Edgar Filing: NATURAL RESOURCE PARTNERS LP

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Accelerated Filer

Non-accelerated Filer

¨ (Do not check if a smaller reporting company)

Smaller Reporting Company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2015

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

Commission file number: 001-31465

NATURAL RESOURCE PARTNERS L.P.

(Exact name of registrant as specified in its charter)


Delaware		35-2164875
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

601 Jefferson Street, Suite 3600

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 751-7507

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “accelerated filer”, “large accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

At August 7, 2015 there were 122,299,825 Common Units outstanding.

NATURAL RESOURCE PARTNERS, L.P.

TABLE OF CONTENTS


		Page
Part I. Financial Information
Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets		2
	Consolidated Statements of Comprehensive Income		3
	Consolidated Statements of Cash Flows		4
	Consolidated Statements of Partners’ Capital		5
	Notes to Consolidated Financial Statements		6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		38

Item 4.	Controls and Procedures		38

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 for unit information)


	June 30, 2015			December 31, 2014
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	27,525		$	50,076
Accounts receivable, net		54,230			66,455
Accounts receivable—affiliate		8,192			9,494
Inventory		7,126			5,814
Prepaid expenses and other		2,854			4,279

Total current assets		99,927			136,118

Land		25,243			25,243
Plant and equipment, net		77,287			60,093
Mineral rights, net		1,788,454			1,781,852
Intangible assets, net		59,182			60,733
Equity in unconsolidated investment		263,619			264,020
Long-term contracts receivable—affiliate		49,236			50,008
Goodwill		4,840			52,012
Other assets		17,317			14,645

Total assets	$	2,385,105		$	2,444,724

LIABILITIES AND CAPITAL

Current liabilities:
Accounts payable	$	16,692		$	22,465
Accounts payable—affiliates		939			950
Accrued liabilities		45,924			43,533
Current portion of long-term debt, net		155,983			80,983

Total current liabilities		219,538			147,931

Deferred revenue		80,706			73,207
Deferred revenue—affiliates		87,116			87,053
Long-term debt, net		1,256,218			1,374,336
Long-term debt, net—affiliate		19,917			19,904
Other non-current liabilities		9,797			22,138

Commitments and contingencies (see Note 13)

Partners’ Capital:
Common unitholders’ interest (122,299,825 units outstanding)		703,055			709,019
General partner’s interest		12,122			12,245
Accumulated other comprehensive loss		(1,214	)		(459	)

Total partners’ capital		713,963			720,805
Non-controlling interest		(2,150	)		(650	)

Total capital		711,813			720,155

Total liabilities and capital	$	2,385,105		$	2,444,724

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)


	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(Unaudited)						(Unaudited)
Revenues and other income:
Coal related revenues	$	28,562		$	34,271		$	58,983		$	67,917
Coal related revenues—affiliates		32,342			21,090			51,403			39,817
Aggregates related revenues		42,886			3,563			71,832			6,959
Oil and gas related revenues		14,839			17,822			30,069			27,880
Equity in earnings of unconsolidated investment		11,599			9,401			24,122			19,180
Property taxes		3,070			3,378			6,074			7,345
Other		4,332			1,036			4,824			1,772

Total revenues and other income		137,630			90,561			247,307			170,870
Costs and expenses:
Coal related expenses		504			663			1,825			1,240
Coal related expenses—affiliates		109			—			109			—
Aggregates related expenses		32,800			—			55,207			73
Oil and gas related expenses		2,999			2,291			6,760			4,212
General and administrative		2,234			6,029			9,689			8,719
General and administrative—affiliates		3,535			3,000			7,321			6,094
Depreciation, depletion and amortization		30,660			16,350			56,052			30,997
Asset impairments		3,803			5,624			3,803			5,624
Property, franchise and other taxes		5,066			6,201			10,204			11,069

Total operating expenses		81,710			40,158			150,970			68,028

Income from operations		55,920			50,403			96,337			102,842

Other income (expense)
Interest expense		(23,343	)		(19,037	)		(46,286	)		(38,897	)
Interest income		1			41			16			67

Other expense, net		(23,342	)		(18,996	)		(46,270	)		(38,830	)

Net income	$	32,578		$	31,407		$	50,067		$	64,012
Less: net income attributable to non-controlling interest		(1,244	)		—			(1,244	)		—

Net income attributable to NRP	$	31,334		$	31,407		$	48,823		$	64,012

Net income attributable to partners:
Limited partners	$	30,707		$	30,779		$	47,847		$	62,732

General partner	$	627		$	628		$	976		$	1,280

Basic and diluted net income per common unit	$	0.25		$	0.28		$	0.39		$	0.57

Weighted average number of common units outstanding		122,300			110,403			122,300			110,127

Net income	$	32,578		$	31,407		$	50,067		$	64,012
Comprehensive (income) loss from unconsolidated investment and other		210			(164	)		(755	)		(264	)
Comprehensive income attributable to non-controlling interest		(1,244	)		—			(1,244	)		—

Comprehensive income attributable to NRP	$	31,544		$	31,243		$	48,068		$	63,748

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Six Months Ended June 30,
	2015			2014
	(Unaudited)
Cash flows from operating activities:
Net income	$	50,067		$	64,012
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		56,052			30,997
Asset impairment		3,803			5,624
Gain on reserve swap		(9,290	)		—
Equity earnings from unconsolidated investment		(24,122	)		(19,180	)
Distributions from equity earnings from unconsolidated investment		21,805			21,935
Other, net		(2,728	)		1,468
Other, net—affiliates		13			—
Change in operating assets and liabilities:
Accounts receivable		12,560			(2,678	)
Accounts receivable—affiliate		1,302			(1,352	)
Accounts payable		581			(1,120	)
Accounts payable—affiliates		(11	)		54
Accrued liabilities		(5,419	)		(1,968	)
Deferred revenue		7,499			(1,165	)
Deferred revenue—affiliates		63			8,264
Accrued incentive plan expenses		(6,952	)		(5,916	)
Other items, net		1,252			318
Other items, net—affiliates		(365	)		345

Net cash provided by operating activities		106,110			99,638

Cash flows from investing activities:
Acquisition of mineral rights		(29,121	)		(8,891	)
Acquisition of plant and equipment and other		(5,073	)		(135	)
Proceeds from sale of mineral rights		5,281			—
Proceeds from sale of plant and equipment and other		5,255			—
Return on equity and other unconsolidated investments		—			3,633
Return on direct financing lease and contractual override—affiliate		1,137			600

Net cash used in investing activities		(22,521	)		(4,793	)

Cash flows from financing activities:
Proceeds from loans		25,000			2,000
Repayment of loans		(68,483	)		(53,483	)
Proceeds from issuance of common units		—			13,842
Capital contribution by general partner		—			347
Distributions to non-controlling interest		(2,744	)		(974	)
Distributions to partners		(54,910	)		(78,639	)
Debt issuance costs and other		(5,003	)		(438	)

Net cash used in financing activities		(106,140	)		(117,345	)

Net decrease in cash and cash equivalents		(22,551	)		(22,500	)
Cash and cash equivalents at beginning of period		50,076			92,513

Cash and cash equivalents at end of period	$	27,525		$	70,013

Supplemental cash flow information:
Cash paid during the period for interest	$	44,174		$	39,135
Plant, equipment and mineral rights funded with accounts payable or accrued liabilities	$	4,452		$	—

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			Accumulated Other Comprehensive			Partners’ Capital Excluding Non-Controlling			Non- Controlling
	Units		Amounts			Partner			Loss			Interest			Interest			Total Capital
Balance at December 31, 2014		122,300	$	709,019		$	12,245		$	(459	)	$	720,805		$	(650	)	$	720,155
Distributions to unitholders		—		(53,811	)		(1,099	)		—			(54,910	)		—			(54,910	)
Distributions to non-controlling interest		—		—			—			—			—			(2,744	)		(2,744	)
Net income		—		47,847			976			—			48,823			1,244			50,067
Comprehensive loss from unconsolidated investment and other		—		—			—			(755	)		(755	)		—			(755	)

Balance at June 30, 2015		122,300	$	703,055		$	12,122		$	(1,214	)	$	713,963		$	(2,150	)	$	711,813

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 prior period amounts have been reclassified to conform to the current period presentation. The reclassifications had no effect on the Partnership’s overall consolidated financial position, income or cash flows. 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, 2014. Interim results are not necessarily indicative of the results for a full year.

In March 2015, the Partnership recorded an out-of-period adjustment to correct an error in depletion expense related to its oil and gas royalty interests owned by BRP LLC, a joint venture with International Paper Company in which the Partnership owns a 51% interest. Depletion expense for the six months ended June 30, 2015 included a credit of $3.8 million to adjust the impact of depletion expense recorded in prior periods. After evaluating the quantitative and qualitative aspects of the error and the out-of-period adjustment to the Partnership’s financial results, management has determined that the misstatement and the out-of-period adjustment are not material to the prior period financial statements.

Recently Issued Accounting Standards

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, with earlier adoption not permitted. 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. We are currently evaluating the impact of the provisions of this guidance on our consolidated financial position, results of operations and cash flows.

In April 2015, the FASB issued authoritative guidance which changes the presentation of debt issuance costs in financial statements. This guidance requires an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. This guidance is effective for annual reporting periods beginning after December 15, 2016. Early adoption is permitted. This guidance will be applied retrospectively to each prior period presented. We are currently evaluating the impact of the provisions of this guidance on our consolidated balance sheets.

2.	Acquisitions

VantaCore Acquisition

On October 1, 2014, the Partnership completed its acquisition of VantaCore Partners LLC (“VantaCore”), a privately held company specializing in the construction materials industry, for $200.6 million in cash and common units. Headquartered in Philadelphia, Pennsylvania, VantaCore operates four hard rock quarries, five sand and gravel plants, two asphalt plants and a marine terminal. VantaCore’s current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Partnership accounted for the transaction as a business combination under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition date, while transaction and integration costs associated with the acquisitions were expensed as incurred. The results of operations of the acquisition have been included in our consolidated financial statements since the acquisition date.

