Edgar Filing: NATURAL RESOURCE PARTNERS LP

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 March 31, 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):


Large Accelerated Filer	x		Accelerated Filer	¨

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

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

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

NATURAL RESOURCE PARTNERS, L.P.

TABLE OF CONTENTS

Part I. Financial Information


	Page
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets		3
Consolidated Statements of Comprehensive Income		4
Consolidated Statements of Cash Flows		5
Consolidated Statements of Partners’ Capital		6
Notes to Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

Item 3. Quantitative and Qualitative Disclosures About Market Risk		32

Item 4. Controls and Procedures		32

Part II. Other Information

Item 1. Legal Proceedings		33

Item 1A. Risk Factors		33

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		33

Item 3. Defaults Upon Senior Securities		33

Item 4. Mine Safety Disclosure		33

Item 5. Other Information		33

Item 6. Exhibits		34

Signatures		35

Part I. Financial Information

Item 1.

Consolidated Financial Statements

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit information)


	March 31, 2015			December 31, 2014
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	33,275		$	50,076
Accounts receivable, net		52,323			66,455
Accounts receivable—affiliate		5,851			9,494
Inventory		5,790			5,814
Prepaid expenses and other		4,154			4,279

Total current assets		101,393			136,118

Land		25,243			25,243
Plant and equipment, net		78,584			60,093
Mineral rights, net		1,773,449			1,781,852
Intangible assets, net		59,713			60,733
Equity in unconsolidated investment		262,722			264,020
Long-term contracts receivable—affiliate		49,610			50,008
Goodwill		29,465			52,012
Other assets		13,746			14,645

Total assets	$	2,393,925		$	2,444,724

LIABILITIES AND CAPITAL

Current liabilities:
Accounts payable	$	16,862		$	22,465
Accounts payable—affiliates		936			950
Accrued liabilities		50,772			43,533
Current portion of long-term debt		155,983			80,983

Total current liabilities		224,553			147,931

Deferred revenue		79,052			73,207
Deferred revenue—affiliates		86,315			87,053
Long-term debt, net		1,283,352			1,374,336
Long-term debt, net—affiliate		19,911			19,904
Other non-current liabilities		8,403			22,138

Partners’ Capital:
Common unitholders’ interest (122,299,825 units outstanding)		683,354			709,019
General partner’s interest		11,721			12,245
Accumulated other comprehensive loss		(1,424	)		(459	)

Total partners’ capital		693,651			720,805
Non-controlling interest		(1,312	)		(650	)

Total capital		692,339			720,155

Total liabilities and capital	$	2,393,925		$	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 March 31,
	2015			2014
	(Unaudited)
Revenues and other income:
Coal related revenues	$	30,421		$	33,646
Coal related revenues—affiliates		19,061			18,727
Aggregates related revenues		28,946			3,396
Oil and gas related revenues		15,230			10,058
Equity in earnings of unconsolidated investment		12,523			9,779
Property taxes		3,004			3,967
Other		492			736

Total revenues and other income		109,677			80,309
Costs and expenses:
Coal related expenses		1,321			577
Aggregates related expenses		22,407			73
Oil and gas related expenses		3,762			1,921
General and administrative		7,454			2,690
General and administrative—affiliates		3,786			3,094
Depreciation, depletion and amortization		25,392			14,647
Property, franchise and other taxes		5,138			4,868

Total operating expenses		69,260			27,870

Income from operations		40,417			52,439

Other income (expense)
Interest expense		(22,943	)		(19,860	)
Interest income		15			26

Other expense, net		(22,928	)		(19,834	)

Net income		17,489			32,605
Less: net income attributable to non-controlling interest		—			—

Net income attributable to NRP	$	17,489		$	32,605

Net income attributable to partners:
Limited partners	$	17,139		$	31,953

General partner	$	350		$	652

Basic and diluted net income per common unit	$	0.14		$	0.29

Weighted average number of common units outstanding		122,300			109,848

Net income	$	17,489		$	32,605
Comprehensive loss from unconsolidated investment and other		(965	)		(101	)

Comprehensive income attributable to NRP	$	16,524		$	32,504

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

NATURAL RESOURCE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Three Months Ended March 31,
	2015			2014
	(Unaudited)
Cash flows from operating activities:
Net income	$	17,489		$	32,605
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		25,392			14,647
Equity earnings from unconsolidated investment		(12,523	)		(9,779	)
Distributions from equity earnings from unconsolidated investment		10,903			11,645
Other, net		(1,010	)		747
Other, net—affiliates		7			—
Change in operating assets and liabilities:
Accounts receivable		15,110			(4,262	)
Accounts receivable—affiliates		3,643			(3,098	)
Accounts payable		(2,642	)		(1,568	)
Accounts payable—affiliates		(14	)		478
Accrued liabilities		921			1,256
Deferred revenue		5,845			330
Deferred revenue—affiliates		(738	)		3,412
Accrued incentive plan expenses		(6,275	)		(8,065	)
Other items, net		103			(18	)
Other items, net—affiliates		(739	)		300

Net cash provided by operating activities		55,472			38,630

Cash flows from investing activities:
Acquisition of mineral rights		(16,788	)		(1,804	)
Acquisition of plant and equipment		(1,365	)		—
Proceeds from sale of mineral rights		4,261			—
Proceeds from sale of plant and equipment		905			—
Return on direct financing lease and contractual override—affiliate		1,137			297

Net cash used in investing activities		(11,850	)		(1,507	)

Cash flows from financing activities:
Proceeds from loans		25,000			2,000
Repayment of loans		(41,166	)		(41,166	)
Proceeds from issuance of common units		—			4,513
Capital contribution by general partner		—			92
Distributions to non-controlling interest		(662	)		(974	)
Distributions to partners		(43,678	)		(39,218	)
Other		83			(57	)

