced production and commodity prices.

Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) 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, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDA should not be considered in isolation or as a substitute for operating income (loss), net income (loss), cash flows provided by operating, investing and financial activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDA provides no information regarding a partnership's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax positions. Adjusted EBITDA does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital and other commitments and obligations. Our management team believes Adjusted EBITDA is a useful measure because it is widely used by financial analysts, investors and rating agencies for comparative purposes. Adjusted EBITDA is also a financial measure widely used by investors in the high-yield bond market. 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.

The following table (in thousands) reconciles net income (loss) (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment for the three months ended March 31, 2016 and 2015:



	Operating Segments
For the Three Months Ended	Coal, Hard Mineral Royalty and Other		Soda Ash			VantaCore			Oil and Gas			Corporate and Financing			Total
March 31, 2016
Net income (loss)	$	24,600	$	9,801		$	(1,036	)	$	17,963		$	(27,901	)	$	23,427
Less: equity earnings from unconsolidated investment	—		(9,801		)	—			—			—			(9,801		)
Add: distributions from unconsolidated investment	—		12,250			—			—			—			12,250
Add: depreciation, depletion and amortization	6,762		—			3,562			4,419			—			14,743
Add: asset impairment	1,893		—			—			137			—			2,030
Add: interest expense	—		—			—			—			23,748			23,748
Adjusted EBITDA	$	33,255	$	12,250		$	2,526		$	22,519		$	(4,153	)	$	66,397

March 31, 2015
Net income (loss)	$	36,695	$	12,523		$	(2,491	)	$	(2,939	)	$	(26,299	)	$	17,489
Less: equity earnings from unconsolidated investment	—		(12,523		)	—			—			—			(12,523		)
Add: distributions from unconsolidated investment	—		10,903			—			—			—			10,903
Add: depreciation, depletion and amortization	10,016		—			3,856			11,520			—			25,392
Add: interest expense	—		—			—			—			22,943			22,943
Adjusted EBITDA	$	46,711	$	10,903		$	1,365		$	8,581		$	(3,356	)	$	64,204

Distributable Cash Flow (Non-GAAP Financial Measure)

Distributable Cash Flow increased $5.1 million, or 10%, from $53.3 million in the three months ended March 31, 2015 to $58.4 million in the three months ended March 31, 2016. This increase is due primarily to the $42.7 million net cash proceeds received from the sales of our oil and gas and aggregates royalty assets, partially offset by less cash provided by ordinary operations from our coal and oil and gas businesses due to lower production and commodity prices and less minimum payments received from our coal leases.

Distributable Cash Flow represents net cash provided by operating activities, 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. Although Distributable Cash Flow is a non-GAAP financial measure, we believe it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. Distributable Cash Flow may not be calculated the same for us as for other companies.

The following table (in thousands) reconciles net cash provided by operating activities (the most comparable GAAP financial measure) by business segment to Distributable Cash Flow for the three months ended March 31, 2016 and 2015:



	Operating Segments
For the Three Months Ended	Coal, Hard Mineral Royalty and Other			Soda Ash		VantaCore			Oil and Gas			Corporate and Financing			Total
March 31, 2016
Net cash provided by (used in) operating activities	$	23,298		$	5,018	$	6,113		$	3,328		$	(18,329	)	$	19,428
Add: return on long-term contract receivables—affiliate	309			—		—			—			—			309
Add: proceeds from sale of mineral rights	9,802			—		—			32,848			—			42,650
Less: maintenance capital expenditures	—			—		(1,250		)	(2,725		)	—			(3,975		)
Distributable Cash Flow	$	33,409		$	5,018	$	4,866		$	33,451		$	(18,329	)	$	58,415

March 31, 2015
Net cash provided by (used in) operating activities	$	46,154		$	6,449	$	7,317		$	15,345		$	(19,793	)	$	55,472
Add: return on long-term contract receivables—affiliate	1,137			—		—			—			—			1,137
Add: proceeds from sale of PP&E	—			—		905			—			—			905
Add: proceeds from sale of mineral rights	866			—		—			3,395			—			4,261
Less: maintenance capital expenditures	(158		)	—		(1,118		)	(7,210		)	—			(8,486		)
Distributable Cash Flow	$	47,999		$	6,449	$	7,104		$	11,530		$	(19,793	)	$	53,289

Revenues and Other Income

Revenues and other income decreased $6.9 million, or 6%, from $109.7 million in the three months ended March 31, 2015 to $102.8 million in the three months ended March 31, 2016. The following table shows our diversified sources of revenues and other income by business segment for the three months ended March 31, 2016 and 2015 (in thousands except for percentages):