In the first quarter 2015, the purchase price allocation was adjusted as more detailed analysis was completed and additional information was obtained about the facts and circumstances for various items of VantaCore’s plant and equipment that existed as of acquisition date. As a result of this adjustment, plant and equipment was increased by $22.5 million with a corresponding decrease to goodwill. In the second quarter 2015, the purchase price allocation was adjusted as more detailed analysis was completed and additional information was obtained about the facts and circumstances for VantaCore’s right to mine and intangible assets that existed as of the acquisition date. As a result of this adjustment, Mineral rights, net and Intangible assets, net were increased by $24.7 million with a corresponding decrease to Goodwill. Measurement-period adjustments were not material to prior period financial statements and were recorded during the period in which the amount of the adjustment was determined. The accounting for the VantaCore acquisition was completed in the second quarter of 2015 and is summarized as follows:

VantaCore Purchase Price Allocation


	October 1, 2014
	(In thousands)
Consideration
Cash	$	168,978
NRP common units		31,604

Total consideration given	$	200,582

Allocation of Purchase Price
Current assets	$	37,222
Land, property and equipment		62,911
Mineral rights		111,500
Other assets		4,347
Current liabilities		(16,953	)
Asset retirement obligation		(3,285	)
Goodwill		4,840

Fair value of net assets acquired	$	200,582

Sanish Field Acquisition

On November 12, 2014, the Partnership acquired non-operated oil and gas working interests in the Sanish Field of the Williston Basin from an affiliate of Kaiser-Francis Oil Company for $339.1 million.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Sanish Field Purchase Price Allocation


	November 12, 2014
	(In thousands)
Consideration
Cash	$	339,093
Allocation of Purchase Price
Mineral rights - proven oil and gas properties		298,293
Mineral rights - probable and possible oil and gas resources		40,800

Fair value of net assets acquired	$	339,093

Pro Forma Financial Information

The following unaudited pro forma financial information presents a summary of the Partnership’s consolidated results of operations for the three and six months ended June 30, 2014, assuming the VantaCore and Sanish Field acquisitions had been completed as of January 1, 2014, including adjustments to reflect the values assigned to the net assets acquired:


	Three Months Ended June 30, 2014		Six Months Ended June 30, 2014
	(Unaudited) (In thousands)
Revenues and other income except aggregates related and oil and gas related revenues	$	69,213	$	136,088
Aggregates related revenues		49,094		82,261
Oil and gas related revenues		34,636		62,528

Total revenues and other income	$	152,943	$	280,877

Net income	$	36,752	$	69,524

Basic and diluted net income per common unit	$	0.33	$	0.62

3.	Equity Investment

We account for our 49% investment in OCI Wyoming LLC (“OCI Wyoming”) using the equity method of accounting. OCI Wyoming distributed $10.9 million and $13.9 million to us in the three months ended June 30, 2015 and 2014, respectively, and OCI Wyoming distributed $21.8 million and $25.6 million to us in the six months ended June 30, 2015 and 2014, respectively.

The difference between the amount at which our investment in OCI Wyoming is carried and the amount of underlying equity in OCI Wyoming’s net assets was $157.6 million and $162.7 million as of June 30, 2015 and December 31, 2014, respectively. This excess basis relates to plant, property and equipment and right to mine assets. The excess basis difference that relates to property, plant and equipment is being amortized into income using the straight-line method over a weighted average of 28 years. The excess basis difference that relates to right to mine assets is being amortized into income using the units of production method. Our equity in the earnings of OCI Wyoming is summarized as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(Unaudited)						(Unaudited)
Income allocation to NRP’s equity interests	$	12,786		$	10,851		$	26,513		$	22,127
Amortization of basis difference		(1,187	)		(1,450	)		(2,391	)		(2,947	)

Equity in earnings of unconsolidated investment	$	11,599		$	9,401		$	24,122		$	19,180

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The results of OCI Wyoming’s operations for the three and six months ended June 30, 2015 and 2014 are summarized as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(Unaudited)				(Unaudited)
Sales	$	122,200	$	112,970	$	242,630	$	229,211
Gross profit		31,091		27,604		63,815		54,723
Net income		26,094		22,145		54,108		45,157

The financial position of OCI Wyoming at June 30, 2015 and December 31, 2014 are summarized as follows (in thousands):


	June 30, 2015		December 31, 2014
	(Unaudited)
Current assets	$	166,900	$	200,622
Noncurrent assets		228,691		202,282
Current liabilities		46,367		47,704
Noncurrent liabilities		135,190		149,192

4.	Plant and Equipment

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


	June 30, 2015			December 31, 2014
	(Unaudited)
Plant and equipment at cost	$	108,234		$	89,759
Construction in process		634			457
Less accumulated depreciation		(31,581	)		(30,123	)

Total plant and equipment, net	$	77,287		$	60,093

Depreciation expense related to the Partnership’s plant and equipment totaled $4.5 million and $1.2 million for the three months ended June 30, 2015 and 2014, respectively. Depreciation expense related to the Partnership’s plant and equipment totaled $9.0 million and $2.5 million for the six months ended June 30, 2015 and 2014, respectively. During the second quarter of 2015, the Partnership recorded $2.3 million of asset impairment expense related to a coal preparation plant.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

5.	Mineral Rights

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


	June 30, 2015			December 31, 2014
	(Unaudited)
Coal	$	1,548,680		$	1,541,572
Oil and Gas		578,791			560,395
Aggregates		236,283			211,490
Other		14,950			15,014
Less accumulated depletion and amortization		(590,250	)		(546,619	)

Total mineral rights, net	$	1,788,454		$	1,781,852

Depletion expense related to the Partnership’s mineral rights totaled $23.4 million and $14.2 million for the three months ended June 30, 2015 and 2014, respectively. Depletion expense related to the Partnership’s mineral rights totaled $43.3 million and $26.7 million for the six months ended June 30, 2015 and 2014, respectively. During the second quarter of 2015, the Partnership recorded $1.5 million of asset impairment expense related to its coal mineral rights.

6.	Intangible Assets

The Partnership’s intangible assets consist of the following (in thousands):


	June 30, 2015			December 31, 2014
	(Unaudited)
Contract intangibles	$	81,109		$	82,972
Other intangibles		4,998			3,004
Less accumulated amortization		(26,925	)		(25,243	)

Total intangible assets, net	$	59,182		$	60,733

Amortization expense related to the Partnership’s intangible assets totaled $1.2 million and $0.9 million for the three months ended June 30, 2015 and 2014, respectively. Amortization expense related to the Partnership’s intangible assets totaled $2.3 million and $1.8 million for the six months ended June 30, 2015 and 2014, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

7.	Debt and Debt—Affiliate

As used in this Note 7, references to “NRP LP” refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC, a wholly owned subsidiary of NRP LP, or any of Natural Resource Partners L.P.’s subsidiaries. References to “Opco” refer to NRP (Operating) LLC and its subsidiaries. References to NRP Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP LP. NRP Finance Corporation (“NRP Finance”) is a wholly owned subsidiary of NRP LP and a co-issuer with NRP LP on the 9.125% senior notes described below.

As of June 30, 2015 and December 31, 2014, Debt and debt—affiliate consisted of the following (in thousands):


	June 30, 2015			December 31, 2014
	(Unaudited)
NRP LP Debt:
$425 million 9.125% senior notes, with semi-annual interest payments in April and October, maturing October 2018, $300 million issued at 99.007% and $125 million issued at 99.5%	$	422,545		$	422,167

Opco Debt:
$300 million floating rate revolving credit facility, due October 2017		215,000			—
$300 million floating rate revolving credit facility, due August 2016		—			200,000
$200 million floating rate term loan, due January 2016		75,000			75,000
4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2018		13,850			18,467
8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2019		85,714			107,143
5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, maturing in July 2020		46,154			46,154
5.31% utility local improvement obligation, with annual principal and interest payments, maturing in March 2021		1,153			1,345
5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, maturing in June 2023		21,600			24,300
4.73% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, maturing in December 2023		67,500			67,500
5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2024		135,000			150,000
8.92% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, maturing in March 2024		40,910			45,455
5.03% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, maturing in December 2026		161,538			161,538
5.18% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, maturing in December 2026		46,154			46,154

NRP Oil and Gas Debt:
Reserve-based revolving credit facility due 2019		100,000			110,000

Total debt and debt—affiliate		1,432,118			1,475,223
Less: current portion of long-term debt, net		(155,983	)		(80,983	)

Total long-term debt and debt—affiliate	$	1,276,135		$	1,394,240

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NRP LP Debt

Senior Notes

In September 2013, NRP LP, together with NRP Finance as co-issuer, issued $300 million of 9.125% Senior Notes due 2018 at an offering price of 99.007% of par. Net proceeds after expenses from the issuance of the senior notes were approximately $289.0 million. The 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 LP, together with NRP Finance as co-issuer, issued an additional $125 million of its 9.125% Senior Notes due 2018 at an offering price of 99.5% of par. The notes constitute the same series of securities as the existing $300.0 million 9.125% senior notes due 2018 issued in September 2013. Net proceeds of $122.6 million from the additional issuance of the 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. The notes call for semi-annual interest payments on April 1 and October 1 of each year and will mature on October 1, 2018.

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 “NRP Senior Notes Indenture”). Before April 1, 2016, NRP and NRP Finance may redeem all or part of the NRP Senior Notes at a redemption price equal to the sum of the principal plus a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. Furthermore, before April 1, 2016, NRP and NRP Finance may on any one or more occasions redeem up to 35% of the aggregate principal amount of the notes with the net proceeds of certain public or private equity offerings at a redemption price of 109.125% of the principal amount of notes, plus any accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the notes issued under the indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. In the event of a change of control, as defined in the indenture, the holders of the notes may require NRP and NRP Finance to purchase their notes at a purchase price equal to 101% of the principal amount of the notes, plus accrued and unpaid interest, if any.

The NRP Senior Notes Indenture contains additional covenants that, among other things, limit NRP’s ability and the ability of certain of its subsidiaries to declare or pay any dividend or distribution on, purchase or redeem units or purchase or redeem subordinated debt; make investments; create certain liens; enter into agreements that restrict distributions or other payments from NRP’s restricted subsidiaries as defined in the indenture to NRP; sell assets; consolidate, merge or transfer all or substantially all of the assets of NRP and its restricted subsidiaries; engage in transactions with affiliates; create unrestricted subsidiaries; and enter into certain sale and leaseback transactions.

The NRP Senior Notes Indenture contains covenants that, among other things, limit the ability of NRP LP and certain of its subsidiaries to incur or guarantee additional indebtedness. Under the NRP Senior Notes Indenture, NRP LP 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 LP and certain of its subsidiaries to incur additional indebtedness is further limited in the event the amount of indebtedness of NRP LP and certain of its subsidiaries that is senior to NRP LP’s unsecured indebtedness exceeds certain threshholds.

Opco Debt

All of Opco’s debt is guaranteed by its wholly owned subsidiaries and is secured by certain of the assets of Opco and its wholly owned subsidiaries other than NRP Trona LLC, as further described below. As of June 30, 2015 and December 31, 2014, 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 million Third Amended and Restated Credit Agreement (the “A&R Revolving Credit Facility”), which amended and restated Opco’s $300 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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Initially, 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 2.375%; or

•

a rate equal to LIBOR plus 3.375%.

Borrowings under the A&R Revolving Credit Facility will bear interest at such rate until the time that Opco delivers quarterly financial statements for the quarter ending September 30, 2015 to the lenders thereunder. Following such delivery date, indebtedness under the A&R Revolving Credit Facility will bear 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 six months ended June 30, 2015 and 2014 were 2.07% and 1.97%, respectively. The weighted average interest rates for the borrowings outstanding under the A&R Revolving Credit Facility for the three months ended June 30, 2015 and 2014 were 2.19% and 1.95%, respectively.