Net cash used in financing activities		(60,423	)		(74,810	)

Net decrease in cash and cash equivalents		(16,801	)		(37,687	)
Cash and cash equivalents at beginning of period		50,076			92,513

Cash and cash equivalents at end of period	$	33,275		$	54,826

Supplemental cash flow information:
Cash paid during the period for interest	$	14,344		$	14,703
Plant, equipment and mineral rights funded with accounts payable or accrued liabilities	$	3,761		$	—

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 Units					General			Accumulated Other Comprehensive			Partners’ Capital Excluding Non-Controlling			Non- Controlling
	Units		Amounts			Partner			Loss			Interest			Interest			Total
Balance at December 31, 2014		122,300	$	709,019		$	12,245		$	(459	)	$	720,805		$	(650	)	$	720,155
Distributions to unitholders		—		(42,804	)		(874	)		—			(43,678	)		—			(43,678	)
Distributions to non-controlling interest		—		—			—			—			—			(662	)		(662	)
Net income		—		17,139			350			—			17,489			—			17,489
Comprehensive loss from unconsolidated investment and other		—		—			—			(965	)		(965	)		—			(965	)

Balance at March 31, 2015		122,300	$	683,354		$	11,721		$	(1,424	)	$	693,651		$	(1,312	)	$	692,339

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 three months ended March 31, 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, 2016, 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 $201.1 million in cash and common units. Headquartered in Philadelphia, Pennsylvania, VantaCore operates three 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 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 accounting for the VantaCore acquisition is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date. 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.

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.

The Partnership accounted for the transaction 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 accounting for the Sanish Field acquisition is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date. The results of operations of the acquisition have been included in our consolidated financial statements since the acquisition date.

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 months ended March 31, 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 March 31, 2014
	(Unaudited) (In thousands)
Revenue and other income except aggregates and oil and gas related revenues	$	66,876
Aggregates related revenues		33,166
Oil and gas related revenues		27,892

Total revenue	$	127,934

Net income	$	33,210

Basic and diluted net income per common unit	$	0.30

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

3.	Equity Investment

We account for our 49% investment in OCI Wyoming LLC (“OCI Wyoming”) using the equity method of accounting. In the three months ended March 31, 2015 and 2014, OCI Wyoming distributed $10.9 million and $11.6 million to us, respectively. The income allocated to NRP’s equity interests and amortization of fair value adjustments are summarized as follows (in thousands):


	Three Months Ended March 31,
	2015			2014
	(Unaudited)
Income allocation to NRP’s equity interests	$	13,727		$	11,276
Amortization of basis difference	$	(1,204	)	$	(1,497	)
Equity in earnings of unconsolidated investment	$	12,523		$	9,779

The financial position of OCI Wyoming at March 31, 2015 and December 31, 2014 and the results of OCI Wyoming’s operations for the three months ended March 31, 2015 and 2014 are summarized as follows (in thousands):


	Three Months Ended March 31,
	2015		2014
	(Unaudited)
Sales	$	120,430	$	116,240
Gross profit	$	32,724	$	27,119
Net income	$	28,014	$	23,012

	March 31, 2015		December 31, 2014
	(Unaudited)
Current assets	$	203,953	$	200,622
Noncurrent assets	$	201,746	$	202,282
Current liabilities	$	46,656	$	47,704
Noncurrent liabilities	$	149,262	$	149,192

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 $160.5 million and $162.7 million as of March 31, 2015 and December 31, 2014, respectively. The excess that relates to property, plant and equipment is being amortized into income over a weighted average of 28 years. The excess that relates to a right to mine asset is being amortized into income using the units of production method.

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. During the first quarter of 2015, the Partnership paid $3.8 million in contingent consideration to Anadarko, and during the first quarter of 2014 the Partnership paid $0.5 million in contingent consideration. As of March 31, 2015, the Partnership has estimated and recorded $8.8 million as an accrued liability 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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

4.	Plant and Equipment

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


	March 31, 2015			December 31, 2014
	(Unaudited)
Plant and equipment at cost	$	111,266		$	89,759
Construction in process		141			457
Less accumulated depreciation		(32,823	)		(30,123	)

Total plant and equipment, net	$	78,584		$	60,093

Depreciation and amortization expense related to our plant and equipment totaled $4.5 million and $1.3 million for the three months ended March 31, 2015 and 2014, respectively.

5.	Mineral Rights

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


	March 31, 2015			December 31, 2014
	(Unaudited)
Coal	$	1,541,343		$	1,541,572
Oil and Gas		570,195			560,395
Aggregates		212,690			211,490
Other		15,014			15,014
Less accumulated depletion and amortization		(565,793	)		(546,619	)

Total mineral rights, net	$	1,773,449		$	1,781,852

Depletion and amortization expense related to our mineral rights totaled $19.9 million and $12.5 million for the three months ended March 31, 2015 and 2014, respectively.

6.	Intangible Assets

Amounts recorded as intangible assets along with the balances and accumulated amortization are reflected in the table below (in thousands):


	March 31, 2015			December 31, 2014
	(Unaudited)
Contract intangibles	$	82,972		$	82,972
Other intangibles		3,004			3,004
Less accumulated amortization		(26,263	)		(25,243	)

Total intangible assets, net	$	59,713		$	60,733

Amortization expense related to our intangible assets totaled $1.0 million and $0.8 million for the three months ended March 31, 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 March 31, 2015 and December 31, 2014, debt and debt—affiliate consisted of the following (in thousands):


	March 31, 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%	$	422,356		$	422,167

Opco Debt:
$300 million floating rate revolving credit facility, due August 2016		225,000			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		18,467			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		24,300			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		110,000			110,000

Total debt and debt – affiliate		1,459,246			1,475,223
Less: current portion of long-term debt		(155,983	)		(80,983	)

Total long-term debt and debt – affiliate	$	1,303,263		$	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.