	Coal, Hard Mineral Royalty and Other			Soda Ash			VantaCore			Oil and Gas			Total
2016
Revenues	$	40,635		$	9,801		$	24,682		$	27,633		$	102,751
Percentage of total	39		%	10		%	24		%	27		%
2015
Revenues	$	55,125		$	12,523		$	26,799		$	15,230		$	109,677
Percentage of total	51		%	11		%	24		%	14		%

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

Coal, Hard Mineral Royalty and Other

Revenues and other income related to our Coal, Hard Mineral Royalty and Other segment decreased $14.5 million, or 26%, from $55.1 million in the three months ended March 31, 2015 to $40.6 million in the three months ended March 31, 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 March 31,				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	1,431		1,745		(314		)	(18	)%
Central	3,227		4,384		(1,157		)	(26	)%
Southern	745		974		(229		)	(24	)%
Total Appalachia	5,403		7,103		(1,700		)	(24	)%
Illinois Basin	1,727		2,584		(857		)	(33	)%
Northern Powder River Basin	974		1,304		(330		)	(25	)%
Gulf Coast	—		117		(117		)	(100	)%
Total coal royalty production	8,104		11,108		(3,004		)	(27	)%

Average coal royalty revenue per ton
Appalachia
Northern	$	0.82	$	0.36	$	0.46		128	%
Central	3.25		3.99		(0.74		)	(19	)%
Southern	2.96		4.81		(1.85		)	(38	)%
Total Appalachia	2.56		3.21		(0.65		)	(20	)%
Illinois Basin	3.29		4.05		(0.76		)	(19	)%
Northern Powder River Basin	2.72		2.69		0.03			1	%
Gulf Coast	—		3.52		(3.52		)	(100	)%
Combined average coal royalty revenue per ton	2.74		3.35		(0.61		)	(18	)%

Coal royalty revenues
Appalachia
Northern	$	1,172	$	634	$	538		85	%
Central	10,473		17,506		(7,033		)	(40	)%
Southern	2,202		4,686		(2,484		)	(53	)%
Total Appalachia	13,847		22,826		(8,979		)	(39	)%
Illinois Basin	5,686		10,467		(4,781		)	(46	)%
Northern Powder River Basin	2,652		3,507		(855		)	(24	)%
Gulf Coast	—		412		(412		)	(100	)%
Total coal royalty revenue	$	22,185	$	37,212	$	(15,027	)	(40	)%

Other Coal, Hard Mineral Royalty and Other revenues
Override revenue	$	210	$	691	$	(481	)	(70	)%
Transportation and processing fees	4,234		4,597		(363		)	(8	)%
Minimums recognized as revenue	6,964		4,540		2,424			53	%
Condemnation related revenues	268		1,665		(1,397		)	(84	)%
Wheelage	413		777		(364		)	(47	)%
Hard mineral royalty revenues	890		2,173		(1,283		)	(59	)%
Gain on sale of hard mineral royalty properties	1,590		—		1,590			100	%
Property tax revenue	3,305		3,004		301			10	%
Other	576		466		110			24	%
Total other Coal, Hard Mineral Royalty and Other revenue	$	18,450	$	17,913	$	537		3	%
Total Coal, Hard Mineral Royalty and Other revenue	$	40,635	$	55,125	$	(14,490	)	(26	)%

Total coal production decreased 3.0 million tons, or 27%, from 11.1 million tons in the three months ended March 31, 2015 to 8.1 million tons in the three months ended March 31, 2016. Total coal royalty revenues decreased $15.0 million, or 40%, from $37.2 million in the three months ended March 31, 2015 to $22.2 million in the three months ended March 31, 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, partially offset by increased production on leases with a higher per ton rate.

Soda Ash

Revenues and other income related to our Soda Ash segment decreased $2.7 million, or 22%, from $12.5 million in the three months ended March 31, 2015 to $9.8 million in the three months ended March 31, 2015. This decrease is primarily related to lower pricing and higher selling, general and administrative expenses.

VantaCore

Revenues and other income related to our VantaCore segment decreased $2.1 million, or 8%, from $26.8 million in the three months ended March 31, 2015 to $24.7 million in the three months ended March 31, 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 crushed stone, sand, gravel and construction revenue. Tonnage sold by the VantaCore segment remained flat at 1.5 million tons quarter-over-quarter.