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

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

•

a 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.

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 and Term Loan (as described below).

The A&R Revolving Credit Facility is collateralized and secured by liens on certain of Opco’s assets with a carrying value of $810.5 million classified as Mineral rights and Plant and equipment on the Partnership’s Consolidated Balance Sheet as of June 30, 2015. 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 OCI 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.

In conjunction with the entry into the A&R Revolving Credit Facility, approximately $85 million of commitments under the previous revolving credit facility that matured in August 2016 were replaced by new lenders. Extinguishment accounting was applied for lenders participating in the previous revolving credit facility but not participating or participating to a lesser extent in the A&R Revolving Credit Facility. This accounting resulted in a write off of $0.2 million of debt issuance costs in June 2015.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Term Loan

During 2013, Opco entered into a $200 million Term Loan facility (the “Term Loan”). The weighted average interest rates for the debt outstanding under the Term Loan for the six months ended June 30, 2015 and 2014 were 2.19% and 2.25%, respectively. The weighted average interest rates for the debt outstanding under the Term Loan for the three months ended June 30, 2015 and 2014 were 2.19% and 2.24%, respectively.

Opco repaid $101.0 million in principal under the Term Loan during the third quarter of 2013 and an additional $24.0 million during the fourth quarter of 2014. Repayment terms call for the remaining outstanding balance of $75.0 million to be paid on January 23, 2016.

Opco’s Term Loan contains covenants requiring Opco to maintain:

•

a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the credit agreement) not to exceed 4.0 to 1.0 and,

•

a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease operating expense) of not less than 3.5 to 1.0 for the four most recent quarters.

In connection with the entry into the A&R Revolving Credit Facility in June 2015, Opco and its subsidiaries entered into the Second Amendment (the “Term Loan Amendment”) to the Term Loan. The Term Loan Amendment amends the Term Loan to provide for the security thereof by the same collateral package pledged by Opco and its subsidiaries to secure the A&R Revolving Credit Facility, as described above.

Senior Notes

Opco made principal payments of $48.3 million on its senior notes during the six months ended June 30, 2015. The Note Purchase Agreements relating to Opco’s 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% 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 agreement) 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.

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 senior notes by the same collateral package pledged by Opco and its subsidiaries to secure the A&R Revolving Credit Facility and the Term Loan, 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, the Term Loan, and all renewals, amendments or restatements thereof), such covenants shall be deemed to be incorporated by reference in the senior notes and the holders of the 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

Revolving Credit Facility

In August 2013, NRP Oil and Gas entered into 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 credit 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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The maximum amount available under the 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 NRP Oil and Gas revolving credit facility and the $137.0 million borrowing base under that facility was redetermined at $105.0 million that also resulted in a write off of $0.6 million of debt issuance costs in April 2015. The Partnership repaid $10.0 million of outstanding borrowings under the NRP Oil and Gas revolving credit facility during the second quarter of 2015. At June 30, 2015 and December 31, 2014, there was $100.0 million and $110.0 million, respectively, outstanding under the NRP Oil and Gas revolving credit facility.

The credit 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 its revolving credit facility, and neither the Partnership nor any of its other subsidiaries is a guarantor of such facility. The weighted average interest rates for the debt outstanding under the credit facility for each of the six month periods ended June 30, 2015 and 2014 was 2.52% and 1.90%, respectively. The weighted average interest rates for the debt outstanding under the credit facility for each of the three month periods ended June 30, 2015 and 2014 were 2.63% and 1.90%, respectively.

Indebtedness under the NRP Oil and Gas credit facility bears interest, at the option of NRP Oil and Gas, at 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 0.50% to 1.50%; or

•

a rate equal to LIBOR, plus an applicable margin ranging from 1.50% to 2.50%.

NRP Oil and Gas incurs a commitment fee on the unused portion of the borrowing base under the credit facility at a rate ranging from 0.375% to 0.50% per annum.

The NRP Oil and Gas credit facility contains certain covenants, which, among other things, require the maintenance of:

•

a total leverage ratio (defined as the ratio of the total debt of NRP Oil and Gas to its EBITDAX) of not more than 3.5 to 1.0; and

•

a minimum current ratio of 1.0 to 1.0.

As of June 30, 2015 and December 31, 2014, NRP Oil and Gas was in compliance with the terms of the financial covenants contained in its credit facility.

8.	Fair Value Measurements

The Partnership’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amounts reported on our Consolidated Balance Sheets for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term nature. The following table (in thousands) shows the carrying amount and estimated fair value of our other financial instruments:


	June 30, 2015				December 31, 2014
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(Unaudited)
Assets
Contracts receivable—affiliate, current and long-term⁽¹⁾	$	4,833	$	5,174	$	4,870	$	5,162

Debt and debt—affiliate
NRP LP senior notes⁽²⁾	$	422,545	$	372,406	$	422,167	$	423,780
Opco revolving credit facility and term loan facility⁽³⁾	$	290,000	$	290,000	$	275,000	$	275,000
Opco senior notes and utility local improvement obligation⁽¹⁾	$	619,573	$	542,901	$	668,056	$	672,740
NRP Oil and Gas revolving credit facility⁽³⁾	$	100,000	$	100,000	$	110,000	$	110,000

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)	The Level 3 estimated fair value was based on inputs that are observable in the market or that could be derived from, or collaborated with, observable market data, including quotations obtained for similar instruments on the closing trading prices near quarter end.

(2)	The Level 2 estimated fair value was based upon quotations obtained for similar instruments on the closing trading prices near quarter end.

(3)	The Level 3 estimated fair value approximates the carrying amount because the interest rates are variable and reflective of market rates and the Partnership has the ability to repay this debt at any time without penalty.

The March 31, 2015 estimated fair value of the NRP LP senior notes and Opco senior notes and local utility improvement obligation were presented incorrectly as $417.0 million and $629.5 million, respectively, and should have been presented as $378.3 million and $557.9 million, respectively. The estimated fair value disclosure had no impact on the Partnership’s overall financial position, income or cash flows.

9.	Related Party Transactions

Reimbursements to Affiliates of our General Partner

The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for expenses incurred on the Partnership’s behalf. All direct general and administrative expenses are charged to the Partnership as incurred. The Partnership also reimburses indirect general and administrative costs, including certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by our general partner and its affiliates, Quintana Minerals Corporation and Western Pocahontas Properties Limited Partnership (“WPPLP”). The Partnership had Accounts payable—affiliates to Quintana Minerals Corporation of $0.6 million at both June 30, 2015 and December 31, 2014, for services provided by Quintana Minerals Corporation to the Partnership. The Partnership had Accounts payable—affiliates to WPPLP of $0.3 million and $0.4 million at June 30, 2015 and December 31, 2014, respectively.

The reimbursements to affiliates of the Partnership’s general partner for services performed by WPPLP and Quintana Minerals Corporation are as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(Unaudited)				(Unaudited)
General and administrative—affiliate	$	3,535	$	3,000	$	7,321	$	6,094

The Partnership also leases an office building in Huntington, West Virginia from WPPLP and recorded $0.2 million and $0.3 million in General and administrative—affiliates in each of the three and six months ended June 30, 2015 and 2014, respectively.

Cline Affiliates

Various companies controlled by Chris Cline, including Foresight Energy LP, lease coal reserves from the Partnership, and the Partnership provides coal transportation services to them for a fee. Mr. Cline, both individually and through another affiliate, Adena Minerals, LLC, owns a 31% interest in NRP’s general partner, as well as approximately 4.9 million of NRP’s common units. Coal related revenues from Foresight Energy LP (“Foresight Energy”) totaled $31.6 million and $20.4 million for the three months ended June 30, 2015 and 2014, respectively. Coal related revenues from Foresight Energy totaled $49.9 million and $38.3 million for the six months ended June 30, 2015 and 2014, respectively.

As of June 30, 2015 and December 31, 2014 the Partnership had Accounts receivable-affiliate from Foresight Energy of $8.2 million and $9.2 million, respectively. As of June 30, 2015, the Partnership had received $86.8 million in minimum royalty payments to date that have not been recorded as revenue since they have not been recouped by Foresight Energy.

The Partnership owns and leases rail load out and associated facilities to Foresight Energy at Foresight Energy’s Sugar Camp mine. The lease agreement is accounted for as a direct financing lease. Total projected remaining payments under the lease at June 30, 2015 were $83.8 million with unearned income of $37.1 million, and the net amount receivable was $46.7 million, of which $1.9 million is included in Accounts receivable—affiliate while the remaining is included in Long-term contracts receivable—affiliate.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Total projected remaining payments under the lease at December 31, 2014 were $86.3 million with unearned income of $39.0 million and the net amount receivable was $47.3 million, of which $1.8 million is included in Accounts receivable—affiliate while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets.

The Partnership holds a contractual overriding royalty interest from a subsidiary of Foresight Energy that provides for payments based upon production from specific tons at Foresight Energy’s Sugar Camp operations. This overriding royalty was accounted for as a financing arrangement and is reflected as an affiliate receivable. The net amount receivable under the agreement as of June 30, 2015 was $4.8 million, of which $0.4 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, 2014 was $5.6 million, of which $1.1 million is included in Accounts receivable—affiliate while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets.

In April 2015, the Partnership recognized a gain of $9.3 million on a reserve swap at Foresight Energy’s Williamson mine. The gain is included in Coal related revenues—affiliates on our Consolidated Statements of Comprehensive Income. The Level 3 fair value of the reserves was estimated using a cash flow model. The expected cash flows were developed using estimated annual sales tons, forecasted sales prices and anticipated market royalty rates.

Long-Term Debt—Affiliate

Donald R. Holcomb, one of the Partnership’s directors, is a manager of Cline Trust Company, LLC, which owns approximately 5.35 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 Christopher Cline, each of which owns an approximately equal membership interest in the Cline Trust Company. Mr. Holcomb also serves as trustee of each of the four trusts. Cline Trust Company, LLC purchased the $20.0 million of the Partnership’s 9.125% Senior Notes due 2018 in the Partnership’s offering of $125.0 million additional principal amount of such notes in October 2014 at the same price as the other purchasers in that offering. The balance on this portion of the Partnership’s 9.125% Senior Notes due 2018 was $19.9 million as of June 30, 2015 and is included in Long-term debt—affiliate.

Quintana Capital Group GP, Ltd.

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

At June 30, 2015, 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 $0.8 million and $0.7 million and $1.5 million and $1.6 million for the three and six months ended June 30, 2015 and 2014, respectively.

As of June 30, 2015, the Partnership had recorded $0.3 million in minimum royalty payments to date that have not been recognized as revenue since they have not been recouped by Corsa. The Partnership also had Accounts receivable—affiliate totaling $0.2 million and $0.3 million from Corsa at June 30, 2015 and December 31, 2014, respectively.

