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EX-31.2 - EXHIBIT 31.2 - NATURAL RESOURCE PARTNERS LPexhibit31233116.htm
EX-31.1 - EXHIBIT 31.1 - NATURAL RESOURCE PARTNERS LPexhibit31133116.htm
EX-95.1 - EXHIBIT 95.1 - NATURAL RESOURCE PARTNERS LPexhibit95133116.htm
EX-32.1 - EXHIBIT 32.1 - NATURAL RESOURCE PARTNERS LPexhibit32133116.htm
EX-32.2 - EXHIBIT 32.2 - NATURAL RESOURCE PARTNERS LPexhibit32233116.htm





 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 ______________________________________________________
FORM 10-Q
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2016
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 001-31465
  ______________________________________________________
NATURAL RESOURCE PARTNERS L.P.
(Exact name of registrant as specified in its charter)
  ______________________________________________________
Delaware
 
35-2164875
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
1201 Louisiana Street, Suite 3400
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)
(713) 751-7507
(Registrant’s telephone number, including area code) 
  ______________________________________________________
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “accelerated filer”, “large accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer
¨
Accelerated Filer
 
ý
Non-accelerated Filer
¨  (Do not check if a smaller reporting company)
Smaller Reporting Company
 
¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
At May 1, 2016 there were 12.2 million Common Units outstanding.
 







NATURAL RESOURCE PARTNERS, L.P.
TABLE OF CONTENTS





i






PART I. FINANCIAL INFORMATION 
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except per unit data) 
 
March 31,
2016
 
December 31,
2015
 
(Unaudited)
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
52,097

 
$
51,773

Accounts receivable, net
48,154

 
50,167

Accounts receivable—affiliates
7,525

 
6,864

Inventory
7,406

 
7,835

Prepaid expenses and other
3,835

 
4,490

Total current assets
119,017

 
121,129

Land
25,022

 
25,022

Plant and equipment, net
57,444

 
61,239

Mineral rights, net
1,060,829

 
1,094,027

Intangible assets, net
3,701

 
3,930

Intangible assets, net—affiliate
52,274

 
52,997

Equity in unconsolidated investment
258,939

 
261,942

Long-term contracts receivable—affiliate
45,931

 
47,359

Other assets
1,204

 
1,266

Other assets—affiliate
532

 
1,124

Total assets
$
1,624,893

 
$
1,670,035

LIABILITIES AND CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
7,595

 
$
8,465

Accounts payable—affiliates
1,227

 
1,464

Accrued liabilities
40,004

 
45,735

Current portion of long-term debt, net
154,441

 
80,745

Total current liabilities
203,267

 
136,409

Deferred revenue
76,750

 
80,812

Deferred revenueaffiliates
81,868

 
82,853

Long-term debt, net
1,146,958

 
1,270,281

Long-term debt, netaffiliate
19,936

 
19,930

Other non-current liabilities
5,839

 
6,808

Commitments and contingencies (see Note 10)

 

Partners’ capital:
 
 
 
Common unitholders’ interest (12.2 million units outstanding)
96,615

 
79,094

General partner’s interest
(249
)
 
(606
)
Accumulated other comprehensive loss
(2,697
)
 
(2,152
)
Total partners’ capital
93,669

 
76,336

Non-controlling interest
(3,394
)
 
(3,394
)
Total capital
90,275

 
72,942

Total liabilities and capital
$
1,624,893

 
$
1,670,035


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

1




NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands, except per unit data) 
(Unaudited)
 
Three Months Ended
 
March 31,
 
2016
 
2015
Revenues and other income:
 
 
 
Coal, hard mineral royalty and other
$
28,476

 
$
34,449

Coal, hard mineral royalty and other—affiliates
10,569

 
19,061

VantaCore
24,682

 
26,799

Oil and gas
7,298

 
14,779

Equity in earnings of Ciner Wyoming
9,801

 
12,523

Gain on asset sales
21,925

 
2,066

Total revenues and other income
102,751

 
109,677

 
 
 
 
Operating expenses:
 
 
 
Operating and maintenance expenses
30,902

 
37,421

Operating and maintenance expenses—affiliates, net
3,748

 
3,076

Depreciation, depletion and amortization
14,021

 
24,554

Amortization expense—affiliate
722

 
838

General and administrative
3,235

 
2,287

General and administrative—affiliates
937

 
1,084

Asset impairments
2,030

 

Total operating expenses
55,595

 
69,260

 
 
 
 
Income from operations
47,156

 
40,417

 
 
 
 
Other income (expense)
 
 
 
Interest expense
(23,748
)
 
(22,943
)
Interest income
19

 
15

Other expense, net
(23,729
)
 
(22,928
)
 
 
 
 
Net income
$
23,427

 
$
17,489

 

 
 
Net income attributable to partners:
 
 
 
Limited partners
23,024

 
17,139

General partner
403

 
350

 
 
 
 
Basic and diluted net income per common unit
$
1.88

 
$
1.40

 
 
 
 
Weighted average number of common units outstanding
12,230

 
12,230

 
 
 
 
Net income
$
23,427

 
$
17,489

Add: comprehensive loss from unconsolidated investment and other
(545
)
 
(965
)
Comprehensive income
$
22,882

 
$
16,524


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


2




NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands) 
(Unaudited)
 
Common Unitholders
 
General Partner
 
Accumulated
Other
Comprehensive
Loss
 
Partners' Capital Excluding Non-Controlling Interest
 
Non-Controlling Interest
 
Total Capital
 
 
Units
 
Amounts
 
Balance at December 31, 2015
12,230

 
$
79,094

 
$
(606
)
 
$
(2,152
)
 
$
76,336

 
$
(3,394
)
 
$
72,942

Distributions to unitholders

 
(5,503
)
 
(113
)
 

 
(5,616
)
 

 
(5,616
)
Net income

 
23,024

 
403

 

 
23,427

 

 
23,427

Non-cash contributions

 

 
67

 

 
67

 

 
67

Comprehensive loss from unconsolidated investment and other

 

 

 
(545
)
 
(545
)
 

 
(545
)
Balance at March 31, 2016
12,230

 
$
96,615

 
$
(249
)
 
$
(2,697
)
 
$
93,669

 
$
(3,394
)
 
$
90,275


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

3




NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
 
Three Months Ended
 
March 31,
 
2016
 
2015
Cash flows from operating activities:
 
 
 
Net income
$
23,427

 
$
17,489

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
14,021

 
24,554

Amortization expense—affiliates
722

 
838

Distributions from equity earnings from unconsolidated investments
12,250

 
10,903

Asset impairment
2,030

 

Gain on asset sales
(21,925
)
 
(2,066
)
Equity earnings from unconsolidated investment
(9,801
)
 
(12,523
)
Other, net
1,887

 
1,056

Other, net—affiliates
664

 
7

Change in operating assets and liabilities:
 
 
 
Accounts receivable
5,782

 
15,110

Accounts receivable—affiliates
(661
)
 
3,643

Accounts payable
(48
)
 
(2,642
)
Accounts payable—affiliates
(237
)
 
(14
)
Accrued liabilities
(5,900
)
 
(5,354
)
Deferred revenue
(4,063
)
 
5,845

Deferred revenue—affiliates
(985
)
 
(738
)
Other items, net
1,146

 
103

Other items, net—affiliates
1,119

 
(739
)
Net cash provided by operating activities
19,428

 
55,472

Cash flows from investing activities:
 
 
 
Acquisition of mineral rights
(2,725
)
 
(16,788
)
Acquisition of plant and equipment and other
(2,221
)
 
(1,365
)
Proceeds from sale of plant and equipment and other
3

 
905

Proceeds from sale of oil and gas properties
32,848

 
3,395

Proceeds from sale of coal and hard mineral royalty properties
9,802

 
866

Return of long-term contract receivables—affiliate
309

 
1,137

Net cash provided by (used in) investing activities
38,016

 
(11,850
)
Cash flows from financing activities:
 
 
 
Proceeds from loans

 
25,000

Repayments of loans
(51,166
)
 
(41,166
)
Distributions to partners
(5,616
)
 
(43,678
)
Distributions to non-controlling interest

 
(662
)
Debt issue costs and other
(338
)
 
83

Net cash used in financing activities
(57,120
)
 
(60,423
)
 
 
 
 
Net increase (decrease) in cash and cash equivalents
324

 
(16,801
)
Cash and cash equivalents at beginning of period
51,773

 
50,076

Cash and cash equivalents at end of period
$
52,097

 
$
33,275

 
 
 
 
Supplemental cash flow information:
 
 
 
Cash paid during the period for interest
$
13,812

 
$
14,344

Plant, equipment and mineral rights funded with accounts payable or accrued liabilities
811

 
3,761


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

4


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


1.    Basis of Presentation

Nature of Business

Natural Resource Partners L.P. (the "Partnership") engages principally in the business of owning, operating, managing and leasing a diversified portfolio of mineral properties in the United States, including interests in coal, trona and soda ash, oil and gas, construction aggregates, frac sand and other natural resources. As used in these Notes to Consolidated Financial Statements, the terms "NRP," "we," "us" and "our" refer to Natural Resource Partners L.P. and its subsidiaries, unless otherwise stated or indicated by context.