The indenture for the senior notes 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 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 thresholds.

Opco Debt

All of Opco’s debt is guaranteed by its wholly owned subsidiaries. As of March 31, 2015 and December 31, 2014, Opco was in compliance with the terms of the financial covenants contained in its debt agreements.

Senior Notes

Opco made principal payments of $41.0 million on its senior notes during each of the three months ended March 31, 2015 and 2014. The Opco senior note purchase agreement contains 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.

Revolving Credit Facility

The weighted average interest rates for the debt outstanding under Opco’s revolving credit facility for the three months ended March 31, 2015 and 2014 were 1.94% and 1.98%, respectively. Opco incurs a commitment fee on the undrawn portion of the revolving credit facility at rates ranging from 0.18% to 0.40% per annum. The facility includes an accordion feature whereby Opco may request its lenders to increase their aggregate commitment to a maximum of $500 million on the same terms.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Opco’s revolving credit facility 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 (as defined in the credit agreement) 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.

Term Loan Facility

During 2013, Opco issued $200 million in term debt. The weighted average interest rates for the debt outstanding under the term loan for the three months ended March 31, 2015 and 2014 were 2.19% and 2.25% 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.

NRP Oil and Gas Debt

Revolving Credit Facility

In August 2013, NRP Oil and Gas entered into a 5-year, $100 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 million with an initial borrowing base of $137 million. The maturity date of the credit facility is November 12, 2019. 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. At both March 31, 2015 and December 31, 2014, there was $110.0 million outstanding under the credit facility. The weighted average interest rate for the debt outstanding under the credit facility for each of the three months ended March 31, 2015 and 2014 was 2.43% and 1.91%, 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 March 31, 2015 and December 31, 2014, NRP Oil and Gas was in compliance with the terms of the financial covenants contained in its credit facility.

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.

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:


	March 31, 2015				December 31, 2014
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(Unaudited)
Assets
Contracts receivable – affiliate, current and long-term⁽³⁾	$	4,646	$	5,041	$	4,870	$	5,162

Debt and debt – affiliate
NRP LP senior notes⁽¹⁾	$	422,356	$	416,957	$	422,167	$	423,780
Opco revolving credit facility and term loan facility⁽²⁾	$	300,000	$	300,000	$	275,000	$	275,000
Opco senior notes and utility local improvement obligation⁽³⁾	$	626,890	$	629,521	$	668,056	$	672,740
NRP Oil and Gas revolving credit facility⁽²⁾	$	110,000	$	110,000	$	110,000	$	110,000

⁽¹⁾	The Level 2 estimated fair value was based upon quotations obtained for similar instruments on the closing trading prices near quarter end.

⁽²⁾	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.

⁽³⁾	The Level 3 estimated fair value was based on comparable term risk-free treasury issues with a market rate component determined by current financial instruments with similar characteristics.

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. The Partnership had accounts payable—affiliate to Quintana Minerals Corporation of $0.6 million at both March 31, 2015 and December 31, 2014, for services provided by Quintana to the Partnership. The Partnership had accounts payable—affiliate to Western Pocahontas of $0.3 million and $0.4 million at March 31, 2015 and December 31, 2015, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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


	Three Months Ended March 31,
	2015		2014
	(Unaudited)
General and administrative—affiliate	$	3,786	$	3,094

The Partnership also leases an office building in Huntington, West Virginia from Western Pocahontas Properties and recorded $0.2 million in general and administrative—affiliate in each of the three months ended March 31, 2015 and 2014.

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 Cline affiliates totaled $18.3 million and $17.9 million for the three months ended March 31, 2015 and 2014, respectively. As of March 31, 2015 and December 31, 2014 the Partnership had accounts receivable-affiliates from Cline affiliates of $5.6 million and $9.2 million, respectively. As of March 31, 2015, the Partnership had recorded $86.1 million in minimum royalty payments to date that have not been recouped by Foresight Energy.

The Partnership entered into a lease agreement related to the rail loadout and associated facilities at Foresight Energy’s Sugar Camp mine that has been accounted for as a direct financing lease. Total projected remaining payments under the lease at March 31, 2015 are $85.0 million with unearned income of $38.1 million, and the net amount receivable was $46.9 million, of which $1.8 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate. 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—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets.

In a separate transaction, the Partnership acquired a contractual overriding royalty interest from a subsidiary of Foresight Energy that will provide for payments based upon production from specific tons at the Sugar Camp operations. This overriding royalty was accounted for as a financing arrangement and is reflected as an affiliate receivable. The net amount receivable under the agreement as of March 31, 2015 was $4.6 million, of which $0.2 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate. The net amount receivable under the agreement as of December 31, 2014 was $5.6 million, of which $1.1 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets.

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 March 31, 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., 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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

At March 31, 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 $0.9 million for the three months ended March 31, 2015 and 2014, respectively.

As of March 31, 2015, the Partnership had recorded $0.2 million in minimum royalty payments to date that have not been recouped by Corsa. The Partnership also had accounts receivable—affiliate totaling $0.2 million and $0.3 million from Corsa at March 31, 2015 and December 31, 2014, respectively.

10.