WPPLP Production Royalty

For the three and six months ended June 30, 2015, we recorded $0.1 million in Coal related expenses—affiliates related to a non-participating production royalty payable to WPPLP pursuant to a conveyance agreement entered into in 2007.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10.

Major Lessees

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


	Three Months Ended June 30,										Six Months Ended June 30,
	2015					2014					2015					2014
	(Unaudited)										(Unaudited)
	Revenues		Percent			Revenues		Percent			Revenues		Percent			Revenues		Percent
Foresight Energy and affiliates	$	31,581		23	%	$	20,432		23	%	$	49,879		20	%	$	38,254		22	%
Alpha Natural Resources		8,943		6	%		12,810		14	%		17,772		7	%		24,451		14	%

The Partnership has a significant concentration of revenues with Foresight Energy and Alpha Natural Resources, although in most cases, with the exception of Foresight Energy’s Williamson mine, the exposure is spread out over a number of different mining operations and leases. Foresight Energy’s Williamson mine was responsible for approximately 12% and 9% of the Partnership’s total revenues and other income for the three and six months ended June 30, 2015, respectively. For the three and six months ended June 30, 2014, the Williamson mine was responsible for approximately 10% and 11% of the Partnership’s total revenues and other income, respectively.

11.

Long-Term Incentive Plans

GP Natural Resource Partners LLC adopted the Natural Resource Partners Long-Term Incentive Plan (the “Long-Term Incentive Plan”) for directors of GP Natural Resource Partners LLC and employees of its affiliates who perform services for the Partnership. Under the plan a grantee will receive the market value of a common unit in cash upon vesting. A summary of activity in the outstanding grants during 2015 is as follows:


	(Unaudited)
Outstanding grants at January 1, 2015		1,153,393
Grants during the year		498,486
Grants vested and paid during the year		(290,430	)
Forfeitures during the year		(23,875	)

Outstanding grants at June 30, 2015		1,337,574

Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The liability fluctuates with the market value of the Partnership units and because of changes in estimated fair value determined each quarter using the Black-Scholes option valuation model. Risk free interest rates and volatility are reset at each calculation based on current rates corresponding to the remaining vesting term for each outstanding grant and ranged from 0.31% to 1.35% and 39.41% to 53.35%, respectively, at June 30, 2015. The Partnership’s average distribution rate of 7.60% and historical forfeiture rate of 4.97% were used in the calculation at June 30, 2015. The Partnership recorded a credit to general and administrative expenses (“G&A expenses”) related to its plan to be reimbursed to its general partner of $1.4 million and $1.5 million for the three and six months ended June 30, 2015, respectively, due to the decline in the market price of the Partnership’s units during 2015. For the three and six months ended June 30 2014, the Partnership recorded G&A expenses of $1.5 million and $0.4 million, respectively. In connection with the Long-Term Incentive Plan, payments are typically made during the first quarter of the year. Payments of $4.4 million and $5.3 million were made during the six month periods ended June 30, 2015 and 2014, respectively.

In connection with the phantom unit awards, the Compensation, Nominating and Governance Committee also granted tandem Distribution Equivalent Rights, or DERs, which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units 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.

The unaccrued cost associated with the unvested outstanding grants and related DERs at June 30, 2015 and June 30, 2014 was $3.2 million and $9.4 million, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

12.

Distributions Paid

On February 13, 2015, the Partnership paid a quarterly distribution of $0.35 per unit to all holders of common units on February 5, 2015. On May 14, 2015, the Partnership paid a quarterly distribution of $0.09 per unit to all holders of common units on May 5, 2015.

On January 31, 2014, the Partnership paid a quarterly distribution of $0.35 per unit to all holders of common units on January 21, 2014. On May 14, 2014, the Partnership paid a quarterly distribution of $0.35 per unit to all holders of common units on May 5, 2014.

13.

Commitments and Contingencies

The purchase agreement for the acquisition of the Partnership’s interest in OCI Wyoming requires it to pay additional contingent consideration to Anadarko to the extent certain performance criteria described in the purchase agreement are met at OCI Wyoming in any of the years 2013, 2014 or 2015. During the first quarters of 2014 and 2015, the Partnership paid $3.8 million and $0.5 million, respectively, in contingent consideration to Anadarko. As of June 30, 2015, the Partnership has estimated and recorded $8.8 million as an accrued liability on its consolidated Balance Sheet, payable in the first quarter of 2016 with respect to 2015. The Partnership has no obligation to pay contingent consideration with respect to any period after 2015.

In March 2014, Anadarko gave the Partnership written notice that it believed certain reorganization transactions conducted in 2013 within the OCI organization triggered an acceleration of the Partnership’s obligation under the purchase agreement with Anadarko to pay the additional contingent consideration in full and demanded immediate payment of such amount. The Partnership disagreed with Anadarko’s position in a written response provided to them in April 2014. In April 2015, Anadarko sent a written request for additional information regarding the OCI reorganization and indicated that they were still considering this claim against the Partnership. The Partnership responded in writing in May 2015 and does not believe the reorganization transactions triggered an obligation to pay the additional contingent consideration. The Partnership will continue to engage in discussions with Anadarko to resolve the issue to the extent necessary. However, if Anadarko were to pursue and prevail on such a claim, the Partnership would be required to pay an amount to Anadarko in excess of the amounts already paid, together with the $8.8 million accrual described above, up to the maximum amount of the additional contingent consideration, minus a deductible. Under the purchase agreement, the maximum cumulative amount of additional contingent consideration is an amount equal to the net present value of $50 million. Any additional amount paid by the Partnership would be considered to be additional acquisition consideration and added to Equity and other unconsolidated investments.

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

14.

Subsequent Events

The following represents material events that have occurred subsequent to June 30, 2015 through the time of the Partnership’s filing of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission:

Alpha Natural Resources Bankruptcy

On August 3, 2015, Alpha Natural Resources, the Partnership’s second largest coal lessee, filed a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code. During the course of the bankruptcy, Alpha is expected to continue operations and pay royalties to the Partnership. In the second quarter of 2015, the Partnership recognized $8.9 million in revenues from Alpha, equivalent to 6.5% of the Partnership’s total revenues. Ultimately, Alpha will determine whether to assume or reject the coal leases that it has with the Partnership in the bankruptcy process. The Partnership currently anticipates that the majority of its active leases with Alpha will be assumed. At the time of the bankruptcy filing, Alpha estimated that it owed the Partnership approximately $2.5 million in pre-petition amounts for royalties on July 2015 production, which would have become due and payable in late August. The Partnership will receive all pre-petition amounts due to it with respect to any leases that are assumed in the bankruptcy.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Hillsboro Mine Force Majeure Notice

In July 2015, we received a notice from Foresight Energy declaring a force majeure event at the Hillsboro mine due to elevated carbon monoxide levels at the mine. While we are disputing Foresight Energy’s claim, the effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us the quarterly minimum deficiency payment with respect to the Hillsboro mine in the second quarter. Foresight Energy’s failure to make the deficiency payment with respect to the second quarter resulted in a $3.1 million cash impact to the Partnership. On July 28, 2015, Foresight Energy announced that mining at the Hillsboro mine had re-commenced. We received $4.4 million in royalty payments on tonnage sold from coal stockpiles at the Hillsboro mine during the second quarter of 2015.

Distributions Declared

On July 21, 2015, the Board of Directors of GP Natural Resource Partners LLC declared a distribution of $0.09 per unit to be paid by the Partnership on August 14, 2015 to unitholders of record on August 5, 2015.

Item 2.

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

Information Regarding Forward-Looking Statements

Statements included in this Form 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 financial strategy;

•

prices of and demand for coal, oil, natural gas, aggregates and industrial minerals;

•

estimated revenues, expenses and results of operations;

•

the amount, nature and timing of capital expenditures;

•

our ability to make acquisitions and integrate the acquisitions we do make;

•

our liquidity and access to capital and financing sources;

•

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

•

OCI Wyoming LLC’s 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 management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

You should not put undue reliance on any forward-looking statements. See “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014 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” and “us” refer to Natural Resource Partners L.P. and, where the context requires, our subsidiaries. References to “NRP” and “Natural Resource Partners” refer to Natural Resource Partners L.P. only, and not to NRP (Operating) LLC or any of Natural Resource Partners L.P.’s subsidiaries. References to “Opco” refer to NRP (Operating) LLC, a wholly owned subsidiary of NRP, and its subsidiaries. References to NRP Oil and Gas refer to NRP Oil and Gas LLC, a wholly owned subsidiary of NRP. NRP Finance Corporation (“NRP Finance”) is a wholly owned subsidiary of NRP and a co-issuer with NRP on the 9.125% senior notes.

Introduction

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

•

Executive Overview

•

Results of Operations

•

Liquidity and Capital Resources

•

Off-Balance Sheet Arrangements

•

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. For the six months ended June 30, 2015, we recorded revenues and other income of $247.3 million and Adjusted EBITDA of $143.4 million. Adjusted EBITDA is a non-GAAP financial measure. For a reconciliation of Adjusted EBITDA to net income, see “—Results of Operations—Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014—Adjusted EBITDA (Non-GAAP Financial Measure).”

Our coal reserves are located in the three major U.S. coal producing regions: Appalachia, the Illinois Basin and the Western United States. We also own lignite reserves in the Gulf Coast region. We do not operate any coal mines, but lease our coal reserves to experienced mine operators under long-term leases that grant the operators the right to mine and sell our reserves in exchange for royalty payments. We also own and manage coal infrastructure assets that generate additional coal related revenues, primarily in the Illinois Basin.

We own or lease aggregates and industrial minerals located in a number of states across the country. We derive a small percentage of our aggregates and industrial minerals revenues by leasing our owned reserves to third party operators who mine and sell the reserves in exchange for royalty payments. However, the majority of our aggregates and industrial minerals revenues come through our ownership of VantaCore, which we acquired in October 2014. VantaCore specializes in the construction materials industry and operates four hard rock quarries, five sand and gravel plants, two asphalt plants and a marine terminal. VantaCore’s current operations are located in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana.

We own a 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. OCI 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.

We own various interests in oil and gas properties that are located in the Williston Basin, the Appalachian Basin, Louisiana and Oklahoma. Our interests in the Appalachian Basin, Louisiana and Oklahoma are minerals and royalty interests, while in the Williston Basin we own non-operated working interests. Our Williston Basin non-operated working interest properties generate the majority of our oil and gas revenues and include the properties acquired in the Sanish Field from an affiliate of Kaiser-Francis Oil Company in November 2014.