Principles of Consolidation and Reporting

The accompanying unaudited Consolidated Financial Statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP") for interim financial information and with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements.

Certain reclassifications have been made to prior period amounts to conform to the current period financial statement presentation. As described in "Note 2. Segment Information", we recasted certain prior period amounts to conform to the way we internally manage and monitor segment performance. In particular, prior year general and administrative charges that were allocated to operating segments have been reclassified to Operating and maintenance expenses and Operating and maintenance expenses—affiliates on the Consolidated Statements of Comprehensive Income. The prior period reclassifications for new segments had no impact on the Partnership's consolidated financial position, net income (loss) or cash flows. On January 1, 2016, the Partnership adopted a new accounting standard using a retrospective approach that required the presentation of the Partnership's debt issuance costs as a direct deduction from the related debt liability, rather than recorded as an asset. The adoption resulted in a reclassification that reduced other current assets and short-term debt by $0.2 million and reduced other assets and long-term debt (including affiliate) by $13.8 million on the Partnership’s Consolidated Balance Sheet at December 31, 2015.

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

Management’s Forecast, Strategic Plan and Going Concern Analysis
    
While NRP has a diversified portfolio of assets and a history and continued forecast of profitable operations with positive operating cash flows, its operating results and credit metrics continue to be impacted by demand challenges for coal and excess worldwide supply of oil and gas. In particular, as described in Note 7. Debt and Debt—Affiliate, NRP Oil and Gas LLC ("NRP Oil and Gas") and NRP Operating LLC ("Opco"), both wholly owned subsidiaries of NRP, have debt agreements that contain customary financial covenants, including maintenance covenants, and other covenants. In addition, NRP has issued $425 million of 9.125% Senior Notes that are governed by an indenture (the "Indenture") containing customary incurrence-based financial covenants and other covenants, but not maintenance covenants. The following discussion presents management’s going concern analysis in light of management’s outlook and strategic plan to address its debt covenant compliance and maturities.

Opco

As of March 31, 2016, Opco had $290.0 million of indebtedness outstanding under its revolving credit facility due October 2017 (the "Opco Credit Facility") and $544.9 million outstanding under several series of Private Placement Notes (the "Opco Private Placement Notes") (collectively referred to as the "Opco Debt agreements"). The maximum leverage ratio under the Opco Debt agreements is required to be below 4.0x through March 31, 2016. Commencing with respect to the period ending June 30, 2016, the maximum leverage ratio reduces to 3.75x and reduces again to 3.5x commencing with respect to the period ending June 30, 2017. In addition, the Opco Debt agreements contain certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations. Opco's leverage ratio was 3.09x at March 31, 2016.


5


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



While we forecast that we will be in compliance with all of the covenants under the Opco Debt agreements through March 31, 2017, our forecast is sensitive to commodity pricing and counterparty risk. Breaches of the Opco Debt agreement covenants that are not waived or cured, to the extent possible, would result in an event of default under the Opco Debt agreements, and if such debt is accelerated by the lenders thereunder, such acceleration would also result in a cross-default under the Indenture. We are currently pursuing or considering a number of actions in order to mitigate the effects of further commodity price and market deterioration which could otherwise cause us to breach financial covenants under the Opco Debt agreements. These actions include (i) dispositions of assets, (ii) actively managing our debt capital structure through a number of potential alternatives, including exchange offers and non-traditional debt financing, (iii) minimizing our capital expenditures, (iv) obtaining waivers or amendments from our lenders, (v) effectively managing our working capital and (vi) improving our cash flows from operations.

NRP Oil and Gas

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

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

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

Reverse Unit Split

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

Recently Issued Accounting Standards Not Yet Adopted

In May 2014, the Financial Accounting Standards Board ("FASB") amended its guidance on revenue recognition. The core principle of this amendment is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted for reporting periods beginning after December 15, 2016, including interim reporting periods within that period. This guidance can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial position, results of operations and cash flows.


6


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



In August 2014, the FASB issued guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The guidance is effective for interim and annual periods ending after December 15, 2016 and early adoption is permitted. The new guidance will require a formal assessment of going concern by management based on criteria prescribed in the new guidance, but will not impact the Partnership's financial position or results of operations. The Partnership is reviewing its policies and processes to ensure compliance with this new guidance.

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

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

2.    Segment Information

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

The Partnership's segments are strategic business units that offer products and services to different customer segments in different geographies within the U.S. and that are managed accordingly. NRP has the following four operating segments:

Coal, Hard Mineral Royalty and Other—consists primarily of coal royalty, coal related transportation and processing assets, aggregate and industrial minerals royalty assets and timber. Our coal reserves are primarily located in Appalachia, the Illinois Basin and the Western United States. Our aggregates and industrial minerals are located in a number of states across the United States. In February 2016, we sold aggregates reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee.

Soda Ash—consists of the Partnership's 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. Ciner Resources LP, our operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. We receive regular quarterly distributions from this business.

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

Oil and Gas—consists of our non-operated working interests, royalty interests and overriding royalty interests in oil and natural gas properties. Our primary interests in oil and natural gas producing properties are non-operated working interests located in the Williston Basin in North Dakota and Montana. We also own fee mineral, royalty or overriding royalty interests in oil and gas properties in Oklahoma and Louisiana. In February 2016, we sold royalty and overriding royalty interests in several producing properties located in the Appalachian Basin.


7


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



Direct segment costs and certain costs incurred at a corporate level that are identifiable and that benefit the Partnership's segments are allocated to the operating segments. These allocated costs include costs of: taxes, legal, information technology and shared facilities services and are included in Operating and maintenance expenses and Operating and maintenance expenses—affiliates on the Consolidated Statements of Comprehensive Income. Prior year general and administrative charges that are allocated to the operating segments have been reclassified to operating and maintenance expenses. Intersegment sales are at prices that approximate market.

Corporate and Financing includes functional corporate departments that do not earn revenues. Costs incurred by these departments include corporate headquarters and overhead, financing, centralized treasury and accounting and other corporate-level activity not specifically allocated to a segment.

The following table summarizes certain financial information for each of the Partnership's operating segments (in thousands):
 
 
Operating Segments
 
 
 
For the Three Months Ended
 
Coal, Hard Mineral Royalty and Other
 
Soda Ash
 
VantaCore
 
Oil and Gas
 
Corporate and Financing
 
Total
For the three months ended March 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
Revenues (including affiliates)
 
$
39,045

 
$
9,801

 
$
24,682

 
$
7,298

 
$

 
$
80,826

Intersegment revenues (expenses)
 
21

 

 
(21
)
 

 

 

Gain on asset sales
 
1,590

 

 

 
20,335

 

 
21,925

Operating and maintenance expenses (including affiliates)
 
7,380

 

 
22,156

 
5,114

 

 
34,650

Depreciation, depletion and amortization
 
6,762

 

 
3,562

 
4,419

 

 
14,743

Asset impairment
 
1,893

 

 

 
137

 

 
2,030

Interest expense, net
 

 

 

 

 
(23,729
)
 
(23,729
)
Net income (loss)
 
24,600

 
9,801

 
(1,036
)
 
17,963

 
(27,901
)
 
23,427

 
 
 
 
 
 
 
 
 
 


 

For the three months ended March 31, 2015
 
 
 
 
 
 
 
 
 


 
 
Revenues (including affiliates)
 
$
53,510

 
$
12,523

 
$
26,799

 
$
14,779

 
$

 
$
107,611

Gain on asset sales
 
1,615

 

 

 
451

 

 
2,066

Operating and maintenance expenses (including affiliates)
 
8,414

 

 
25,434

 
6,649

 

 
40,497

Depreciation, depletion and amortization
 
10,016

 

 
3,856

 
11,520

 

 
25,392

Interest expense, net
 

 

 

 

 
(22,928
)
 
(22,928
)
Net income (loss)
 
36,695

 
12,523

 
(2,491
)
 
(2,939
)
 
(26,299
)
 
17,489

 
 
 
 
 
 
 
 
 
 


 


Total assets
 
 
 
 
 
 
 
 
 
 
 
 
March 31, 2016
 
1,016,827

 
258,939

 
196,720

 
132,324

 
20,083

 
1,624,893

December 31, 2015
 
1,047,922

 
261,942

 
200,348

 
158,862

 
961

 
1,670,035


3.    Equity Investment

We account for our 49% investment in Ciner Wyoming LLC ("Ciner Wyoming", and formerly "OCI Wyoming LLC") using the equity method of accounting. Ciner Wyoming distributed $12.3 million and $10.9 million to us in the three months ended March 31, 2016 and 2015, respectively.