Major Lessees

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


	Three Months Ended March 31,
	2015					2014
	(Unaudited)
	Revenues		Percent			Revenues		Percent
Foresight Energy and affiliates	$	18,298		17	%	$	17,882		22	%
Alpha Natural Resources	$	8,829		8	%	$	11,642		14	%

For the three months ended March 31, 2015, the Partnership derived over 25% of its total revenues and other income from the two companies listed above. The Partnership has a significant concentration of revenues with Foresight Energy and Alpha, 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 5% and 11% of the Partnership’s total revenues and other income for the three months ended March 31, 2015 and 2014, 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		468,486
Grants vested and paid during the year		(290,430	)
Forfeitures during the year		—

Outstanding grants at March 31, 2015		1,331,449

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 0.26% to 1.17% and 36.36% to 46.99%, respectively at March 31, 2015. The Partnership’s average distribution rate of 7.65% and historical forfeiture rate of 4.29% were used in the calculation at March 31, 2015. The Partnership recorded a reversal of expenses related to its plan to be reimbursed to its general partner of $0.1 million for the three months ended March 31, 2015 and reversal of expenses of $1.1 million for the three months ended March 31, 2014 due to the decline in the market price of the Partnership’s common units. In connection with the Long-Term Incentive Plan, payments are typically made during the first quarter of the year. Payments of $4.4 million and $5.3 million were made during the three month period ended March 31, 2015 and 2014, respectively.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In connection with the phantom unit awards, the Compensation, Nominating and Governace 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. 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 March 31, 2015 and March 31, 2014 was $6.6 million and $11.3 million, respectively.

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.

13.

Subsequent Events

The following represents material events that have occurred subsequent to March 31, 2015 through the time of the Partnership’s filing of this Quarterly Report on Form 10-Q with the Securities and Exchange Commission:

Distributions Declared

On April 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 May 14, 2015 to unitholders of record on May 5, 2015.

NRP Oil and Gas Revolving Credit Facility

In April 2015, the Partnership’s lenders completed their semi-annual redetermination of its borrowing base under the NRP Oil and Gas revolving credit facility and the $137.0 million borrowing base under that facility was redetermined to $105.0 million. In connection with this reduction, the Partnership repaid $5.0 million of outstanding borrowings under the NRP Oil and Gas revolving credit facility.

Equity Investment

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 are still considering this claim against the Partnership. The Partnership does not believe the reorganization transactions triggered an obligation to pay the additional contingent consideration and will continue to engage in discussions with Anadarko to resolve the issue. 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.

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, 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 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 three months ended March 31, 2015, we recorded revenues and other income of $109.7 million and Adjusted EBITDA of $64.2 million. Adjusted EBITDA is a non-GAAP financial measure. For a reconciliation of Adjusted EBITDA to net income, see “—Results of Operations—Three Months Ended March 31, 2015 compared to Three Months Ended March 31, 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, as well as 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 infrastructure assets that generate additional 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 Partners LLC (“VantaCore”), which we acquired in October 2014. VantaCore specializes in the construction materials industry and operates three 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 March 31, 2015, our liquidity consisted of $33.3 million in cash and $102 million in combined borrowing capacity under our revolving credit facilities. Subsequent to the end of the quarter, the borrowing base on the NRP Oil and Gas revolving credit facility was reduced to $105.0 million, reducing our combined borrowing capacity to $75.0 million. 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 declared a distribution with respect to the first quarter of 2015 of $0.09 per common unit, a 75% decrease from the distribution paid with respect to the prior quarter. We intend to use the annual cash savings from the distribution reduction to pay down Opco’s debt and improve our consolidated credit metrics. We have $80.9 million in principal payments due on Opco’s senior notes each year through 2018, and Opco’s revolving credit facility and term loan facility both mature in 2016. While we believe we have sufficient liquidity to meet our current financial needs, we will be required to repay or refinance the amounts outstanding under Opco’s credit facilities.

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 quarter of 2015, as compared to 35% of total revenues and other income first quarter of 2014. This increase is due primarily to our diversification efforts, including our acquisition of VantaCore in the fourth quarter of 2014. As an operating construction aggregates business, VantaCore generates higher revenues but experiences lower profit margins than our royalty businesses. Accordingly, we experienced a significant increase in revenues during the first quarter of 2015 as compared to the first quarter of 2014, while our Adjusted EBITDA declined approximately 7% from the same period. Coal-related revenues were down 6% for the first quarter of 2015 compared to the first quarter of 2014, due primarily to lower coal royalty revenues, which were down approximately 17% in Appalachia and 16% in the Illinois Basin from the prior period. During the first quarter of 2015, our investment in OCI Wyoming’s trona mining and soda ash production operations contributed $12.5 million in other income, up $2.7 million from the first quarter of 2014, and our oil and gas revenues increased to $15.2 million, up $5.2 million from the first quarter of 2014, due primarily to our acquisition of the Sanish Field assets.

The thermal coal market remains challenged and does not currently show any signs of recovery. We expect the markets for thermal coal to remain weak during 2015, and we anticipate that producers of Central Appalachian thermal coal will continue to struggle in the current market due to the high cost nature of their operations. In contrast, despite decreased production and coal royalty revenues from our properties in the Illinois Basin during the first quarter of 2015 as compared to the first quarter of 2014, we expect revenues from our properties in the basin to increase over the long-term, as production from the basin becomes a larger portion of overall U.S. thermal coal production due to the low cost nature of operations in that basin.

We continue to have substantial exposure to metallurgical coal, from which we derived approximately 40% of our coal royalty revenues and 33% of the related production during the first quarter of 2015. The global metallurgical coal market continues to suffer from oversupply in addition to reduced demand from China and a relatively strong U.S. dollar. The second quarter 2015 benchmark settled at a new multi-year low, and we do not anticipate that metallurgical coal prices will recover in 2015. Mine idlings resulting in reductions of production of metallurgical coal from our properties may occur during the year if prices remain at current levels. In addition, if coal prices continue to remain depressed for an extended period of time, the lessees on our coal properties may close some of their mines causing those coal properties to be impaired.

Our trona mining and soda ash refinery investment performed in line with our expectations during the first quarter of 2015. The international market for soda ash continues to grow, as global production capacity for high-cost synthetic soda ash continues to be reduced, and OCI Wyoming’s sales through ANSAC were better than expected. Domestic sales volumes, which are typically sold at higher prices than soda ash sold internationally, have remained relatively stable.