Current Liquidity Position

At June 30, 2015, our liquidity consisted of $27.5 million in cash and $90.0 million in combined borrowing capacity under our revolving credit facilities. In April 2015, we announced a 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 that plan, our Board of Directors has declared distributions with respect to the first and second quarters of 2015 of $0.09 per common unit, a 75% decrease from the distribution paid with respect to fourth quarter of 2014. We intend to use the annual cash savings from the distribution reduction to pay down debt and improve our consolidated credit metrics. During the six months ended June 30, 2015, we reduced our debt by a net amount of $43.5 million.

In June 2015, we amended and restated Opco’s $300 million revolving credit facility, extending the maturity of that facility to October 2017 from August 2016. We have $80.8 million in principal payments due on Opco’s senior notes each year through 2018, and as of June 30, 2015, we had $75.0 million outstanding under Opco’s term loan facility that matures in January 2016. We believe that we have sufficient liquidity to meet our current financial needs.

Current Results/Market Outlook

Our revenues and other income from sources other than coal represented 55% of our total revenues and other income in the first half of 2015, as compared to 37% of total revenues and other income in the first half of 2014. This increase is due primarily to our diversification efforts, including our acquisition of VantaCore, which generated revenues of $67.4 million during the first half of 2015. As an operating construction aggregates business, VantaCore generates higher revenues but experiences lower profit margins than our royalty businesses. Coal-related revenues were up 2% for the first half of 2015 compared to the first half of 2014, due primarily to the recognition of increased minimums as revenue and a gain recognized on a reserve swap. This increase in coal related revenues was partially offset by declines in coal royalty revenues per ton in each of our operating areas other than the Northern Powder River Basin. During the first half of 2015, our investment in OCI Wyoming’s trona mining and soda ash production operations contributed $24.1 million in other income, up $4.9 million from the first half of 2014, and our oil and gas revenues increased 8% over the first half of 2014 due to higher production volumes partially offset by lower oil and natural gas prices.

Coal. Both the thermal and metallurgical coal markets remain severely challenged, and we do not anticipate that either market will recover during 2015. We expect that coal producers will continue to cut production and idle additional mines during 2015 in response to market conditions, but we do not know to what extent our properties may be affected. A number of coal producers have recently filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code, including Patriot Coal Corporation and Alpha Natural Resources, Inc. which are lessees of NRP. We do not expect that these bankruptcies will have a material adverse effect on our business or results of operations, and historically, our leases have generally been assumed and all pre-petition amounts have been cured in full in our lessees’ bankruptcy processes. In the second quarter of 2015, we recognized $8.9 million in revenues (representing 6.5% of our total revenues) from Alpha, which is our second largest lessee. During the course of its bankruptcy process, Alpha is expected to continue operations and pay royalties to us. Ultimately, Alpha will determine whether to assume or reject the coal leases that it has with us in the bankruptcy process. We currently anticipate that the majority of our active leases with Alpha will be assumed. At the time of the bankruptcy filing, Alpha estimated that it owed approximately $2.5 million to us in pre-petition amounts for royalties on July 2015 production, which would have become due and payable in late August. We will receive all pre-petition amounts due to us with respect to any leases that are assumed in the bankruptcy. We continue to monitor our coal properties for impairment, and any impairments would reduce the carrying value of our assets.

We anticipate that producers of Central Appalachian thermal coal in particular will continue to struggle in the current environment due to the high cost nature of their operations. In contrast, despite a 15% decrease in production and a corresponding decrease in coal royalty revenues from our properties in the Illinois Basin during the first half of 2015 as compared to the first half of 2014, we expect revenues from our properties in the basin to increase over the long term, as production from the Illinois Basin becomes a larger portion of overall U.S. thermal coal production due to the low cost nature of operations in that basin. Part of the decrease in production in the Illinois Basin is attributable to the idling of Foresight Energy LP’s Hillsboro mine 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 Hillsboro mine. While we are disputing Foresight Energy’s claim, the effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us the quarterly minimum deficiency payment with respect to the Hillsboro mine in the second quarter. Foresight Energy’s failure to make the deficiency payment with respect to the second quarter resulted in a $3.1 million cash impact to us. On July 28, 2015, Foresight Energy announced that mining at the Hillsboro mine had re-commenced. We received $4.4 million in royalty payments on tonnage sold from coal stockpiles at the Hillsboro mine during the second quarter of 2015 and expect to continue receiving royalty payments until the coal stockpile is depleted.

The metallurgical coal markets continued to deteriorate during the second quarter of 2015, and the third quarter 2015 metallurgical coal benchmark price was set at its lowest level since 2004. We derived approximately 42% of our coal royalty revenues and 31% of the related production from metallurgical coal during the first half of 2015. 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 relatively strong domestic dollar which increases the production cost of U.S. coal producers relative to foreign producers.

Soda Ash. Our trona mining and soda ash refinery investment performed in line with our expectations during the first half of 2015 with record soda ash production volumes. The international market for soda ash continues to grow and OCI Wyoming’s international sales were better than expected. Domestic sales volumes, which are typically sold at higher prices than soda ash sold internationally, have remained relatively stable. The cash we receive from OCI Wyoming is in part determined by the quarterly distributions declared by OCI Resources LP, which has increased its quarterly distribution with respect to each of the last three quarters. The distribution declared with respect to the second quarter of 2015 represents a 2.5% increase over the distribution paid with respect to the fourth quarter of 2014. OCI Resources has announced its intent to increase distributions with respect to 2015 by 3% to 6%. OCI Enterprises, Inc. recently announced an agreement to sell its interests in the general partner of OCI Resources, as well as common and subordinated units of OCI Resources, to the Ciner Group for $429 million. We do not anticipate that this transaction will have any impact on the operations of OCI Wyoming or future cash distributions to our interest.

Aggregates. 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. Production and sales during the second quarter of 2015 recovered to normal levels as compared to the first quarter of 2015, which was impacted by adverse winter weather conditions. VantaCore’s Laurel Aggregates operation in southwestern Pennsylvania serves producers and oilfield service companies operating in the Marcellus and Utica Shales and was slightly impacted during the first half of 2015 by the slowing pace of exploration and development of natural gas in those areas due to low natural gas prices. However, increased local construction activity offset these declines. 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 in line with expectations during the second quarter, while the Baton Rouge operation continued to be impacted by significant rainfall during the quarter. 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. The acquisition consideration was cash consideration of $4.0 million payable over four years and the assumption of a $1.2 million current liability. Under VantaCore’s ownership, this operation will continue to lease reserves from NRP and sell its produced limestone aggregates in both the local market and downstream to river-based markets.

Oil and Gas. Global oil and gas prices modestly recovered in the second quarter, although prices remain significantly lower than the same period in 2014. Domestic oil production is estimated to have begun declining during the second quarter as a result of reduced development drilling activities. The natural gas market in the second quarter was characterized by sustained low prices, increased working inventories in storage, and modestly lower production. Overall expectations are for increases in natural gas production and storage levels in 2015 relative to the previous year. While oil and gas prices improved in the second quarter of 2015, they have declined since quarter end. Our oil and gas revenues will continue to fluctuate with changes in prices for oil and natural gas. As of the date of this filing, we have not hedged any of our future oil or natural gas production.

Results of Operations

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

Adjusted EBITDA (Non-GAAP Financial Measure)

Adjusted EBITDA increased 3% in the three months ended June 30, 2015 to $79.2 million from $76.9 million generated in the three months ended June 30, 2014. This increase in Adjusted EBITDA is mainly related to the inclusion of VantaCore in our operating results in 2015, which was partially offset by lower coal royalty revenues and oil and gas revenues in 2015 as compared to 2014.

Adjusted EBITDA is a non-GAAP financial measure that we define as net income less equity earnings in unconsolidated investment, gains on reserve swaps and income to non-controlling interest; plus distributions from equity earnings in unconsolidated investment, interest expense, gross, 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 insolation or as a substitute for operating income, net income or 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 or 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 to Adjusted EBITDA for the three months ended June 30, 2015 and 2014.


	Three Months Ended June 30,
	2015			2014
	(unaudited)
Net income	$	32,578		$	31,407
Less equity earnings in unconsolidated investment		(11,599	)		(9,401	)
Less gain on reserve swap		(9,290	)		—
Less income to non-controlling interest		(1,244	)		—
Add distributions from equity earnings in unconsolidated investment		10,902			13,923
Add depreciation, depletion and amortization		30,660			16,350
Add asset impairment		3,803			5,624
Add interest expense, gross		23,343			19,037

Adjusted EBITDA	$	79,153		$	76,940

Adjusted EBITDA presented in the table above differs from the EBITDDA definitions contained in Opco’s debt agreement covenants. In calculating EBITDDA for purposes of Opco’s debt covenant compliance, pro forma effect may be given to acquisitions and dispositions made during the relevant period. See Note 7. “Debt and Debt—Affiliate” in the consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for a description of Opco’s debt agreements.

Distributable Cash Flow (Non-GAAP Financial Measure)

Distributable cash flow decreased by 27%, or $17.8 million, to $47.2 million in the second quarter 2015 as compared to $64.9 million in the second quarter 2014 due to increased maintenance capital expenditures and changes in working capital that were partially offset by $5.4 million related to the sale of minerals rights and assets. Maintenance capital expenditures primarily consist of costs to maintain the long-term production capacity of our oil and gas non-operating working interest business and VantaCore.

Our distributable cash flow represents net cash provided by operating activities, plus returns on unconsolidated equity investments, proceeds from sales of assets, and returns on direct financing lease and contractual overrides 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 to distributable cash flow for the three months ended June 30, 2015 and 2014:


	Three Months Ended June 30,
	2015			2014
	(Unaudited)
Net cash provided by operating activities	$	50,638		$	61,008
Add return on direct financing lease and contractual overrides		—			303
Add return on unconsolidated equity investments		—			3,633
Add proceeds from sale of mineral rights		1,020			—
Add proceeds from sale of plant and equipment and other		4,350			—
Less maintenance capital expenditures		(6,755	)		—
Less distributions to non-controlling interest		(2,082	)		—

Distributable cash flow	$	47,171		$	64,944

Diversified Natural Resource Revenues and Other Income

The following table shows our diversified sources of revenues in the three months ended June 30, 2015 and 2014:


	Three Months Ended June 30, (Unaudited)
(In thousands except for percentages)	Coal Related Revenues			Aggregates Related Revenues			Industrial Minerals Other Income (OCI Wyoming)			Oil and Gas Related Revenues			Other Revenues			Total
2015
Revenues	$	60,904		$	42,886		$	11,599		$	14,839		$	7,402		$	137,630
Percentage of total		44	%		31	%		8	%		11	%		6	%

2014
Revenues	$	55,361		$	3,563		$	9,401		$	17,822		$	4,414		$	90,561
Percentage of total		61	%		4	%		10	%		20	%		5	%

Coal Related Revenues (including affiliates)

Total coal related revenues comprised approximately 44% and 61% of our total revenues and other income for the three months ended June 30, 2015 and 2014, respectively. The table below presents coal royalty production and revenues derived from our major coal producing regions and the significant categories of other coal related revenues:


	Three Months Ended June 30,				Increase (Decrease)			Percentage Change
	2015		2014		Increase (Decrease)			Percentage Change
	(In thousands, except percent and per ton data) (Unaudited)
Coal royalty production (tons)
Appalachia
Northern		4,318		1,826		2,492			136	%
Central		4,376		5,288		(912	)		(17	)%
Southern		1,174		949		225			24	%

Total Appalachia		9,868		8,063		1,805			22	%
Illinois Basin		2,960		3,416		(456	)		(13	)%
Northern Powder River Basin		892		173		719			416	%
Gulf Coast		300		199		101			51	%

Total coal royalty production		14,020		11,851		2,169			18	%

Average coal royalty revenue per ton
Appalachia
Northern	$	0.16	$	1.07	$	(0.91	)		(85	)%
Central		4.04		4.50		(0.46	)		(10	)%
Southern		4.60		5.14		(0.54	)		(11	)%
Total Appalachia		2.41		3.80		(1.39	)		(37	)%
Illinois Basin		3.90		4.12		(0.22	)		(5	)%
Northern Powder River Basin		2.32		2.09		0. 23			11	%
Gulf Coast		3.49		3.54		(.05	)		(1	)%
Combined average coal royalty revenue per ton	$	2.74	$	3.86	$	(1.12	)		(29	)%

Coal royalty revenues
Appalachia
Northern	$	708	$	1,958	$	(1,250	)		(64	)%
Central		17,670		23,781		(6,111	)		(26	)%
Southern		5,399		4,875		524			11	%

Total Appalachia		23,777		30,614		(6,837	)		(22	)%
Illinois Basin		11,538		14,083		(2,545	)		(18	)%
Northern Powder River Basin		2,071		362		1,709			472	%
Gulf Coast		1,047		704		343			49	%

Total coal royalty revenue	$	38,433	$	45,763	$	(7,330	)		(16	)%

Other coal related revenues
Override revenue	$	1,071	$	1,402	$	(331	)		(24	%)
Transportation and processing fees		6,465		5,996		469			8	%
Minimums recognized as revenue		4,706		1,338		3,368			252	%
Coal reserve swap		9,290		—		9,290			100	%
Wheelage		939		862		77			9	%

Total other coal related revenues	$	22,471	$	9,598	$	12,873			134	%

Total coal related revenues and coal related revenues—affiliates	$	60,904	$	55,361	$	5,543			10	%

Appalachia

Appalachian coal production increased 1.8 million tons, or 22%, and coal royalty revenues decreased $6.8 million, or 22%, in the three-months ended June 30, 2015 as compared to the same period of 2014.

Production from our properties in the Central Appalachian region decreased 0.9 million tons for the three months ended June 30, 2015 compared to the same quarter for 2014 and pricing realized by our lessees for both steam and metallurgical coal in Central Appalachia was generally lower. As a result, coal royalty revenue from Central Appalachian properties decreased $6.1 million, or 26%, for the three months ended June 30, 2015 compared to the three months ended June 30, 2014.

The Southern Appalachian region was essentially flat for the three months ended June 30, 2015 when compared to the three months ended June 30, 2014.

With respect to Northern Appalachia, during the three months ended June 30, 2015 there was an increase in production of 2.5 million tons and decrease of $1.3 million in coal royalty revenues and production. Our revenue per ton in the region was lower primarily due to one of our leases, which has a very low royalty per ton, being a larger proportion of production in the region.

Illinois Basin

Illinois Basin coal production decreased 0.5 million tons, or 13%, and coal royalty revenues decreased $2.5 million, or 18%, in the three-months ended June 30, 2015 as compared to the same period of 2014. These variances are due primarily to lower pricing received by our lessees and lower demand.

Northern Powder River Basin

Northern Powder River Basin coal production increased 0.7 million tons, or 416%, and coal royalty revenues increased $1.7 million, or 472%, in the three months ended June 30, 2015 as compared to the same period of 2014. Coal royalty revenues and production increased on our Western Energy property due to the normal variations that occur due to the checkerboard nature of ownership.

Gulf Coast

Gulf Coast coal production increased 0.1 million tons, or 51%, and coal royalty revenues increased $0.3 million, or 49%, in the three months ended June 30, 2015 as compared to the same period of 2014. The increase was due primarily to a lessee having a greater portion of its production on adjacent properties.

Other Coal Related Revenues

Other coal related revenues for the three months ended June 30, 2015 increased $12.9 million, or 134% compared to the same period in 2014. Override revenue for the three months ended June 30, 2015 decreased by 24% compared to the same period in 2014 primarily due to one lessee moving its mining operations from an area on which we receive an overriding royalty onto property on which we receive coal royalty revenue. Minimums recognized as revenue increased $3.4 million, or 252%, for the three months ended June 30, 2015 when compared to the same period in 2014, primarily due to the recoupment period under our lease relating to Foresight Energy’s Macoupin mine expiring in 2015. Transportation and processing fees increased $0.5 million or 8%. This increase was due primarily to more tonnage being transported from our Illinois Basin properties. Also included in other coal related revenues for the three months ended June 30, 2015 was a $9.3 million gain on a reserve swap at Foresight Energy’s Williamson mine.

Aggregates Related Revenues and Industrial Minerals Other Income

Total aggregates related revenues and total industrial minerals other income represented approximately 39% and 14% of our total revenues and other income for the three months ended June 30, 2015 and 2014, respectively. The table below presents the major categories of our aggregates related revenues and industrial minerals other income:


	Three Months Ended June 30,				Increase (Decrease)			Percentage Change
	2015		2014		Increase (Decrease)			Percentage Change
	(In thousands, except percent and per ton data) (Unaudited)
VantaCore:
Tonnage sold		2,040		N/A		N/A			N/A
Revenues	$	40,625		N/A		N/A			N/A
Operating expenses		32,800		N/A		N/A			N/A
Aggregates related royalty revenues		2,261		3,563		(1,302	)		(37	)%
Total aggregates related revenues	$	42,886	$	3,563	$	39,323			1,104	%

Industrial minerals other income and cash distributions:
Equity in earnings of unconsolidated investment	$	11,599	$	9,401	$	2,198			23	%
Cash distributions from equity earnings in unconsolidated investment	$	10,902	$	13,923	$	(3,021	)		(22	)%

VantaCore

VantaCore operates hard rock quarries, sand and gravel plants, asphalt plants and a marine terminal in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana. We recognized $40.6 million of aggregates related revenues from VantaCore’s operations in the three months ended June 30, 2015.

Aggregates Related Royalty Revenues

Aggregates related royalty revenues decreased $1.3 million, or 37%, in the three-months ended June 30, 2015 as compared to the same period of 2014. This decrease is primarily due to a lessee moving from property where we collect a 15% royalty to property where we collect a 1% override.

Industrial Minerals Other Income and Cash Distributions

For the three months ended June 30, 2015, equity in the earnings of our investment in the OCI Wyoming trona mining and soda ash production business was $11.6 million, and we received $10.9 million in cash distributions from OCI Wyoming. For the three months ended June 30, 2014, we recorded equity in the earnings of OCI Wyoming of $9.4 million and received $13.9 million in cash distributions.

Oil and Gas Related Revenues

Total oil and gas related revenues comprised approximately 11% and 20% of our total revenues and other income for the three months ended June 30, 2015 and 2014, respectively. 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 related revenues:


	Three Months Ended June 30,				Increase (Decrease)			Percentage Change
	2015		2014		Increase (Decrease)			Percentage Change
	(Dollars in thousands, except per unit data) (Unaudited)
Williston Basin non-operated working interests:
Production volumes:
Oil (MBbl)		266		139		127			91	%
Natural gas (Mcf)		188		97		91			94	%
NGL (MBoe)		36		10		26			260	%
Average sales price per unit:
Oil (Bbl)	$	49.14	$	93.40	$	(44.26	)		(47	)%
Natural gas (Mcf)		2.34		5.71		(3.37	)		(59	)%
NGL (Boe)		12.14		35.40		(23.26	)		(66	)%

Revenues:
Oil	$	13,071	$	12,982	$	89			1	%
Natural gas		439		554		(115	)		(21	)%
NGL		437		354		83			23	%

Total	$	13,947	$	13,890	$	57			—

Royalty and overriding revenues	$	892	$	3,932	$	(3,040	)		(77	)%

Total oil and gas related revenues	$	14,839	$	17,822	$	(2,983	)		(17	)%

Oil and gas revenues decreased $3.0 million, or 17%, for the three months ended June 30, 2015 when compared to the same period ended for 2014. The decrease in revenues is primarily due to lower oil and natural gas prices, partially offset by higher oil and natural gas production volumes from the fourth quarter 2014 Sanish Field acquisition.

Other Revenues

Other revenues primarily include reimbursements of property taxes from our lessees, rentals and proceeds from an asset sale. Other revenues increased $3.0 million, or 68%, for the three months ended June 30, 2015 when compared to the same period ended for 2014 primarily as a result of a gain of $3.1 million on the sale of other assets in the second quarter of 2015.

Operating Expenses

Depreciation, depletion and amortization

Depreciation, depletion and amortization increased $14.3 million, or 88%, for the three months ended June 30, 2015 when compared to the same period ended for 2014, primarily as a result of assets acquired during the fourth quarter of 2014.

General and administrative expenses

General and administrative expenses decreased $3.3 million, or 36%, for the three months ended June 30, 2015 when compared to the same period ended for 2014, primarily as a result of a decrease in the market value of our common units used to value awards under our Long-Term Incentive Plan partially offset by increased expenses associated with the VantaCore business.

Interest Expense

Interest expense increased $4.3 million, or 23%, for the three months ended June 30, 2015 when compared to the same period ended for 2014, primarily as a result of additional debt incurred to complete acquisitions in the fourth quarter of 2014.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Adjusted EBITDA (Non-GAAP Financial Measure)

Adjusted EBITDA decreased 2% for the six months ended 2015 to $143.4 million, from $145.9 million generated in the six months ended June 30, 2014. This decrease in Adjusted EBITDA is mainly related to decreased coal royalty revenues and oil and gas revenues in 2015 as compared to 2014, which decreases were partially offset by the inclusion of VantaCore in our operating results in 2015.

Adjusted EBITDA is a non-GAAP financial measure. For an explanation of Adjusted EBITDA, see “—Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014—Adjusted EBITDA (Non-GAAP Financial Measure).” The following table (in thousands) reconciles net income to Adjusted EBITDA for the six months ended June 30, 2015 and 2014.