The difference between the amount at which the investment in Ciner Wyoming is carried and the amount of underlying equity in Ciner Wyoming's net assets was $153.6 million and $154.8 million as of March 31, 2016 and December 31, 2015, respectively. This excess basis relates to plant, property and equipment and right to mine assets. The excess basis difference that relates to property, plant and equipment is being amortized into income using the straight-line method over a weighted average of

8


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



28 years. The excess basis difference that relates to right to mine assets is being amortized into income using the units of production method.

Our equity in the earnings of Ciner Wyoming is summarized as follows (in thousands):
 
Three Months Ended
March 31,
 
2016
 
2015
 
(Unaudited)
Income allocation to NRP’s equity interests
$
10,996

 
$
13,727

Amortization of basis difference
(1,195
)
 
(1,204
)
Equity in earnings of unconsolidated investment
$
9,801

 
$
12,523


The results of Ciner Wyoming’s operations are summarized as follows (in thousands):
 
Three Months Ended
March 31,
 
2016
 
2015
 
(Unaudited)
Sales
$
114,384

 
$
120,430

Gross profit
28,251

 
32,724

Net Income
22,441

 
28,014


The financial position of Ciner Wyoming is summarized as follows (in thousands):
 
March 31,
2016
 
December 31,
2015
 
(Unaudited)
 
 
Current assets
$
139,185

 
$
144,695

Noncurrent assets
233,236

 
233,845

Current liabilities
46,881

 
43,018

Noncurrent liabilities
110,518

 
116,808


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

4.    Plant and Equipment

The Partnership’s plant and equipment consist of the following (in thousands):
 
March 31,
2016
 
December 31,
2015
 
(Unaudited)
 
 
Plant and equipment at cost
$
77,565

 
$
92,203

Construction in process
1,323

 
1,074

Less accumulated depreciation
(21,444
)
 
(32,038
)
Total plant and equipment, net
$
57,444


$
61,239


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

9


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



5.    Mineral Rights

The Partnership’s mineral rights consist of the following (in thousands):
 
March 31, 2016
 
(Unaudited)
 
Carrying Value
 
Accumulated Depletion
 
Net Book Value
Coal, Hard Mineral Royalty and Other
$
1,269,633

 
$
(437,628
)
 
$
832,005

VantaCore
112,700

 
(3,475
)
 
109,225

Oil and Gas
136,392

 
(16,793
)
 
119,599

Total
$
1,518,725

 
$
(457,896
)
 
$
1,060,829

 
December 31, 2015
 
Carrying Value
 
Accumulated Depletion
 
Net Book Value
Coal, Hard Mineral Royalty and Other
$
1,278,274

 
$
(432,260
)
 
$
846,014

VantaCore
112,700

 
(3,082
)
 
109,618

Oil and Gas
155,293

 
(16,898
)
 
138,395

Total
$
1,546,267

 
$
(452,240
)
 
$
1,094,027


Depletion expense related to the Partnership’s mineral rights totaled $10.3 million and $19.9 million for the three months ended March 31, 2016 and 2015, respectively.

Sales of Royalty Properties

As discussed in Note 1. "Basis of Presentation," we are currently pursuing or considering a number of actions, including dispositions of assets, in order to mitigate the effects of further commodity price and market deterioration which could otherwise cause us to breach financial covenants under our debt agreements. As part of this plan, the Partnership sold the following assets during the three months ended March 31, 2016:
1)Oil and gas royalty and overriding royalty interests in several producing properties located in the Appalachian Basin for $37.5 million. The effective date of the sale was January 1, 2016, and the Partnership recorded a $20.3 million gain from this sale included in Gain on asset sales on its Consolidated Statement of Comprehensive Income.
2)Hard mineral reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee for $10.0 million. The effective date of the sale was February 1, 2016, and the Partnership recorded a $1.6 million gain from this sale included in Gain on asset sales on its Consolidated Statement of Comprehensive Income.

6.    Intangible Assets (Including Affiliate)

The Partnership's intangible assets—affiliate relate to above market coal transportation contracts with subsidiaries of Foresight Energy LP ("Foresight Energy") in which we receive throughput fees for the handling and transportation of coal.
 
March 31,
2016
 
December 31,
2015
 
(Unaudited)
 
 
Intangible assets—affiliate
$
81,109

 
$
81,109

Less accumulated amortization—affiliate
(28,835
)
 
(28,112
)
Total intangible assets, net—affiliate
$
52,274

 
$
52,997


Amortization expense related to the Partnership's intangible assets—affiliate totaled $0.7 million and $0.8 million for the three months ended March 31, 2016 and 2015, respectively.

10


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



The Partnership's intangible assets consist of permits, aggregate-related trade names and other agreements as follows (in thousands):
 
March 31,
2016
 
December 31,
2015
 
(Unaudited)
 
 
Intangible assets
5,076

 
5,076

Less accumulated amortization
(1,375
)
 
(1,146
)
Total intangible assets, net
$
3,701

 
$
3,930


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

7. Debt and Debt—Affiliate

As of March 31, 2016 and December 31, 2015, debt and debt—affiliate consisted of the following (in thousands):
 
March 31,
2016
 
December 31,
2015
 
(Unaudited)
 
 
NRP LP debt:
 
 
 
9.125% senior notes, with semi-annual interest payments in April and October, due October 2018, $300 million issued at 99.007% and $125 million issued at 99.5%
$
425,000

 
$
425,000

Opco debt (1):
 
 
 
$300 million floating rate revolving credit facility, due October 2017
290,000

 
290,000

4.91% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018
13,850

 
13,850

8.38% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2019
64,286

 
85,714

5.05% senior notes, with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020
38,462

 
38,462

5.31% utility local improvement obligation, with annual principal and interest payments in February, due March 2021
960

 
1,153

5.55% senior notes, with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023
21,600

 
21,600

4.73% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2023
60,000

 
60,000

5.82% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024
120,000

 
135,000

8.92% senior notes, with semi-annual interest payments in March and September, with annual principal payments in March, due March 2024
36,364

 
40,909

5.03% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026
148,077

 
148,077

5.18% senior notes, with semi-annual interest payments in June and December, with annual principal payments in December, due December 2026
42,308

 
42,308

NRP Oil and Gas debt:
 
 
 
Reserve-based revolving credit facility due November 2019
75,000

 
85,000

Total debt at face value
$
1,335,907

 
$
1,387,073

Net unamortized debt discount
(1,889
)
 
(2,077
)
Net unamortized debt issuance costs (1)
(12,683
)
 
(14,040
)
Total debt, net
$
1,321,335


$
1,370,956

Less: current portion of long-term debt
154,441

 
80,745

Total long-term debt
$
1,166,894

 
$
1,290,211

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

11


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



NRP Debt

NRP Senior Notes    

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

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

NRP and NRP Finance have the option to redeem the NRP Senior Notes, in whole or in part, at any time on or after April 1, 2016, at fixed redemption prices specified in the indenture governing the NRP Senior Notes (the "Indenture"). The Indenture contains covenants that, among other things, limit the ability of NRP and certain of its subsidiaries to incur or guarantee additional indebtedness. Under the Indenture, NRP and certain of its subsidiaries generally are not permitted to incur additional indebtedness unless, on a consolidated basis, the fixed charge coverage ratio (as defined in the indenture) is at least 2.0 to 1.0 for the four preceding full fiscal quarters. The ability of NRP and certain of its subsidiaries to incur additional indebtedness is further limited in the event the amount of indebtedness of NRP and certain of its subsidiaries that is senior to NRP’s unsecured indebtedness exceeds certain thresholds. As of March 31, 2016 and December 31, 2015, NRP was in compliance with the terms of the covenants contained under the Indenture.