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 first quarter of each year are typically lower than the rest of the year and are also more difficult to forecast due to winter weather. VantaCore’s operations were significantly impacted by winter weather conditions. In addition, we expect that the Laurel Aggregates operation in southwestern Pennsylvania, which serves producers and oilfield service companies operating in the Marcellus and Utica Shales, will be impacted in 2015 by the slowing pace of exploration and development of natural gas in those areas due to low natural gas prices. VantaCore’s operations based in Clarksville, Tennessee and Baton Rouge, Louisiana depend on the pace of commercial and residential construction in those areas, each of which is typically slow in the first quarter of the year.

Global oil prices remain depressed in the first quarter as a result of continued supply growth from prior period development activity in the U.S., coupled with reduced global demand and a strong U.S. dollar. Natural gas prices are also low due to record levels of production and high storage inventories. As of the date of this filing, we have not hedged any of our future oil or natural gas production and, as a result, our oil and gas revenues will continue to be impacted by the current price environment. However, we are able to manage the capital expenditures associated with our Williston Basin non-operated working interest properties by evaluating well proposals on a well-by-well basis. We 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.

Results of Operations

Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

Adjusted EBITDA (Non-GAAP Financial Measure)

Adjusted EBITDA declined 7% in 2015 to $64.2 million from $69.0 million generated in 2014. This decrease in Adjusted EBITDA is mainly related to decreased coal related revenues.

Adjusted EBITDA is a non-GAAP financial measure that we define as net income less equity earnings in unconsolidated investment; 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 useful in evaluating our financial performance because this measure 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.


	Three Months Ended March 31,
	2015			2014
	(unaudited)
Net income	$	17,489		$	32,605
Less equity earnings in unconsolidated investment		(12,523	)		(9,779	)
Add distributions from equity earnings in unconsolidated investment		10,903			11,645
Add depreciation, depletion and amortization		25,392			14,647
Add interest expense, gross		22,943			19,860

Adjusted EBITDA	$	64,204		$	68,978

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 for a description of Opco’s debt agreements.

Distributable Cash Flow (Non-GAAP Financial Measure)

Distributable cash flow increased by 37%, or $14.4 million, to $53.3 million in the first quarter 2015, mainly due to timing of cash payments received by our aggregates related business and approximately $5.2 million related to the sale of some minerals rights and assets. In addition, for the first time, NRP has reduced distributable cash flow for maintenance capital expenditures. Maintenance capital expenditures for the three months ended March 31, 2015 were $8.5 million. 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 expect the majority of our 2015 maintenance capital expenditures will be incurred during the first half of the year.

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. 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:


	Three Months Ended March 31,
	2015			2014
	(Unaudited)
Net cash provided by operating activities	$	55,472		$	38,630
Return on direct financing lease and contractual overrides		1,137			297
Proceeds from sale of mineral rights		4,261			—
Proceeds from sale of plant and equipment		905			—
Maintenance capital expenditures		(8,486	)		—

Distributable cash flow	$	53,289		$	38,927

Diversified Natural Resource Revenues and Other Income

The following table shows our diversified sources of revenues in the three months ended March 31, 2015 and 2014:


	Three Months Ended March 31,
(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	$	49,482		$	28,946		$	12,523		$	15,230		$	3,496		$	109,677
Percentage of total		45	%		26	%		11	%		14	%		4	%

2014
Revenues	$	52,373		$	3,396		$	9,779		$	10,058		$	4,703		$	80,309
Percentage of total		65	%		4	%		12	%		13	%		6	%

Coal Related Revenues and Coal Related Revenues—Affiliates

Total coal related revenues comprised approximately 45% and 65% of our total revenues and other income for the three months ended March 31, 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 March 31,				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		1,745		2,651		(906	)		(34	)%
Central		4,384		4,376		8			N/A
Southern		974		984		(10	)		(1	)%

Total Appalachia		7,103		8,011		(908	)		(11	)%
Illinois Basin		2,584		3,122		(538	)		(17	)%
Northern Powder River Basin		1,304		879		425			48	%
Gulf Coast		117		240		(123	)		(51	)%

Total coal royalty production		11,108		12,252		(1,144	)		(9	)%

Average coal royalty revenue per ton
Appalachia
Northern	$	0.36	$	0.81	$	(.45	)		(56	)%
Central		3.99		4.58		(.59	)		(13	)%
Southern		4.81		5.55		(.74	)		(13	)%
Total Appalachia		3.21		3.45		(.24	)		(7	)%
Illinois Basin		4.05		3.99		.06			2	%
Northern Powder River Basin		2.69		2.97		(.28	)		(9	)%
Gulf Coast		3.52		3.40		.12			4	%
Combined average coal royalty revenue per ton	$	3.35	$	3.55	$	(.20	)		(6	)%

Coal royalty revenues
Appalachia
Northern	$	634	$	2,139		(1,505	)		(70	)%
Central		17,506		20,038		(2,532	)		(13	)%
Southern		4,686		5,464		(778	)		(14	)%

Total Appalachia		22,826		27,641		(4,815	)		(17	)%
Illinois Basin		10,467		12,470		(2,003	)		(16	)%
Northern Powder River Basin		3,507		2,610		897			34	%
Gulf Coast		412		815		(403	)		(49	)%

Total coal royalty revenue	$	37,212	$	43,536		(6,324	)		(15	)%

Other coal related revenues
Override revenue	$	691	$	1,343		(652	)		(49	)%
Transportation and processing fees		4,597		5,097		(500	)		(10	)%
Minimums recognized as revenue		4,540		1,470		3,070			209	%
DOH Property Sale		1,665		—		1,665			N/A
Wheelage		777		927		(150	)		(16	)%

Total other coal related revenues	$	12,270	$	8,837		3,433			39	%

Total coal related revenues and coal related revenues—affiliate	$	49,482	$	52,373		(2,891	)		(6	)%

Appalachia

Appalachian coal production decreased 0.9 million tons, or 11%, and coal royalty revenues decreased $4.8 million, or 17%, in the three-months ended March 31, 2015 as compared to the same period of 2014.