	Six Months Ended June 30,
	2015			2014
	(Unaudited)
Net income	$	50,067		$	64,012
Less equity earnings in unconsolidated investment		(24,122	)		(19,180	)
Less gain on reserve swap		(9,290	)		—
Less income to non-controlling interest		(1,244	)		—
Add distributions from equity earnings in unconsolidated investment		21,805			25,568
Add depreciation, depletion and amortization		56,052			30,997
Add asset impairment		3,803			5,624
Add interest expense, gross		46,286			38,897

Adjusted EBITDA	$	143,357		$	145,918

Distributable Cash Flow (Non-GAAP Financial Measure)

Distributable cash flow decreased by 3%, or $3.1 million, to $99.8 million in the first half of 2015, mainly due to timing of cash payments received by our aggregates related business and approximately $10.5 million related to the sale of some minerals rights and assets. In addition, distributable cash flow for the six months ended June 30, 2015 was reduced by $15.2 million for maintenance capital expenditures.

Distributable cash flow is a non-GAAP financial measure. For an explanation of distributable cash flow, see “—Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014—Distributable Cash Flow (Non-GAAP Financial Measure).” The following table (in thousands) reconciles net cash provided by operating activities to distributable cash flow for the six months ended June 30, 2015 and 2014.


	Six Months Ended June 30,
	2015			2014
	(Unaudited)
Net cash provided by operating activities	$	106,110		$	99,638
Add return on direct financing lease and contractual overrides		1,137			600
Add return on unconsolidated equity investments		—			3,633
Add proceeds from sale of mineral rights		5,281			—
Add proceeds from sale of plant and equipment and other		5,255			—
Less maintenance capital expenditures		(15,241	)		—
Less distributions to non-controlling interest		(2,744	)		(974	)

Distributable cash flow	$	99,798		$	102,897

Diversified Natural Resource Revenues and Other Income

The following table shows our diversified sources of revenues in the six months ended June 30, 2015 and 2014:


	Six Months Ended June 30, (Unaudited)
(In thousands except for percentages)	Coal Related Revenues			Aggregates Related Revenues			Industrial Minerals Other Income (OCI Wyoming)			Oil and Gas Related Revenues			Other Revenues			Total
2015
Revenues	$	110,386		$	71,832		$	24,122		$	30,069		$	10,898		$	247,307
Percentage of total		45	%		29	%		10	%		12	%		4	%

2014
Revenues	$	107,734		$	6,959		$	19,180		$	27,880		$	9,117		$	170,870
Percentage of total		63	%		4	%		11	%		16	%		6	%

Coal Related Revenues (including affiliates)

Total coal related revenues comprised approximately 45% and 63% of our total revenues and other income for the six months ended June 30, 2015 and 2014, respectively. The table below presents coal royalty production and revenues derived from our major coal producing regions and the significant categories of other coal related revenues:


	Six Months Ended June 30,				Increase (Decrease)			Percentage Change
	2015		2014		Increase (Decrease)			Percentage Change
	(In thousands, except percent and per ton data) (Unaudited)
Coal royalty production (tons)
Appalachia
Northern		6,063		4,477		1,586			35	%
Central		8,760		9,664		(904	)		(9	)%
Southern		2,149		1,933		216			11	%

Total Appalachia		16,972		16,074		898			6	%
Illinois Basin		5,543		6,538		(995	)		(15	)%
Northern Powder River Basin		2,196		1,052		1,144			109	%
Gulf Coast		417		439		(22	)		(5	)%

Total coal royalty production		25,128		24,103		1,025			4	%

Average coal royalty revenue per ton
Appalachia
Northern	$	0.22	$	0.91	$	(0.69	)		(76	)%
Central		4.02		4.53		(0.51	)		(11	)%
Southern		4.69		5.35		(0.66	)		(12	)%
Total Appalachia		2.75		3.62		(0.87	)		(24	)%
Illinois Basin		3.97		4.06		(0.09	)		(2	)%
Northern Powder River Basin		2.54		2.83		(0.29	)		(10	)%
Gulf Coast		3.50		3.46		.04			1	%
Combined average coal royalty revenue per ton	$	3.01	$	3.70	$	(0.69	)		(19	)%

Coal royalty revenues
Appalachia
Northern	$	1,342	$	4,096	$	(2,754	)		(67	)%
Central		35,176		43,818		(8,642	)		(20	)%
Southern		10,085		10,339		(254	)		(2	)%

Total Appalachia		46,603		58,253		(11,650	)		(20	)%
Illinois Basin		22,005		26,553		(4,548	)		(17	)%
Northern Powder River Basin		5,578		2,972		2,606			88	%
Gulf Coast		1,459		1,520		(61	)		(4	)%

Total coal royalty revenue	$	75,645	$	89,298	$	(13,653	)		(15	)%

Other coal related revenues
Override revenue	$	1,762	$	2,746	$	(984	)		(36	)%
Transportation and processing fees		11,062		11,093		(31	)		—
Minimums recognized as revenue		9,246		2,808		6,438			229	%
Coal reserve swap		9,290		—		9,290			100	%
DOH Property Sale		1,665		—		1,665			100	%
Wheelage		1,716		1,789		(73	)		(4	)%

Total other coal related revenues	$	34,741	$	18,436	$	16,305			88	%

Total coal related revenues and coal related revenues—affiliates	$	110,386	$	107,734	$	2,652			2	%

Appalachia

Appalachian coal production increased 0.9 million tons, or 6%, and coal royalty revenues decreased $11.7 million, or 20%, in the six months ended June 30, 2015 as compared to the same period of 2014.

Production from our properties in the Central Appalachian region decreased 0.9 million tons for the six months ended June 30, 2015 compared to the same six month period for 2014 and pricing realized by our lessees for both steam and metallurgical coal in Central Appalachia was generally lower. As a result, coal royalty revenue from Central Appalachian properties decreased $8.6 million, or 20%, for the six months ended June 30, 2015 compared to the six months ended June 30, 2014.

The Southern Appalachian region coal production and coal royalty revenues were virtually flat in the six months ended June 30, 2015 as compared to the same period of 2014.

With respect to Northern Appalachia, during the six months ended June 30, 2015, there was an increase in coal production of 1.6 million tons and coal royalty revenue decreased $2.8 million, or 67%. Our revenue per ton in the region was lower primarily due to one of our leases, which has a very low royalty per ton, being a larger proportion of production in the region.

Illinois Basin

Illinois Basin coal production decreased 1.0 million tons, or 15%, and coal royalty revenues decreased $4.5 million, or 17%, in the six months ended June 30, 2015 as compared to the same period of 2014. These decreases were due primarily to lower pricing received by our lessees and lower demand.

Northern Powder River Basin

Northern Powder River Basin coal production increased 1.1 million tons, or 109%, and coal royalty revenues increased $2.6 million, or 88%, in the six months ended June 30, 2015 as compared to the same period of 2014. Coal royalty revenues and production increased on our Western Energy property due to the normal variations that occur due to the checkerboard nature of ownership.

Gulf Coast

Gulf Coast coal production and coal royalty revenues were virtually flat in the six months ended June 30, 2015 as compared to the same period of 2014.

Other Coal Related Revenues

Other coal related revenues for the six months ended June 30, 2015 increased $16.3 million, or 88%, compared to the same period in 2014. Override revenue for the six months ended June 30, 2015 decreased by 36% compared to the same period in 2014, primarily due to one lessee moving its mining operations from an area on which we receive an overriding royalty onto property on which we receive coal royalty revenue. Minimums recognized as revenue increased $6.4 million, or 229%, for the six months ended June 30, 2015 when compared to the same period in 2014, primarily due to the recoupment period under our lease relating to Foresight Energy’s Macoupin mine expiring in 2015. Transportation and processing fees and wheelage were virtually flat year over year. Also included in other coal related revenues for the six months ended June 30, 2015 was a $1.7 million public roadway condemnation payment. In addition, we recognized a gain of $9.3 million on a reserve swap at Foresight Energy’s Williamson mine.

Aggregates Related Revenues and Industrial Minerals Other Income

Total aggregates related revenues and total industrial minerals other income represented approximately 39% and 15% of our total revenues and other income for the six months ended June 30, 2015 and 2014, respectively. The table below presents the major categories of our aggregates related revenues and industrial minerals other income:


	Six Months Ended June 30,				Increase (Decrease)			Percentage Change
	2015		2014		Increase (Decrease)			Percentage Change
	(In thousands, except percent and per ton data) (Unaudited)
VantaCore:
Tonnage sold		3,526		N/A		N/A			N/A
Revenues	$	67,398		N/A		N/A			N/A
Operating expenses	$	55,207		N/A		N/A			N/A
Aggregates related royalty revenues	$	4,434	$	6,959	$	(2,525	)		(36	)%
Total aggregates related revenues	$	71,832	$	6,959	$	64,873			932	%

Industrial minerals other income and cash distributions:
Equity in earnings of unconsolidated investment	$	24,122	$	19,180	$	4,942			26	%
Cash distributions from equity earnings in unconsolidated investment	$	21,805	$	25,568	$	(3,763	)		(15	)%

VantaCore

VantaCore operates hard rock quarries, sand and gravel plants, asphalt plants and a marine terminal in Pennsylvania, West Virginia, Tennessee, Kentucky and Louisiana. We recognized $67.4 million of aggregates related revenues from VantaCore’s operations in the six months ended June 30, 2015.

Aggregates Related Royalty Revenues

Aggregates related royalty revenues decreased $2.5 million, or 36%, in the six months ended June 30, 2015 as compared to the same period of 2014. This decrease is primarily due to a lessee moving from property where we collect a 15% royalty to property where we collect a 1% override.

Industrial Minerals Other Income and Cash Distributions

For the six months ended June 30, 2015, equity in the earnings of our investment in the OCI Wyoming trona mining and soda ash production business was $24.1 million, and we received $21.8 million in cash distributions from OCI Wyoming. For the six months ended June 30, 2014, we recorded equity in the earnings of OCI Wyoming of $19.2 million and received $25.6 million in cash distributions.

Oil and Gas Related Revenues

Total oil and gas related revenues comprised approximately 12% and 16% of our total revenues and other income for the six months ended June 30, 2015 and 2014, respectively. 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 related revenues:


	Six Months Ended June 30,				Increase (Decrease)			Percentage Change
	2015		2014		Increase (Decrease)			Percentage Change
	(Dollars in thousands, except per unit data) (Unaudited)
Williston Basin non-operated working interests:
Production volumes:
Oil (MBbl)		573		207		366			177	%
Natural gas (Mcf)		409		112		297			265	%
NGL (MBoe)		76		12		64			533	%
Average sales price per unit:
Oil (Bbl)	$	43.89	$	95.86	$	(51.97	)		(54	)%
Natural gas (Mcf)	$	2.54	$	7.54	$	(5.00	)		(66	)%
NGL (Boe)	$	12.21	$	48.50	$	(36.29	)		(75	)%

Revenues:
Oil	$	25,147	$	19,842	$	5,305			27	%
Natural gas		1,037		844		193			23	%
NGL		928		582		346			59	%
Non-production revenue		450		—		450			100	%

Total	$	27,562	$	21,268	$	6,294			30	%

Royalty and overriding revenues	$	2,507	$	6,612	$	(4,105	)		(62	)%

Total oil and gas related revenues	$	30,069	$	27,880	$	2,189			8	%

Oil and gas revenues increased $2.2 million, or 8%, for the six months ended June 30, 2015 when compared to the same period ended for 2014. The increase in revenues is due to increased production from the fourth quarter 2014 Sanish Field acquisition that was partially offset by lower oil and gas prices in 2015 as compared to 2014.