Opco Debt

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

Revolving Credit Facility

In June 2015, Opco entered into a $300.0 million Third Amended and Restated Credit Agreement (the "A&R Revolving Credit Facility"), which amended and restated Opco’s $300.0 million Second Amended and Restated Credit Agreement due August 2016. The A&R Revolving Credit Facility matures on October 2, 2017, is guaranteed by all of Opco’s wholly owned subsidiaries, and is secured by liens on certain of the assets of Opco and its subsidiaries, as further described below.

Initially, indebtedness under the A&R Revolving Credit Facility bore interest, at Opco's option, at a rate of either:
the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 1%, in each case plus 2.375%; or
a rate equal to LIBOR plus 3.375%

Subsequent to the delivery of financial statements for the year ended December 31, 2015 to the lenders in March 2016, indebtedness under the A&R Revolving Credit Facility bears interest, at Opco's option, at a rate of either:
the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 1%, in each case plus an applicable margin ranging from 1.50% to 2.50% or
a rate equal to LIBOR plus an applicable margin ranging from 2.50% to 3.50%

The weighted average interest rates for the borrowings outstanding under the A&R Revolving Credit Facility for the three months ended March 31, 2016 and 2015 were 3.80% and 1.94%, respectively.

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

12


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



The A&R Revolving Credit Facility contains financial covenants requiring Opco to maintain: 
a leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the A&R Revolving Credit Facility) not to exceed:
4.0 to 1.0 for each fiscal quarter ending on or before March 31, 2016;
3.75 to 1.0 for each subsequent fiscal quarter ending on or before March 31, 2017; and
3.5 to 1.0 for each fiscal quarter ending on or after June 30, 2017; and
a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease expense) of not less than 3.5 to 1.0.

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

The A&R Revolving Credit Facility contains certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations. Included in the investment covenant are restrictions upon Opco’s ability to acquire assets where Opco does not maintain certain levels of liquidity. The A&R Revolving Credit Facility also contains customary events of default, including cross-defaults under Opco’s senior notes (as described below).

The A&R Revolving Credit Facility is collateralized and secured by liens on certain of Opco’s assets with a carrying values of $698.1 million and $709.9 million classified as Land, Mineral rights and Plant and equipment on the Partnership’s Consolidated Balance Sheet as of March 31, 2016 and December 31, 2015, respectively. The collateral includes (1) the equity interests in all of Opco’s wholly owned subsidiaries, other than NRP Trona LLC (which owns a 49% non-controlling equity interest in Ciner Wyoming), (2) the personal property and fixtures owned by Opco’s wholly owned subsidiaries, other than NRP Trona LLC, (3) Opco’s material coal royalty revenue producing properties, (4) real property associated with certain of VantaCore’s construction aggregates mining operations, and (5) certain of Opco’s coal-related infrastructure assets.

Opco Senior Notes   

Opco has issued several series of private placement senior notes (the “Opco Senior Notes") with various interest rates and principal due dates. As of March 31, 2016, and December 31, 2015, the Opco Senior Notes had cumulative principal balances of $544.9 million and $585.9 million, respectively. Opco made principal payments of $41.0 million on the Opco Senior Notes during each of the three months ended March 31, 2016 and 2015.

The Note Purchase Agreements relating to the Opco Senior Notes contain covenants requiring Opco to: 
maintain a ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the note purchase agreement) of no more than 4.0 to 1.0 for the four most recent quarters;
not permit debt secured by certain liens and debt of subsidiaries to exceed 10% of consolidated net tangible assets (as defined in the note purchase agreement); and
maintain the ratio of consolidated EBITDDA (as defined in the note purchase agreement) to consolidated fixed charges (consisting of consolidated interest expense and consolidated operating lease expense) at not less than 3.5 to 1.0.

The 8.38% and 8.92% Opco Senior Notes also provide that in the event that Opco’s leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the Note Purchase Agreements) exceeds 3.75 to 1.00 at the end of any fiscal quarter, then in addition to all other interest accruing on these notes, additional interest in the amount of 2.00% per annum shall accrue on the notes for the two succeeding quarters and for as long thereafter as the leverage ratio remains above 3.75 to 1.00. Opco has not exceeded the 3.75 to 1.00 ratio at the end of any fiscal quarter through March 31, 2016.

In connection with the entry into the A&R Revolving Credit Facility in June 2015, Opco entered into the Third Amendment to the Note Purchase Agreements (the "NPA Amendment") that provides for the security of the Opco Senior Notes by the same collateral package pledged by Opco and its subsidiaries to secure the A&R Revolving Credit Facility, as described above. In addition, the NPA Amendment includes a covenant that provides that, in the event Opco or any of its subsidiaries is subject to any additional or more restrictive covenants under the agreements governing its material indebtedness (including the A&R Revolving Credit Facility, and all renewals, amendments or restatements thereof), such covenants shall be deemed to be incorporated by

13


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



reference in the Opco Senior Notes and the holders of the Opco Senior Notes shall receive the benefit of such additional or more restrictive covenants to the same extent as the lenders under such material indebtedness agreement.

NRP Oil and Gas Debt

The RBL Facility    

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

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

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

In March 2016, the Company entered into an amendment to the RBL Facility (the “Fourth Amendment”) and repaid $10.0 million thereunder, which reduced the outstanding balance thereunder to $75.0 million. In connection with such repayment, the borrowing base under the RBL Facility was reduced from $88.0 million to $75.0 million in lieu of the May 2016 borrowing base redetermination. Per the Fourth Amendment, the borrowing base will be reduced to $70.0 million on August 1, 2016, and to $50.0 million on October 1, 2016, with any outstanding amounts under the RBL Facility in excess of the reduced principal amounts due and payable on their respective day. The next scheduled redetermination of the borrowing base under the RBL Facility will occur in November 2016.

The Fourth Amendment amends the financial covenants contained in the RBL Facility as follows:
The maximum total leverage ratio (defined as the ratio of the total debt to EBITDAX) will be increased from 3.5x to 4.0x at March 31, 2016 and 4.5x at June 30, 2016. Thereafter, the total leverage ratio will decrease to 3.5x for the remainder of the term of the RBL Facility.
The minimum current ratio will decrease from 1.0x to 0.75x at March 31, 2016 and June 30, 2016 and revert to 1.0x thereafter for the remainder of the term of the RBL Facility.

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

In addition, effective on the date of the Fourth Amendment, indebtedness under the RBL Facility bears interest, at the Company's option, at:
the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 4.0%; or
a rate equal to LIBOR, plus an applicable margin of 4.0%

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

14


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)




The Fourth Amendment contains several other amendments, including a requirement for NRP Oil and Gas to pay down the RBL Facility each month with excess cash flow (which amounts may not be reborrowed and will result in a corresponding reduction in the borrowing base) and a requirement to use the net proceeds of any asset sales to repay the RBL Facility (which amounts may not be reborrowed and will result in a corresponding reduction in the borrowing base). In addition, the Fourth Amendment waives the delivery of 2015 audited financial statements containing an audit opinion containing "a "going concern" or like qualification or exception" as an event of default under the RBL Facility.

8.    Fair Value Measurements

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

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

The following table (in thousands) shows the face and estimated fair values of the Partnership's debt and debt—affiliate:
 
March 31, 2016
 
December 31, 2015
 
Debt at Face Value
 
Estimated Fair Value
 
Debt at Face Value
 
Estimated Fair Value
 
(Unaudited)
 
 
 
 
NRP Senior Notes (1)
$
425,000

 
$
272,000

 
$
425,000

 
$
277,313

Opco Senior Notes and utility local improvement obligation (2)
545,907

 
349,380

 
587,073

 
383,065

Opco Revolving Credit Facility (3)
290,000

 
290,000

 
290,000

 
290,000

NRP Oil and Gas RBL Facility (3)
75,000

 
75,000

 
85,000

 
85,000

 
 
 
 
 
(1)
The Level 1 fair value is based upon quotations obtained for identical instruments on the closing trading prices near period end.
(2)
The Level 3 fair value is estimated by management using quotations obtained for comparable instruments on the closing trading prices near period end.
(3)
The Level 3 fair value approximates the carrying amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty.