Production from our properties in the Central Appalachian region was essentially flat for the three months ended March 31, 2015 compared to the same quarter for 2014, but 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 $2.5 million, or 13%, for the three months ended March 31, 2015 compared to the three months ended March 31, 2014.

The Southern Appalachian region also had decreased production and coal royalty revenues, primarily due to one of our lessees curtailing production during a process to sell its business and the timing of sales by some other lessees coupled with lower realized prices for metallurgical coal.

With respect to Northern Appalachia, during the three months ended March 31, 2015 there was also a decrease in coal royalty revenue and production. These decreases were primarily due to certain lessees having a greater proportion of their production on adjacent properties. Our revenue per ton in the region was also 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 17%, and coal royalty revenues decreased $2.0 million, or 16%, in the three-months ended March 31, 2015 as compared to the same period of 2014. Increased production from Foresight Energy’s Williamson and Hillsboro mines was offset by lower sales from Foresight Energy’s Macoupin mine and another property in Indiana where a lessee not related to Foresight Energy had a greater proportion of production from adjacent properties. Prices received by our lessees were at or below those received in the same period in 2014.

Northern Powder River Basin

Northern Powder River Basin coal production increased 0.4 million tons, or 48%, and coal royalty revenues increased $0.9 million, or 34%, in the three months ended March 31, 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 decreased 0.1 million tons, or 51%, and coal royalty revenues decreased $0.4 million, or 49%, in the three months ended March 31, 2015 as compared to the same period of 2014. The decrease 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 March 31, 2015 increased $3.4 million, or 39% compared to the same period in 2014. Override revenue for the three months ended March 31, 2015 decreased by 49% 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 $3.1 million, or 209% for the three months ended March 31, 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 decreased $0.5 million or 10%. This reduction was due primarily to less tonnage being transported from our Illinois properties. Wheelage revenue decreased by $0.2 million, or 16%, for the three months ended March 31, 2015 compared to the same period in 2014. This slight decrease was due to the normal fluctuations of tonnage that are subject to wheelage charges. Also included in other coal related revenues for the three months ended March 31, 2015 was a $1.7 million public roadway condemnation payment.

Aggregates Related Revenues and Industrial Minerals Other Income

Total aggregates related revenues and total industrial minerals other income represented approximately 38% and 16% of our total revenues and other income for the three months ended March 31, 2015 and 2014, respectively. The table below presents the major categories of our aggregates related revenues and industrial minerals other income:


	Three Months Ended March 31,				Increase (Decrease)			Percentage Change
	2015		2014		Increase (Decrease)			Percentage Change
	(In thousands, except percent and per ton data) (Unaudited)
VantaCore:
Tonnage sold		1,486		N/A		N/A			N/A
Revenues	$	26,773		N/A		N/A			N/A
Operating expenses	$	22,407		N/A		N/A			N/A
Aggregates related royalty revenues	$	2,173	$	3,396		(1,223	)		(36	)%
Total aggregates related revenues	$	28,946	$	3,396		25,550			752	%

Industrial minerals other income and cash distributions:
Equity in earnings of unconsolidated investment	$	12,523	$	9,779		2,744			(28	)%
Cash distributions from equity earnings in unconsolidated investment	$	10,903	$	11,645		(742	)		(6	)%

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 $26.8 million of aggregates related revenues from VantaCore’s operations in the three months ended March 31, 2015.

Aggregates Related Royalty Revenues

Aggregates related royalty revenues decreased $1.2 million, or 36%, in the three-months ended March 31, 2015 as compared to the same period of 2014. This decrease is primarily due to a lessee moving from property we own to property we collect an override on, which is at a lower royalty rate resulting in a decrease of $0.7 million for the three months ended March 31, 2015 when compared to the first quarter of 2014. Also contributing to the decline was a mine idling by one of the aggregates lessees in Kentucky during 2014.

Industrial Minerals Other Income and Cash Distributions

For the three months ended March 31, 2015 equity in the earnings of our investment in the OCI Wyoming trona mining and soda ash production business was $12.5 million, and we received $10.9 million in cash distributions from OCI Wyoming. For the three months ended March 31, 2014, we recorded equity in the earnings of OCI Wyoming of $9.8 million and received $11.6 million in cash distributions.

Oil and Gas Related Revenues

Total oil and gas related revenues comprised approximately 14% and 13% of our total revenues and other income for the three months ended March 31, 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 March 31,				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)		307		68		239			351	%
Natural gas (Mcf)		221		15		206			1,373	%
NGL (MBoe)		40		3		37			1,233	%
Average sales price per unit:
Oil (Bbl)	$	39.34	$	105.53	$	(66.19	)		(63	)%
Natural gas (Mcf)	$	2.71	$	5.73	$	(3.02	)		(53	)%
NGL (Boe)	$	12.28	$	39.00	$	(26.72	)		(69	)%

Revenues:
Oil	$	12,076	$	7,176	$	4,900			68	%
Natural gas		598		86		512			595	%
NGL		491		117		374			320	%
Non-production revenue		450		—		450			100	%

Total	$	13,615	$	7,379	$	6,236			85	%

Royalty and overriding revenues	$	1,615	$	2,679	$	(1,064	)		(40	)%

Total oil and gas related revenues	$	15,230	$	10,058	$	5,172			51	%

Oil and gas revenues increased $5.2 million, or 51%, for the three months ended March 31, 2015 when compared to the same period ended for 2014. The increase in revenues is due to our Sanish Field properties acquired on November 12, 2014.