Other Revenues

Other revenues increased $1.8 million, or 20%, for the six months ended June 30, 2015 when compared to the same period ended for 2014 primarily as a result of a gain of $3.1 million on the sale of other assets in the second quarter of 2015.

Operating Expenses

Depreciation, depletion and amortization

Depreciation, depletion and amortization increased $25.1 million, or 81%, for the six months ended June 30, 2015 when compared to the same period ended for 2014, primarily as a result of the VantaCore and Sanish Field acquisitions during the fourth quarter of 2014. This increase was partially offset by a $3.8 million credit to adjust the impact of depletion expense recorded in prior periods as discussed in Note 1 to our consolidated financial statements incorporated herein by reference.

General and administrative expenses

General and administrative expenses increased $2.2 million, or 15%, for the six months ended June 30, 2015 when compared to the same period ended for 2014, primarily as a result of increased expenses associated with the VantaCore business offset somewhat by the decline in the market price of our common units used to value awards under our Long-Term Incentive Plan.

Interest Expense

Interest expense increased $7.4 million, or 19%, for the six months ended June 30, 2015 when compared to the same period ended for 2014, primarily as a result of additional debt incurred to complete acquisitions in the fourth quarter of 2014.

Liquidity and Capital Resources

Overview

We also have $425 million principal amount of 9.125% senior notes issued by NRP and NRP Finance, as co-issuers, that mature in 2018. While we believe we will be able to refinance these notes, we may not be able to do so on terms acceptable to us, if at all. Our ability to comply with the financial and other restrictive covenants in our debt agreements will be affected by the levels of cash flow from our operations and future events and circumstances beyond our control. In addition, our ability to refinance our debt may depend in part or our ability to access the debt or equity capital markets, which are challenging in the current market environment.

Generally, we satisfy our working capital requirements with cash generated from operations. We finance our acquisitions with available cash, borrowings under our revolving credit facilities, and the issuance of debt securities and common units. We typically access the capital markets to refinance amounts outstanding under our revolving credit facilities as we approach the limits under those facilities. Our current liabilities exceeded our current assets by approximately $120 million as of June 30, 2015, primarily due to debt that matures within one year consisting of $80.8 million of Opco’s senior notes and Opco’s $75 million term loan. Excluding these debt maturities, our current assets exceeded our current liabilities by approximately $36 million as of June 30, 2015.

Capital Expenditures

Our capital expenditures, other than for acquisitions, have historically been minimal. However, as a result of our Sanish Field oil and gas and VantaCore aggregates acquisitions in the fourth quarter of 2014, our operating capital expenditures have been higher in 2015 and will continue to be higher than historical levels. 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 and expect that the majority of our 2015 maintenance capital expenditures were incurred during the first half of the year. Total capital expenditures for NRP Oil and Gas for the three and six months ended June 30, 2015 were $12.3 million and $28.7 million, respectively. 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. VantaCore’s capital expenditures for the three and six months ended June 30, 2015 were $3.7 million and $4.9 million, respectively.

Cash Flows

Net cash provided by operating activities for the six months ended June, 2015 and 2014 was $106.1 million and $99.6 million, respectively. The majority of our cash provided by operations is generated from coal royalty revenues, our equity interest in OCI Wyoming and oil and gas revenues.

Net cash used in investing activities for the six months ended June 30, 2015 and 2014 was $22.5 million and $4.8 million, respectively.

Net cash used in financing activities for the six months ended June 30, 2015 and 2014 was $106.1 million and $117.3 million, respectively. During the six months ended June 30, 2015 and 2014, we had proceeds from loans of $25.0 million and $2.0 million, respectively. During the six months ended June 30, 2015 and 2014, these proceeds were offset by repayment of debt of $68.5 million and $53.5 million, respectively. Also during the six months ended June 30, 2015 and 2014, we paid cash distributions to our unitholders of $54.9 million and $78.6 million, respectively.

Capital Resources and Obligations

Indebtedness

As of June 30, 2015 and December 31, 2014, we had the following indebtedness:


	June 30, 2015		December 31, 2014
	(Unaudited)
Current portion of long-term debt, net	$	155,983	$	80,983
Long-term debt and debt-affiliate, net		1,276,135		1,394,240

Total debt and debt – affiliate, net	$	1,432,118	$	1,475,223

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.

Anadarko Contingent Consideration Payment Claim

The purchase agreement for the acquisition of our interest in OCI Wyoming requires us to pay additional contingent consideration to Anadarko to the extent certain performance criteria described in the purchase agreement are met at OCI Wyoming in any of the years 2013, 2014 or 2015. We paid $0.5 million and $3.8 million of consideration in the first quarter of 2014 and 2015, respectively, in satisfaction of our obligations under this agreement with respect to 2013 and 2014. As of June 30, 2015, we estimate, and have recorded $8.8 million as the amount that will be payable in the first quarter of 2016 with respect to 2015. We have no obligation to pay contingent consideration with respect to any period after 2015.

In March 2014, Anadarko gave us written notice that it believed certain reorganization transactions conducted in 2013 within the OCI organization triggered an acceleration of our obligation to pay the additional contingent consideration in full and demanded immediate payment of such amount. We disagreed with Anadarko’s position in a written response provided to Anadarko in April 2014. In April 2015, Anadarko sent a written request for additional information regarding the OCI reorganization and indicated that they are still considering this claim against us. We do not believe the reorganization transactions triggered an obligation to pay the additional contingent consideration. We responded in writing in May 2015, and we will continue to engage in discussions with Anadarko to resolve the issue if necessary. However, if Anadarko were to pursue and prevail on such a claim, we would be required to pay an amount to Anadarko in excess of the amounts already paid, together with the $8.8 million accrual described above, up to the maximum amount of the additional contingent consideration, minus a deductible. Under the purchase agreement, the maximum cumulative amount of additional contingent consideration is an amount equal to the net present value of $50 million. Any additional amount paid by us would be considered to be additional acquisition consideration and added to Equity and other unconsolidated investments and would reduce our liquidity.

Shelf Registration Statement and “At-the-Market” Program

In April 2015, we filed an automatically effective shelf registration statement on Form S-3 with the SEC that is available for registered offerings of common units and debt securities.

In November 2013, we initiated an at-the-market program to sell common units for an aggregate offering price of $75.0 million. As of December 31, 2014, we sold 1,559,914 common units for an average price of $16.05 for gross proceeds of $25.0 million. During the six months ended June 30, 2015, we did not sell any common units nor pay any commissions under this at-the-market program.

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 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, 2014.

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

Interest Rate Risk

Our exposure to changes in interest rates results from our borrowings under our revolving credit facility and term loan, which are subject to variable interest rates based upon LIBOR. At June 30, 2015, we had $390.0 million in variable interest rate debt. If interest rates were to increase by 1%, annual interest expense would increase approximately $3.9 million, assuming the same principal amount remained outstanding during the year.

Item 4.

Controls and Procedures

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, for the reason described in the paragraph below, the Chief Executive Officer and Chief Financial Officer concluded that these disclosure controls and procedures were ineffective 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.

In July 2015, NRP’s VantaCore Partners LLC/Winn Materials, LLC quarry in Clarksville, Tennessee received a 107(a) imminent danger order from the Mine Safety and Health Administration, which is a reportable item under Item 1.04 of Form 8-K. This event was not reported to management on a timely basis, resulting in a late filing of the required Form 8-K. NRP filed the Form 8-K promptly after management was notified of the citation, and NRP management has designed additional controls and procedures to provide reasonable assurance that information regarding mine safety is communicated to management on a timely basis in order for NRP to file future Form 8-Ks within the required time periods.

Changes in the Partnership’s Internal Control Over Financial Reporting

The ineffective disclosure controls and procedures that resulted in the Partnership’s late Item 1.04 Form 8-K filing described above did not implicate the Partnership’s internal control over financial reporting. In addition, there were no changes in the Partnership’s internal control over financial reporting during the second quarter of 2015 that materially affected, or were reasonably likely to materially affect, the Partnership’s internal control over financial reporting. The Partnership continues to integrate certain processes and related internal control over financial reporting as a result of the acquisition of VantaCore Partners LLC. The Partnership will continue to assess the effectiveness of its internal control over financial reporting as integration activities continue.

Part II. Other Information

Item 1.

Legal Proceedings

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes these claims will not have a material adverse effect on our financial position, liquidity, or operations.

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

Item 1A.

Risk Factors

During the period covered by this report, there were no material changes from the risk factors previously disclosed in Natural Resource Partners L.P.’s Annual Report on Form 10-K for the year ended December 31, 2014.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

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

Item 5.

Other Information

None.

Item 6.

Exhibits


Exhibit No.		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 the Current Report on Form 8-K filed on January 25, 2013).

2.2	—	Agreement and Plan of Merger, dated as of August 18, 2014, by and among VantaCore Partners LP, VantaCore LLC, the Holders named therein, Natural Resource Partners L.P., NRP (Operating) LLC and Rubble Merger Sub, LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on August 20, 2014).

2.3	—	Interest Purchase Agreement, by and among NRP Oil and Gas LLC, Kaiser-Whiting, LLC and the Owners of Kaiser-Whiting, LLC dated as of October 5, 2014 (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on October 6, 2014).

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).

4.2	—	Third Amendment, dated as of June 16, 2015, to Note Purchase Agreements, dated as of June 19, 2003, among NRP (Operating) LLC and the holders named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on June 18, 2015).

10.1	—	Third Amended and Restated Credit Agreement, dated as of June 16, 2015, by and among NRP (Operating) LLC, the lenders party thereto, Citibank, N.A. as Administrative Agent and Collateral Agent, Citigroup Global Markets Inc. and Wells Fargo Securities LLC as Joint Lead Arrangers and Joint Bookrunners, and Citibank, N.A., as Syndication Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 18, 2015).

10.2	—	Second Amendment, dated as of June 16, 2015, to Term Loan Agreement dated as of January 23, 2013, by and among NRP (Operating) LLC, the lenders named therein and Citibank, N.A., as Administrative Agent for the lenders (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on June 18, 2015).

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

SIGNATURES

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


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

Date: August 7, 2015

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

Date: August 7, 2015

	By:	/s/ Craig Nunez
		Craig Nunez,
		Chief Financial Officer and Treasurer
		(Principal Financial Officer)

Date: August 7, 2015

	By:	/s/ Chris Zolas
		Chris Zolas
		Chief Accounting Officer
		(Principal Accounting Officer)