9.    Related Party Transactions

Reimbursements to Affiliates of our General Partner

The Partnership’s general partner does not receive any management fee or other compensation for its management of Natural Resource Partners L.P. However, in accordance with the partnership agreement, the general partner and its affiliates are reimbursed for services provided to the Partnership and for expenses incurred on the Partnership’s behalf. Employees of Quintana Minerals Corporation ("QMC") and Western Pocahontas Properties Limited Partnership ("WPPLP"), affiliates of the Partnership, provide their services to manage the Company's business. QMC and WPPLP charge the Partnership the portion of their employee salary and benefits costs related to their employee services provided to NRP. In addition, the Partnership receives non-cash equity contributions from its general partner related to compensation paid directly by the general partner and not reimbursed by the Partnership. These amounts are presented as non-cash equity contributions on the Partnership's Consolidated Statements of Partners' Capital. These QMC and WPPLP employee management service costs and non-cash equity compensation expenses are presented as Operating and maintenance expenses—affiliates, net and General and administrative—affiliates on the Consolidated Statements of Comprehensive Income. NRP also reimburses overhead costs incurred by its affiliates to manage the Partnership's business. These overhead costs include certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by the Partnership’s general partner and its affiliates and are presented as Operating and maintenance expenses—affiliates, net and General and administrative—affiliates on the Consolidated Statements of

15


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



Comprehensive Income.

The Partnership had Accounts payable—affiliates to Quintana Minerals Corporation of $0.6 million and $1.1 million at March 31, 2016 and December 31, 2015, respectively, for services provided by Quintana Minerals Corporation to the Partnership. The Partnership had Accounts payable—affiliates to WPPLP of $0.6 million and $0.3 million at March 31, 2016 and December 31, 2015, respectively.

Direct general and administrative expenses charged to the Partnership by WPPLP and Quintana Minerals Corporation are as follows (in thousands):
 
Three Months Ended
March 31,
 
2016
 
2015
 
(Unaudited)
Operating and maintenance expenses—affiliates, net
$
2,776

 
$
2,702

General and administrative—affiliates
937

 
1,084


Cline Affiliates

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

Coal related revenues from Foresight Energy totaled $10.1 million and $18.3 million for the three months ended March 31, 2016 and 2015, respectively. As of March 31, 2016 and December 31, 2015, the Partnership had Accounts receivable—affiliates from Foresight Energy of $7.4 million and $6.4 million, respectively. The Partnership had recorded $81.6 million and $82.6 million in minimum royalty payments as Deferred revenue—affiliates at March 31, 2016 and December 31, 2015, respectively.

The Partnership owns and leases rail load out and associated facilities to Foresight Energy at Foresight Energy's Sugar Camp mine. The lease agreement is accounted for as a direct financing lease. Total projected remaining payments under the lease at March 31, 2016 were $80.2 million with unearned income of $34.5 million, and the net amount receivable was $45.7 million, of which $2.1 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets. Total projected remaining payments under the lease at December 31, 2015 were $81.2 million with unearned income of $35.4 million and the net amount receivable was $45.9 million, of which $2.0 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliates on the accompanying Consolidated Balance Sheets.

The Partnership holds a contractual overriding royalty interest from a subsidiary of Foresight Energy that provides for payments based upon production from specific tons at Foresight Energy's Sugar Camp operations. This overriding royalty was accounted for as a financing arrangement and is reflected as an affiliate receivable. The net amount receivable under the agreement as of March 31, 2016 was $4.5 million, of which $2.2 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate. The net amount receivable under the agreement as of December 31, 2015 was $4.9 million, of which $1.5 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliate on the accompanying Consolidated Balance Sheets.

Long-Term Debt—Affiliate

Cline Trust Company, LLC owns approximately 0.54 million of the Partnership’s common units and $20.0 million in principal amount of the Partnership’s 9.125% Senior Notes due 2018. The members of the Cline Trust Company are four trusts for the benefit of the children of Chris Cline, each of which owns an approximately equal membership interest in the Cline Trust Company. Cline Trust Company, LLC purchased the $20.0 million of the Partnership’s 9.125% Senior Notes due 2018 in the Partnership’s offering of $125.0 million additional principal amount of such notes in October 2014 at the same price as the other purchasers in that offering. The balance on this portion of the Partnership’s 9.125% Senior Notes due 2018 was $19.9 million as of March 31, 2016 and is included in Long-term debt, net—affiliate on the accompanying Consolidated Balance Sheet.

16


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)




Quintana Capital Group GP, Ltd.

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

At March 31, 2016, a fund controlled by Quintana Capital owned a majority interest in Corsa Coal Corp. ("Corsa"), a coal mining company traded on the TSX Venture Exchange that is one of the Partnership’s lessees in Tennessee. Corbin J. Robertson III, one of the Partnership’s directors, is Chairman of the Board of Corsa. Coal related revenues from Corsa totaled $0.5 million and $0.8 million for the three months ended March 31, 2016 and 2015, respectively. The Partnership had recorded $0.3 million in minimum royalty payments as Deferred revenue—affiliates at both March 31, 2016 and December 31, 2015. The Partnership also had Accounts receivable—affiliates totaling $0.1 million and $0.2 million from Corsa at March 31, 2016 and December 31, 2015, respectively.

WPPLP Production Royalty and Overriding Royalty

For the three months ended March 31, 2016, the Partnership recorded $0.6 million in operating and maintenance expenses—affiliates related to a non-participating production royalty payable to WPPLP pursuant to a conveyance agreement entered into in 2007. These charges were zero for the three months ended March 31, 2015. The Partnership had Other assets—affiliate from WPPLP of $0.5 million and $1.1 million at March 31, 2016 and December 31, 2015, respectively related to a non-production royalty receivable from WPPLP for overriding royalty interest on a mine.

10.    Commitments and Contingencies

Legal

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

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

Foresight Energy Disputes

On November 24, 2015, we filed a lawsuit against Foresight Energy’s subsidiary, Hillsboro Energy LLC ("Hillsboro"), in the Circuit Court of the Fourth Judicial Circuit in Montgomery County, Illinois. The lawsuit alleges, among other items, breach of contract by Hillsboro resulting from a wrongful declaration of force majeure at Hillsboro’s Deer Run mine in July 2015. In late March 2015, elevated carbon monoxide readings were detected at the Deer Run mine, and coal production at the mine was idled. In July 2015, we received the notice declaring a force majeure event at the mine as a result of the elevated carbon monoxide levels. The effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us minimum deficiency payments of $7.5 million per quarter, or $30.0 million per year. Foresight Energy's failure to make the deficiency payment with respect to 2015 and first quarter of 2016 resulted in a $23.6 million cash impact to us. Such amount will increase for each quarter during which mining operations continue to be idled. We do not currently have an estimate as to when the mine will resume coal production. If the mine remains idled for an extended period or if the mine is permanently closed, our financial condition could be adversely affected.


17


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



On April 1, 2016, we filed a lawsuit against Macoupin Energy, LLC (“Macoupin”), a subsidiary of Foresight Energy, in Macoupin County, Illinois. The lawsuit alleges that Macoupin has failed to comply with the terms of its coal mining, rail loadout and rail loop leases by incorrectly recouping previously paid minimum royalties. Foresight Energy’s failure to properly calculate its recoupable balance and failure to make payments in accordance with these lease agreements with respect to the third and fourth quarters of 2015 and the first quarter of 2016 resulted in a $4.7 million negative cash impact to us. While the Partnership plans to pursue its claim, a valuation allowance for the receivable amount has been recorded given the early stage of this ongoing litigation. It is possible that the Partnership’s current estimate of the valuation allowance related to this matter could change, perhaps materially, in the future.

11.    Major Customers

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

12.    Unit-Based Compensation

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

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

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

In connection with the phantom unit awards, the Compensation, Nominating and Governance Committee also granted tandem Distribution Equivalent Rights ("DERs"), which entitle the holders to receive distributions equal to the distributions paid on the Partnership’s common units between the date the units are granted and the vesting date. The DERs are payable in cash upon vesting but may be subject to forfeiture if the grantee ceases employment prior to vesting.

A summary of activity in the outstanding grants during 2016 is as follows (in thousands):
 
Phantom Units
Outstanding grants at January 1, 2016
126

Grants during the period

Grants vested and paid during the period
(28
)
Forfeitures during the period
(3
)
Outstanding grants at March 31, 2016
95


18


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)




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

In connection with the Long-Term Incentive Plan, payments are typically made during the first quarter of the year. Payments of $1.5 million and $4.4 million were made during the three months ended March 31, 2016 and 2015, respectively. The unaccrued cost associated with unvested outstanding grants and related DERs at March 31, 2016 and December 31, 2015, was $0.4 million and $0.7 million, respectively.