Other Revenues

Other revenues primarily include reimbursements of property taxes from our lessees, rentals, metal revenues and timber royalties. Other revenues decreased $1.2 million, or 26%, for the three months ended March 31, 2015 when compared to the same period ended for 2014 primarily as a result of lower property tax revenues due to lower assessments on our coal properties.

Operating Expenses

Depreciation, depletion and amortization

Depreciation, depletion and amortization increased $10.7 million, or 73%, for the three months ended March 31, 2015 when compared to the same period ended for 2014 primarily as a result of assets acquired 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 $5.5 million, or 94%, for the three months ended March 31, 2015 when compared to the same period ended for 2014, primarily as a result of increased expenses associated with the VantaCore business. General and administrative expenses were also lower in the three month period ending March 31, 2014 due to decreased long term incentive plan expenses resulting from a lower market price of our common units.

Interest Expense

Interest expense increased $3.1 million, or 16%, for the three months ended March 31, 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

In April 2015, we announced a long-term plan to strengthen our balance sheet, reduce debt and enhance liquidity in order to reposition the company for future growth. As part of that plan, our Board of Directors declared a distribution with respect to the first quarter of 2015 of $0.09 per common unit, a 75% decrease from the distribution paid with respect to the prior quarter. We intend to use the annual cash savings from the distribution reduction to pay down Opco’s debt and improve our consolidated credit metrics. As of March 31, 2015, we were in compliance with all of our debt covenant ratios. Opco’s revolving credit facility and term loan facility both mature during 2016. In addition, we are required to make approximately $81 million of principal payments in connection with Opco’s senior notes each year through 2018. 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. We will be required to repay or refinance these amounts. While we believe we will be able to refinance these amounts, 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.

As of March 31, 2015, we had $75 million in available borrowing capacity under Opco’s revolving credit facility and $27 million of available borrowing capacity under the NRP Oil and Gas revolving credit facility. Subsequent to the end of the quarter, the borrowing base on the NRP Oil and Gas revolving credit facility was redetermined to $105.0 million, reducing our combined borrowing capacity to $75.0 million. In addition to the amounts available under our revolving credit facilities, we had $33.3 million in cash at March 31, 2015. 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 $123 million as of March 31, 2015, primarily as a result of the reclassification of $75 million of long-term debt to current debt due in January 2016 and the use of cash to repay part of the principal on Opco’s notes.

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, we anticipate higher operating capital expenditures in 2015. A portion of the capital expenditures associated with both our oil and gas working interest business and VantaCore are maintenance capital expenditures, which are capital expenditures made to maintain the long-term production capacity of those businesses. These maintenance capital expenditures reduce our cash available for distribution to our unitholders. We finance the capital expenditures associated with our Williston Basin non-operated working interest oil and gas assets through a combination of cash flow from operations and are able to control the level of these capital expenditures by evaluating well proposals on a well-by-well basis. Total capital expenditures for NRP Oil and Gas for the three months ended March 31, 2015 were $16.8 million. 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. The capital expenditures in connection with VantaCore’s construction aggregates mining and production operations are generally funded through cash flow from operations. VantaCore’s capital expenditures for the three months ended March 31, 2015 were $1.2 million.

Cash Flows

Net cash provided by operating activities for the quarters ended March 31, 2015 and 2014 was $55.5 million and $38.6 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 quarters ended March 31, 2015 and 2014 was $11.9 million and $1.5 million, respectively.

Net cash used in financing activities for the quarters ended March 31, 2015 and 2014 was $60.4 million and $74.8, respectively. During the three months ended March 31, 2015 and 2014, we had proceeds from loans of $25.0 million and $2.0 million, respectively. During the three months ended March 31, 2015 and 2014, these proceeds were offset by repayment of debt of $41.2 million in each of the three month periods. Also during the three months ended March 31, 2015 and 2014, we paid cash distributions to our unitholders of $43.7 million and $39.2 million, respectively.

Capital Resources and Obligations

As of March 31, 2015 and December 31, 2014, we were and continue to be in compliance with the terms of all of the financial covenants contained in our debt agreements.

NRP Debt

As of the date of this filing, NRP debt consisted of $425.0 million in principal amount of 9.125% senior notes due October 2018 (the “NRP Senior Notes”). Interest on the NRP Senior Notes is payable semiannually in arrears on April 1 and October 1 of each year. The NRP Senior Notes are the senior unsecured obligations of NRP and NRP Finance. The notes rank equal in right of payment to all existing and future senior unsecured debt of NRP and NRP Finance and senior in right of payment to any subordinated debt of NRP and NRP Finance. The NRP Senior Notes are effectively subordinated in right of payment to all future secured debt of NRP and NRP Finance to the extent of the value of the collateral securing such indebtedness and are structurally subordinated in right of payment to all existing and future debt and other liabilities of NRP’s subsidiaries, including Opco’s revolving credit facility and term loan facility, each series of Opco’s existing senior notes, and NRP Oil and Gas’s revolving credit facility, all of which are described below. None of NRP’s subsidiaries guarantee the NRP Senior Notes.

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

Opco Debt

As of the date of this filing, Opco’s debt consisted of the following:

•

$225.0 million under a floating rate revolving credit facility, due August 2016;

•

$75.0 million under a floating rate term loan, due January 2016;

•

$18.5 million of 4.91% senior notes due 2018;

•

$85.7 million of 8.38% senior notes due 2019;

•

$46.2 million of 5.05% senior notes due 2020;

•

$1.2 million of 5.31% utility local improvement obligation due 2021;

•

$24.3 million of 5.55% senior notes due 2023;

•

$67.5 million of 4.73% senior notes due 2023;

•

$135.0 million of 5.82% senior notes due 2024;

•

$40.9 million of 8.92% senior notes due 2024;

•

$161.5 million of 5.03% senior notes due 2026; and

•

$46.2 million of 5.18% senior notes due 2026.