Oil and Gas

Revenues and other income related to our Oil and Gas segment increased $12.4 million, or 82%, from $15.2 million in the three months ended March 31, 2015 to $27.6 million in the three months ended March 31, 2016. This increase was primarily due to a $20.3 million gain recorded on the sale of our oil and gas royalty assets. Production and royalty revenue within the Partnership's Oil and Gas segment declined $7.5 million as a result of a decline in prices and production quarter-over-quarter in addition to the sale of a portion of our oil and gas royalty assets in the first quarter of 2016. The table below presents oil and gas production and revenues derived from our major oil and gas producing regions and the significant categories of oil and gas revenues:



	For the Three Months Ended March 31,				Increase (Decrease)			Percentage Change
	2016		2015		Increase (Decrease)			Percentage Change
	(Dollars in thousands, except per unit data) (Unaudited)
Williston Basin non-operated working interests:
Production volumes:
Oil (MBbl)	246		307		(61		)	(20	)%
Natural gas (Mcf)	229		221		8			4	%
NGL (MBbl)	30		40		(10		)	(25	)%
Total production (MBoe)	314		384		(70		)	(18	)%
Average sales price per unit:
Oil (Bbl)	$	25.61	$	39.34	$	(13.73	)	(35	)%
Natural gas (Mcf)	1.80		2.71		$	(0.91	)	(34	)%
NGL (Bbl)	7.00		12.28		(5.28		)	(43	)%
Revenues:
Oil	$	6,301	$	12,076	$	(5,775	)	(48	)%
Natural gas	413		598		(185		)	(31	)%
NGL	210		491		(281		)	(57	)%
Total production revenues	$	6,924	$	13,165	$	(6,241	)	(47	)%

Royalty and overriding royalty revenues	$	374	$	1,615	$	(1,241	)	(77	)%
Gain on sale of assets	$	20,335	$	450	$	19,885		4,419	%

Total oil and gas revenues	$	27,633	$	15,230	$	12,403		81	%

Operating and Maintenance Expenses (including affiliates)

Operating and maintenance expenses (including affiliates) decreased $5.8 million, or 14%, from $40.5 million in the three months ended March 31, 2015 to $34.7 million in the three months ended March 31, 2016. This decrease is primarily related to the following:

VantaCore

Operating and maintenance expenses (including affiliates) in our VantaCore segment decreased $3.2 million, or 13% from $25.4 million in the three months ended March 31, 2015 to $22.2 million in the three months ended March 31, 2016. This decrease is primarily due to the decline in materials cost as a result of the decrease in brokered stone volume quarter-over-quarter.

Oil and Gas

Operating and maintenance expenses (including affiliates) in our Oil and Gas segment decreased $1.5 million, or 23%, from $6.6 million in the three months ended March 31, 2015 to $5.1 million in the three months ended March 31, 2016. This decrease is primarily due to lower lease operating expenses and production taxes resulting from decreased production quarter-over-quarter.

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

DD&A expense decreased $10.7 million, or 42%, from $25.4 million in the three months ended March 31, 2015 to $14.7 million in the three months ended March 31, 2016. This decrease is primarily related to the reduction of our coal, aggregate and 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 as follows:

Coal, Hard Mineral Royalty and Other

DD&A expense (including affiliate) in our Coal, Hard Mineral Royalty and Other segment decreased $3.2 million, or 32%, from $10.0 million in the three months ended March 31, 2015 to $6.8 million in the three months ended March 31, 2016. This decrease was primarily the result of the reduction in depletion expense on the assets that were impaired during the third and fourth quarters of 2015 as well as the aggregates royalty assets that were sold in the first quarter of 2016 and decline in production quarter-over-quarter.

Oil and Gas

DD&A expense for our Oil and Gas segment decreased $7.1 million, or 62%, from $11.5 million in the three months ended March 31, 2015 to $4.4 million in the three months ended March 31, 2016. This decrease was primarily due to the reduction in depletion expense on the assets that were impaired during the third and fourth quarters of 2015 as well as the royalty assets that were sold in the first quarter of 2016 and 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 $0.8 million, or 24%, from $3.4 million in the three months ended March 31, 2015 to $4.2 million in the three months ended March 31, 2016. This increase is primarily related to increased legal and consulting fees.

Interest Expense

Interest expense increased $0.8 million, or 3%, from $22.9 million in the three months ended March 31, 2015 to $23.7 million in the three months ended March 31, 2016. This increase is primarily related to the write off of debt issue costs during the first quarter 2016 resulting from the lowering of the borrowing base of the RBL Facility in connection with the Fourth Amendment, partially offset by lower interest expense resulting from lower debt balances quarter-over-quarter.