13.    Cash Distributions

The following table shows the distributions paid by the Partnership during the three months ended March 31, 2016 and 2015:
 
 
 
 
 
 
Total Distributions (In thousands)
Date Paid
 
Period Covered by Distribution
 
Distribution per Common Unit
 
Common Units
 
GP Interest
 
Total
2016
 
 
 
 
 
 
 
 
 
 
February 12, 2016
 
October 1 - December 31, 2015
 
$
0.45

 
$
5,503

 
$
113

 
$
5,616

2015
 
 
 
 
 
 
 
 
 
 
February 13, 2015
 
October 1 - December 31, 2014
 
$
3.50

 
$
42,804

 
$
874

 
$
43,678


14.  Supplementary Unrestricted Subsidiary Information

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


19


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



CONDENSED CONSOLIDATING BALANCE SHEETS
(in thousands)
 
 
March 31, 2016
 
 
Unrestricted Subsidiaries of NRP
 
NRP and its Restricted Subsidiaries
 
Eliminations
 
Total
ASSETS
 
 
 
 
 
 
 
 
Current assets (including affiliates)
 
$
10,101

 
$
109,133

 
$
(217
)
 
$
119,017

Mineral rights, net
 
131,905

 
928,924

 

 
1,060,829

Equity in unconsolidated investment
 

 
258,939

 

 
258,939

Other non-current assets (including affiliates)
 
734

 
185,374

 

 
186,108

Total assets
 
$
142,740


$
1,482,370


$
(217
)
 
$
1,624,893

LIABILITIES AND CAPITAL
 
 
 
 
 
 
 


Current portion of long-term debt, net
 
$
73,696

 
$
80,745

 
$

 
$
154,441

Other current liabilities (including affiliates)
 
6,217

 
42,636

 
(27
)
 
48,826

Long-term debt, net (including affiliate)
 

 
1,166,894

 

 
1,166,894

Other non-current liabilities (including affiliates)
 
4,778

 
159,679

 

 
164,457

Partners' capital
 
61,494

 
32,365

 
(190
)
 
93,669

Non-controlling interest
 
(3,445
)
 
51

 

 
(3,394
)
Total liabilities and capital
 
$
142,740


$
1,482,370


$
(217
)
 
$
1,624,893

 
 
 
 
 
 
 
 


 
 
December 31, 2015
 
 
Unrestricted Subsidiaries of NRP
 
NRP and its Restricted Subsidiaries
 
Eliminations
 
Total
ASSETS
 
 
 
 
 
 
 


Current assets (including affiliates)
 
$
21,540

 
$
100,178

 
$
(589
)
 
$
121,129

Mineral rights, net
 
134,445

 
959,582

 

 
1,094,027

Equity in unconsolidated investment
 

 
261,942

 

 
261,942

Other non-current assets (including affiliates) (1)
 
887

 
192,050

 

 
192,937

Total assets
 
$
156,872

 
$
1,513,752

 
$
(589
)
 
$
1,670,035

LIABILITIES AND CAPITAL
 
 
 
 
 
 
 


Current portion of long-term debt, net (1)
 
$

 
$
80,745

 
$

 
$
80,745

Other current liabilities (including affiliates)
 
7,351

 
48,356

 
(43
)
 
55,664

Long-term debt, net (including affiliate) (1)
 
83,600

 
1,206,611

 

 
1,290,211

Other non-current liabilities (including affiliates)
 
4,703

 
165,770

 

 
170,473

Partners' capital
 
64,663

 
12,219

 
(546
)
 
76,336

Non-controlling interest
 
(3,445
)
 
51

 

 
(3,394
)
Total liabilities and capital
 
$
156,872

 
$
1,513,752

 
$
(589
)
 
$
1,670,035

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


20


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
 
 
Three Months Ended March 31, 2016
 
 
Unrestricted Subsidiaries of NRP
 
NRP and its Restricted Subsidiaries
 
Total
Revenues
 
$
7,323

 
$
95,428

 
$
102,751

Operating expenses
 
9,401

 
46,194

 
55,595

Income (loss) from operations
 
(2,078
)
 
49,234

 
47,156

Other expense, net
 
1,090

 
22,639

 
23,729

Net income (loss)
 
(3,168
)
 
26,595

 
23,427

Add: comprehensive loss from unconsolidated investment and other
 

 
(545
)
 
(545
)
Comprehensive income (loss)
 
$
(3,168
)
 
$
26,050

 
$
22,882

 
 
 
 
 
 


 
 
Three Months Ended March 31, 2015
 
 
Unrestricted Subsidiaries of NRP
 
NRP and its Restricted Subsidiaries
 
Total
Revenues
 
$
14,900

 
$
94,777

 
$
109,677

Operating expenses
 
16,748

 
52,512

 
69,260

Income (loss) from operations
 
(1,848
)
 
42,265

 
40,417

Other expense, net
 
808

 
22,120

 
22,928

Net income (loss)
 
(2,656
)
 
20,145

 
17,489

Add: comprehensive loss from unconsolidated investment and other
 

 
(965
)
 
(965
)
Comprehensive income (loss)
 
$
(2,656
)
 
$
19,180

 
$
16,524


15. Deferred Revenue and Deferred Revenue—Affiliate

Most of the Partnership’s coal and aggregates lessees must make minimum annual or quarterly payments which are generally recoupable over certain time periods. These minimum payments are recorded as deferred revenue when received. The deferred revenue attributable to the minimum payment is recognized as revenue based upon the underlying mineral lease when the lessee recoups the minimum payment through production or in the period immediately following the expiration of the lessee’s ability to recoup the payments. The Partnership’s deferred revenue (including affiliate) consist of the following (in thousands):
 
March 31,
2016
 
December 31,
2015
 
(Unaudited)
 
 
Deferred revenue
$
76,750

 
$
80,812

Deferred revenue—affiliate
81,868

 
82,853

Total deferred revenue (including affiliate)
$
158,618

 
$
163,665


The Partnership recognized the following amounts of deferred revenue (including affiliate) attributable to previously paid minimums as Coal, hard mineral royalty and other revenue (in thousands):
 
Three Months Ended
March 31,
 
2016
 
2015
 
(Unaudited)
Coal, hard mineral royalty and other (1)
$
6,094

 
$
1,063

Coal, hard mineral royalty and other—affiliates
870

 
3,477

Total coal, hard mineral royalty and other (including affilaites)
$
6,964

 
$
4,540

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


21


NATURAL RESOURCE PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(Unaudited)



16.    Subsequent Events

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

Distribution Declared

On April 20, 2016 the Board of Directors of GP Natural Resource Partners LLC declared a distribution of $0.45 per unit to be paid by the Partnership on May 13, 2016 to unitholders of record on May 5, 2016.

Lease Modifications, Termination and Forfeitures of Minimum Royalty Balances

In April 2016, the Partnership entered into agreements with certain lessees to either modify or terminate existing coal related leases that resulted in the Partnership recognizing approximately $35 million of deferred revenue in April 2016 as follows:
An agreement that terminated a central Appalachia coal royalty lease and resulted in the lessee forfeiting the right to recoup $26.2 million of minimum royalties previously paid to the Partnership. The Partnership agreed to transfer its coal mineral rights that were subject to this former lease to the lessee. This terminated lease had no current or planned production and the mineral rights transferred had zero net book value on the Partnership's consolidated Balance Sheets as of March 31, 2016. As a result of this transaction, in April 2016 the Partnership will recognize $26.2 million of revenue.
Lease modifications of existing coal royalty leases resulted in lessee forfeiture of rights to recoup previously paid minimum royalties and the reduction in lessee recoupment time. As a result of these modifications, in April 2016 the Partnership will recognize approximately $9 million of revenue.





22






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

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

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

Such forward-looking statements include, among other things, statements regarding:
our business strategy;
our liquidity and access to capital and financing sources;
our financial strategy;
prices of and demand for coal, trona and soda ash, construction aggregates, crude oil and natural gas, frac sand and other natural resources;
estimated revenues, expenses and results of operations;
the amount, nature and timing of capital expenditures;
our ability to consummate planned asset sales and execute on our long-term strategic plan;
projected production levels by our lessees, VantaCore Partners LLC ("VantaCore"), and the operators of our oil and gas working interests;
Ciner Wyoming LLC’s ("Ciner Wyoming") trona mining and soda ash refinery operations;
the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us, and of scheduled or potential regulatory or legal changes; and
global and U.S. economic conditions.