Opco Revolving Credit Facility

As of the date of this report, Opco had $75.0 million in available borrowing capacity under its $300 million revolving credit facility (the “Opco Revolving Credit Facility”), which matures on August 9, 2016. Opco’s obligations under the Opco Revolving Credit Facility are unsecured but are guaranteed by its subsidiaries. Opco may prepay all amounts outstanding under the Opco Revolving Credit Facility at any time without penalty. Indebtedness under the Opco Revolving Credit Facility bears interest, at our option, at either:

•

the Alternate Base Rate (as defined in the credit agreement) plus an applicable margin ranging from 0% to 1%; or

•

the Adjusted LIBO Rate (as defined in the credit agreement) plus an applicable margin ranging from 1.00% to 2.25%.

Opco incurs a commitment fee on the unused portion of the Opco Revolving Credit Facility at a rate ranging from 0.18% to 0.40% per annum.

The Opco Revolving Credit Facility 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) not less than 3.5 to 1.0.

Under an accordion feature in the Opco Revolving Credit Facility, Opco may request its lenders to increase their aggregate commitment to a maximum of $500 million on the same terms. However, Opco cannot be certain that its lenders will elect to participate in the accordion feature. To the extent the lenders decline to participate, Opco may elect to bring new lenders into the facility, but cannot make any assurance that the additional credit capacity will be available on existing or comparable terms.

Opco Term Loan

In connection with the OCI Wyoming soda ash business acquisition in January 2013, Opco entered into a 3-year, $200 million term loan facility (the “Opco Term Loan”) . The Opco Term Loan is guaranteed by Opco’s operating subsidiaries. We repaid $101.0 million of the Opco Term Loan during 2013 and an additional $24.0 million in the fourth quarter of 2014. The remaining balance of $75.0 million is due on January 23, 2016. The term loan facility contains financial covenants and other terms that are identical to those of Opco’s revolving credit facility.

Opco Senior Notes

Opco issued the senior notes listed above (collectively the “Opco Senior Notes”) under a note purchase agreement as supplemented from time to time. The senior notes are unsecured but are guaranteed by Opco’s subsidiaries. Opco may prepay the

senior notes at any time together with a make-whole amount (as defined in the note purchase agreement). If any event of default exists under the note purchase agreement, the noteholders will be able to accelerate the maturity of the senior notes and exercise other rights and remedies.

The senior note purchase agreement contains 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 to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.

All of Opco’s senior notes require annual principal payments in addition to semi-annual interest payments. Opco also makes annual principal and interest payments on the utility local improvement obligation.

NRP Oil and Gas Debt

NRP Oil and Gas Revolving Credit Facility.

NRP Oil and Gas has a senior secured, reserve-based revolving credit facility (the “NRP Oil and Gas Revolving Credit Facility”) in order to fund its non-operated working interests in oil and gas assets. The NRP Oil and Gas Revolving Credit Facility will mature on November 12, 2019 and is secured by a first priority lien and security interest in substantially all of the assets of NRP Oil and Gas. NRP Oil and Gas is the sole obligor under the NRP Oil and Gas Revolving Credit Facility, and neither NRP nor any of its other subsidiaries is a guarantor of such facility. As of March 31, 2015, the borrowing base under this facility was $137.0 million, and NRP Oil and Gas had $110.0 million outstanding thereunder. Effective April 21, 2015, the borrowing base was reduced to $105.0 million in connection with the regular, semi-annual redetermination thereof. As of the date of this report, NRP had $105.0 million outstanding under this facility.

Indebtedness under the NRP Oil and Gas Revolving 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 NRP Oil and Gas Revolving Credit Facility at a rate ranging from 0.375% to 0.50% per annum.

The NRP Oil and Gas Revolving Credit Facility contains certain covenants, which, among other things, require the maintenance of (i) 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 (ii) a current ratio of at least 1.0 to 1.0. The NRP Oil and Gas Revolving Credit Facility also contains other customary covenants, subject to certain agreed exceptions, including covenants restricting the ability of NRP Oil and Gas to, among other items, incur indebtedness; create, assume or permit to exist liens; be a party to or be liable on any hedging contract; engage in mergers or consolidations; transfer, lease, exchange, alienate or dispose of material assets or properties; pay distributions; make any acquisitions of, capital contributions to or other investments in any entity or property; extend credit or make advances or loans; or engage in transactions with affiliates. Events of default under the NRP Oil and Gas Revolving Credit Facility include payment defaults, misrepresentations and breaches of covenants by NRP Oil and Gas. The NRP Oil and Gas Revolving Credit Facility also contains a cross-default provision with respect to any indebtedness of NRP’s.

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 March 31, 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, and we will continue to engage in discussions with Anadarko to resolve the issue. 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 three months ended March 31, 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.

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. In addition, crude oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. These markets will likely continue to be volatile in the future.

Interest Rate Risk

Our exposure to changes in interest rates results from our borrowings under our revolving credit facility and term loan, which are subject to variable interest rates based upon LIBOR. At March 31, 2015, we had $410.0 million in variable interest rate debt. If interest rates were to increase by 1%, annual interest expense would increase approximately $4.1 million, assuming the same principal amount remained outstanding during the year.

Item 4.

Controls and Procedures

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

No changes were made to our internal control over financial reporting during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes these claims will not have a material effect on our financial position, liquidity or operations.

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.

NATURAL RESOURCE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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).

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: May 7, 2015

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

Date: May 7, 2015

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

Date: May 7, 2015

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

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