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. 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 through asset sales and other means. Through the first quarter of 2016, we completed asset sales for $47.5 million in gross proceeds and we have initiated a process to sell NRP Oil and Gas' non-operating working interest properties in the Williston Basin within the next twelve months. However, we believe the 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 included in our debt agreement financial covenants. Traditionally, 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 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 2017 and 2018 debt maturities.

While we have closed two 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 $84.3 million as of March 31, 2016, primarily due to $80.8 million in principal payments on Opco's senior notes due over the next year as well as the $75.0 million due under the RBL Facility. Excluding these principal payments, net of their unamortized debt issue costs, our current assets exceeded our current liabilities by approximately $70.2 million as of March 31, 2016.

Capital Expenditures

In response to the significant decline in oil price, we expect our oil and gas capital expenditures to decline significantly in 2016 as compared to 2015. A portion of the capital expenditures associated with both our oil and gas working interest business and VantaCore 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 distributable cash flow. We continue to monitor the development programs of the operators of these properties and manage the capital expenditures associated with those properties by only participating in wells that are expected to provide acceptable economic returns.

Cash Flows

Operating activities provided $19.4 million and $55.5 million in cash for the three months ended March 31, 2016 and 2015, respectively. The majority of our cash provided by operations is generated from our coal royalty leases. Operating cash flow declined $22.9 million in our Coal, Hard Mineral Royalty and Other segment primarily as a result of the reduction in revenue and the receipt of minimum payments on certain leases quarter-over-quarter. Cash provided by operations within our Oil and Gas segment decreased primarily due to lower production and commodity prices as compared to the same quarter last year. Cash flow used in Corporate and Financing operating activities decreased as a result of lower cash paid for interest during the quarter as compared to the three months ended March 31, 2015.

Investing activities provided $38.0 million in cash for the three months ended March 31, 2016 and used $11.9 million in cash for the three months ended March 31, 2015. During the first quarter of 2016, our investing activities primarily consisted of $42.7 million in net proceeds received from the sale of certain hard mineral royalty and oil and gas royalty properties. These investing cash inflows were partially offset by $2.7 million in well participation costs within our Oil and Gas segment and $2.2 million in plant and equipment acquisitions within our VantaCore segment. During the first quarter of 2015, our investing activities

primarily consisted of well participation costs within our Oil and Gas segment and plant and equipment acquisitions within our VantaCore segment. These investing cash outflows were partially offset by the sale of 50% of our interest in a development project within our Oil and Gas segment in the first quarter of 2015.

Net cash flows used in financing activities for the three months ended March 31, 2016 and 2015 was $57.1 million and $60.4 million, respectively. During the first quarter of 2016 we repaid $51.2 million in debt and distributed $5.6 million to our unitholders. During the first quarter of 2015 our financing outflows primarily consisted of unitholder distributions of $43.7 million and loan repayments of $41.2 million. These cash outflows were partially offset by $25.0 million in loan proceeds during the first quarter of 2015.

Capital Resources and Obligations

Indebtedness

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



	March 31, 2016		December 31, 2015
Current portion of long-term debt, net	$	154,441	$	80,745
Long-term debt, net (including affiliate)	1,166,894		1,290,211
Total debt, net (including affiliate)	$	1,321,335	$	1,370,956

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 7. "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 14. 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 9 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 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 March 31, 2016, we had $365 million outstanding in variable interest rate debt. If interest rates were to increase by 1%, annual interest expense would increase approximately $3.7 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 quarter 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 10. "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).
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		Fourth Amendment to Credit Agreement, dated effective as of March 21, 2016 among NRP Oil and Gas LLC, each of the Lenders that is a signatory thereto, and Wells Fargo Bank, N.A., as administrative agent for the Lenders (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on March 22, 2016).
10.2***		Natural Resource Partners L.P. 2016 Cash Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on February 26, 2016).
10.3***		Form of Long-Term Incentive Award Agreement (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on February 26, 2016).
10.4***		Form of Long-Term Performance Award Agreement (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed on February 26, 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
***		Management compensatory plan or arrangement

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: May 6, 2016	By:	/s/ CORBIN J. ROBERTSON, JR.
		Corbin J. Robertson, Jr.
		Chairman of the Board and
		Chief Executive Officer
		(Principal Executive Officer)



Date: May 6, 2016	By:	/s/ CRAIG W. NUNEZ
		Craig W. Nunez
		Chief Financial Officer and
		Treasurer
		(Principal Financial Officer)



Date: May 6, 2016	By:	/s/ CHRISTOPHER J. ZOLAS
		Christopher J. Zolas
		Chief Accounting Officer
		(Principal Accounting Officer)