These forward-looking statements speak only as of the date hereof and are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

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

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

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our consolidated financial statements and footnotes included elsewhere in this filing. Our discussion and analysis consists of the following subjects:
Executive Overview
Results of Operations
Liquidity and Capital Resources
Unrestricted Subsidiary Information
Off-Balance Sheet Transactions

23






Related Party Transactions
Recent Accounting Standards

Executive Overview

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

Coal, Hard Mineral Royalty and Other—consists primarily of coal royalty, coal related transportation and processing assets, aggregate and industrial minerals royalty assets and timber. Our coal reserves are primarily located in Appalachia, the Illinois Basin and the Western United States. Our aggregates and industrial minerals are located in a number of states across the United States. In February 2016, we sold aggregates reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee.

Soda Ash—consists of our 49% non-controlling equity interest in a trona ore mining operation and soda ash refinery in the Green River Basin, Wyoming. Ciner Resources LP, our operating partner, mines the trona, processes it into soda ash, and distributes the soda ash both domestically and internationally into the glass and chemicals industries. We receive regular quarterly distributions from this business.

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

Oil and Gas—consists of our non-operated working interests, royalty interests and overriding royalty interests in oil and natural gas properties. Our primary interests in oil and natural gas producing properties are non-operated working interests located in the Williston Basin in North Dakota and Montana. We also own fee mineral, royalty or overriding royalty interests in oil and gas properties in Oklahoma and Louisiana. In February 2016, we sold royalty and overriding royalty interests in several producing properties located in the Appalachian Basin.

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

Current Liquidity Position

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

We have significant debt service requirements, including $80.8 million each year through 2018 in principal payments on several series of private placement senior notes (the “Opco Senior Notes"), and $25.0 million in aggregate principal payments on NRP Oil and Gas' reserve-based lending credit facility (the "RBL Facility") through October 1, 2016, and our operating results continue to be impacted by the adverse conditions in the commodity markets. We continue to implement our long-term plan to strengthen our balance sheet, reduce debt and enhance liquidity in order to reposition the Partnership for future growth. As part of this plan, we reduced our cash distributions during 2015 by over 87%. The cash savings resulting from the distribution reductions are being used primarily to repay debt. We have also taken steps to reduce general and administrative and other overhead costs in connection with these efforts.


24






However, we have determined that the cash savings from the distribution cuts and our cost reduction efforts will not be sufficient to meet our deleveraging objectives and have determined to sell certain assets to help meet these objectives. In February 2016, we sold the aggregates reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee, which comprised approximately 0.8%, or $8.2 million of our mineral rights balance as of of December 31, 2015 for $10.0 million in cash. The effective date of the sale was February 1, 2016. In February 2016, we sold royalty and overriding royalty interests in several producing properties located in the Appalachian Basin, including our overriding royalty interests in the Marcellus Shale, for $37.5 million in cash. The sale included royalty and overriding royalty interests in approximately 765 gross producing wells as of December 31, 2015 and approximately 1.6%, or $17.1 million of our mineral rights balance as of of December 31, 2015. The effective date of the sale was January 1, 2016.

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

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

Current Results/Market Outlook

Coal, Hard Minerals Royalty and Other Business Segment

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

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

Although the U.S. coal industry is under extreme pressure, we do not know to what extent our properties will be affected. A number of coal producers have filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code, and additional producers may file for bankruptcy. Historically, our leases have generally been assumed and all pre-petition bankruptcy amounts have been cured in full in our lessees’ bankruptcy processes, but we have no assurance this will continue in the future. In October 2015, Patriot Coal Corporation completed the sale of its assets in accordance with its bankruptcy plan. All of our leases were assumed and assigned in the sale process, and we received full pre-petition cure payments. Alpha Natural Resources ("Alpha"), which is our second largest lessee, filed for Chapter 11 bankruptcy protection in August 2015. Alpha has continued operating and paying royalties to us following the bankruptcy filing. However, Alpha has reduced production and idled certain mines, and we expect that Alpha will continue to reduce production and/or idle mines during its bankruptcy process. Production cuts and mine idlings by Alpha have resulted in and will continue to result in decreased royalty payments to us to the extent such production cuts or idlings are on our properties. We estimate that Alpha owes us approximately $3.3 million in pre-petition royalties and minimum payments, and we expect to receive pre-petition amounts due to us with respect to any leases that are assumed in the bankruptcy process. Arch Coal, Inc. ("Arch") and Peabody Energy Corporation ("Peabody") filed for Chapter 11 bankruptcy protection in January 2016 and April 2016, respectively. While we do not yet know whether our leases will be assumed or rejected in these bankruptcy processes, our overall exposure to both Arch and Peabody is immaterial.

While producers of Central Appalachian thermal coal have struggled for an extended period due to the high cost nature of their operations, production from our Illinois Basin properties also decreased by 33% in the first three months of 2016 as compared

25






to the same period in 2015. Part of the decrease in production from our Illinois Basin properties is attributable to the idling of Foresight Energy's Deer Run mine (which we also refer to as our Hillsboro property) as a result of elevated carbon monoxide levels at the mine beginning in March 2015. In July 2015, we received a notice from Foresight Energy declaring a resulting force majeure event at the Deer Run mine. While we have filed a lawsuit disputing Foresight Energy’s claim of force majeure, the effect of a valid force majeure declaration would relieve Foresight Energy of its obligation to pay us quarterly minimum deficiency payments with respect to the Deer Run mine until mining resumes. Under the lease for the Deer Run mine, Foresight Energy is required to make minimum deficiency payments to us of $7.5 million per quarter, or $30.0 million per year. The amount payable to us as the minimum deficiency payment with respect to any quarter is reduced by the amount of coal royalties actually paid to us for tonnage sold at the mine with respect to that quarter. We received royalty payments on tonnage sold from coal stockpiles at the Deer Run mine during 2015, but these stockpiles have been depleted. Foresight Energy’s failure to make the deficiency payments with respect to the second, third and fourth quarters of 2015 and the first quarter of 2016 resulted in a negative cash impact to us of $23.6 million. Such amount will increase for each quarter during which mining operations continue to be idled. Foresight Energy has temporarily sealed the mine, and is continuing efforts to cure the elevated carbon monoxide levels, but we do not know when, or if, mining activities at the Deer Run mine will recommence.

The metallurgical coal markets continue to remain depressed. We derived approximately 32% of our coal royalty revenues and 31% of the related production from metallurgical coal during the first quarter of 2016. The global metallurgical coal market continues to suffer from oversupply driven in part by reduced demand from China. Domestic coal producers are also burdened by the effects of the relatively strong U.S. dollar, which increases the production cost of domestic coal producers relative to foreign producers.

Soda Ash Business Segment

For the three months ended March 31, 2016, our Soda Ash business segment contributed revenues and other income of $9.8 million, Adjusted EBITDA of $12.3 million, and Distributable Cash Flow of $5.0 million. Our trona mining and soda ash refinery investment performed slightly below our expectations due to certain operational, production related issues in the first quarter of 2016. We believe these issues have been resolved, the market remains firm, and that we should see improvements from Ciner Wyoming over the remainder of the year. Domestic sales volumes, which are typically sold at higher prices than soda ash sold internationally, have remained relatively stable. The cash we receive from Ciner Wyoming is in part determined by the quarterly distributions declared by Ciner Resources LP. For the three months ended March 31, 2016, we received $12.3 million in cash distributions from Ciner Wyoming.

VantaCore Business Segment

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

VantaCore’s construction aggregates mining and production business is largely dependent on the strength of the local markets that it serves and is also seasonal, with lower production and sales expected during the first quarter of each year due to winter weather. VantaCore’s Laurel Aggregates operation in southwestern Pennsylvania serves producers and oilfield service companies operating in the Marcellus and Utica Shales and was impacted during the first quarter of 2016 by the slowing pace of exploration and development of natural gas in those areas due to low natural gas prices. Increased local construction activity partially offset these declines during the three months ended March 31, 2016, but we expect that Laurel’s business will continue to be impacted by decreased natural gas development activities. VantaCore’s operations based in Clarksville, Tennessee and Baton Rouge, Louisiana depend on the pace of commercial and residential construction in those areas. The Clarksville operation performed above expectations during the first quarter of 2016, while the Baton Rouge operation volumes were lower than expected due to weather. In June 2015, VantaCore purchased a hard rock quarry operation located on the Tennessee River near Grand Rivers, Kentucky from one of NRP’s aggregates lessees that had previously idled the operation. This operation continues to lease reserves from NRP and sells its produced limestone aggregates in both the local market and downstream to river-based markets.


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Oil and Gas Business Segment

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

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

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

Management’s Forecast and Strategic Plan
    
Opco’s revolving credit facility matures in October 2017 and NRP’s 9.125% Senior Notes mature in October 2018. We believe we need to significantly improve our leverage ratios prior to the maturity thereof in order to be able to refinance or restructure such debt. We remain committed to our strategic plan announced in April 2015 to improve our balance sheet and reduce leverage, and intend to take all necessary steps to execute on that plan, including through asset sales and other means. During the first quarter of 2016, we completed asset sales for $47.5 million in gross proceeds. However, we believe the deterioration in the commodity markets will continue to have a negative impact on our results of operations, which in turn may prevent us from achieving our leverage ratio goals including those included in our debt agreement financial covenants. Traditionally, we have accessed the debt and equity capital markets on a regular basis and have relied on bank credit facilities to finance our business activities. However, due to the current commodity price environment and the state of the coal markets in particular, we believe we do not currently have the ability to access either the debt or equity capital markets. In addition, the volatility in the energy industry combined with recent bankruptcies and additional perceived credit risks of companies with coal and/or oil and gas exposure has resulted in traditional bank lenders seeking to reduce or eliminate their lending exposure to these companies. Accordingly, we will be required over the near term to run our business and service our debt through cash from operations or asset sales. In addition, we may be required to seek financing from non-traditional sources at unfavorable pricing or with unfavorable terms to run our business or to refinance or restructure our 2017 and 2018 debt maturities.

While NRP has a diversified portfolio of assets and a history and continued forecast of profitable operations with positive operating cash flows, its operating results and credit metrics continue to be impacted by demand challenges for coal and excess worldwide supply of oil and gas. In particular, as described in Note 7. Debt and Debt—Affiliate, NRP Oil and Gas LLC ("NRP Oil and Gas") and NRP Operating LLC ("Opco"), both wholly owned subsidiaries of NRP, have debt agreements that contain customary financial covenants, including maintenance covenants, and other covenants. In addition, NRP has issued $425 million of 9.125% Senior Notes that are governed by an indenture ("the Indenture") containing customary incurrence-based financial covenants and other covenants, but not maintenance covenants. The following discussion presents management’s going concern analysis in light of management’s outlook and strategic plan to address its debt covenant compliance and maturities.

Opco

As of March 31, 2016, Opco had $290.0 million of indebtedness outstanding under its revolving credit facility due October 2017 (the "Opco Credit Facility") and $544.9 million outstanding under several series of Private Placement Notes (the "Opco Private Placement Notes") (collectively referred to as the "Opco Debt agreements"). The maximum leverage ratio under the Opco Debt agreements is required to be below 4.0x through March 31, 2016. Commencing with respect to the period ended June 30, 2016, the maximum leverage ratio reduces to 3.75x and reduces again to 3.5x commencing with respect to the period ended June 30, 2017. In addition, the Opco Debt agreements contain certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations. Our Opco leverage ratio was 3.09x at March 31, 2016.


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While we forecast that we will be in compliance with all of the covenants under the Opco Debt agreements through March 31, 2017, our forecast is sensitive to commodity pricing and counterparty risk. Breaches of the Opco Debt agreement covenants that are not waived or cured, to the extent possible, would result in an event of default under the Opco Debt agreements, and if such debt is accelerated by the lenders thereunder, such acceleration would also result in a cross-default under the Indenture. We are currently pursuing or considering a number of actions in order to mitigate the effects of further commodity price and market deterioration which could otherwise cause us to breach financial covenants under the Opco Debt agreements. These actions include (i) dispositions of assets, (ii) actively managing our debt capital structure through a number of potential alternatives, including exchange offers and non-traditional debt financing, (iii) minimizing our capital expenditures, (iv) obtaining waivers or amendments from our lenders, (v) effectively managing our working capital and (vi) improving our cash flows from operations.

NRP Oil and Gas

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

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

Results of Operations

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

Adjusted EBITDA (Non-GAAP Financial Measure)

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

Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) less equity earnings from unconsolidated investment, gain on reserve swaps and income to non-controlling interest; plus distributions from equity earnings in unconsolidated investment, interest expense, depreciation, depletion and amortization and asset impairments. Adjusted EBITDA, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDA should not be considered in isolation or as a substitute for operating income (loss), net income (loss), cash flows provided by operating, investing and financial activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDA provides no information regarding a partnership's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax positions. Adjusted EBITDA does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital and other commitments and obligations. Our management team believes Adjusted EBITDA is a useful measure because it is widely used by financial analysts, investors and rating agencies for comparative purposes. Adjusted EBITDA is also a financial measure widely used by investors in the high-yield bond market. There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring items that materially affect our net income (loss), the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by different companies.

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The following table (in thousands) reconciles net income (loss) (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment for the three months ended March 31, 2016 and 2015:
 
 
Operating Segments
 
 
 
For the Three Months Ended
 
Coal, Hard Mineral Royalty and Other
 
Soda Ash
 
VantaCore
 
Oil and Gas
 
Corporate and Financing
 
Total
March 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
 
$
24,600

 
$
9,801

 
$
(1,036
)
 
$
17,963

 
$
(27,901
)
 
$
23,427

Less: equity earnings from unconsolidated investment
 

 
(9,801
)
 

 

 

 
(9,801
)
Add: distributions from unconsolidated investment
 

 
12,250

 

 

 

 
12,250

Add: depreciation, depletion and amortization
 
6,762

 

 
3,562

 
4,419

 

 
14,743

Add: asset impairment
 
1,893

 

 

 
137

 

 
2,030

Add: interest expense
 

 

 

 

 
23,748

 
23,748

Adjusted EBITDA
 
$
33,255

 
$
12,250

 
$
2,526

 
$
22,519

 
$
(4,153
)
 
$
66,397

 
 
 
 
 
 
 
 
 
 
 
 
 
March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
 
$
36,695

 
$
12,523

 
$
(2,491
)
 
$
(2,939
)
 
$
(26,299
)
 
$
17,489

Less: equity earnings from unconsolidated investment
 

 
(12,523
)
 

 

 

 
(12,523
)
Add: distributions from unconsolidated investment
 

 
10,903

 

 

 

 
10,903

Add: depreciation, depletion and amortization
 
10,016

 

 
3,856

 
11,520

 

 
25,392

Add: interest expense
 

 

 

 

 
22,943

 
22,943

Adjusted EBITDA
 
$
46,711

 
$
10,903

 
$
1,365

 
$
8,581

 
$
(3,356
)
 
$
64,204


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Distributable Cash Flow (Non-GAAP Financial Measure)

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

Distributable Cash Flow represents net cash provided by operating activities, plus returns of unconsolidated equity investments, proceeds from sales of assets, and returns of long-term contract receivables—affiliate, less maintenance capital expenditures and distributions to non-controlling interest. Although Distributable Cash Flow is a non-GAAP financial measure, we believe it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. Distributable Cash Flow may not be calculated the same for us as for other companies.

The following table (in thousands) reconciles net cash provided by operating activities (the most comparable GAAP financial measure) by business segment to Distributable Cash Flow for the three months ended March 31, 2016 and 2015:
 
 
Operating Segments
 
 
 
For the Three Months Ended
 
Coal, Hard Mineral Royalty and Other
 
Soda Ash
 
VantaCore
 
Oil and Gas
 
Corporate and Financing
 
Total
March 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
23,298

 
$
5,018

 
$
6,113

 
$
3,328

 
$
(18,329
)
 
$
19,428

Add: return on long-term contract receivables—affiliate
 
309

 

 

 

 

 
309

Add: proceeds from sale of mineral rights
 
9,802

 

 

 
32,848

 

 
42,650

Less: maintenance capital expenditures
 

 

 
(1,250
)
 
(2,725
)
 

 
(3,975
)
Distributable Cash Flow
 
$
33,409

 
$
5,018

 
$
4,866

 
$
33,451

 
$
(18,329
)
 
$
58,415

 
 
 
 
 
 
 
 
 
 
 
 
 
March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
46,154

 
$
6,449

 
$
7,317

 
$
15,345

 
$
(19,793
)
 
$
55,472

Add: return on long-term contract receivables—affiliate
 
1,137

 

 

 

 

 
1,137

Add: proceeds from sale of PP&E
 

 

 
905

 

 

 
905

Add: proceeds from sale of mineral rights
 
866

 

 

 
3,395

 

 
4,261

Less: maintenance capital expenditures
 
(158
)