Document




 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 ______________________________________________________
FORM 10-Q
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2016
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 001-31465
  ______________________________________________________
image0a03.gif
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 November 4, 2016 there were 12,232,006 Common Units outstanding.
 


NATURAL RESOURCE PARTNERS, L.P.
TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
 
 





i


PART I. FINANCIAL INFORMATION 
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

NATURAL RESOURCE PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit data) 
 
September 30,
2016
 
December 31,
2015
 
(Unaudited)
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
92,391


$
41,204

Accounts receivable, net
44,139


43,633

Accounts receivable—affiliates, net
7,057


6,345

Inventory
7,160


7,835

Prepaid expenses and other
3,707


4,268

Current assets held for sale (see Note 6)
5,520

 
—

Current assets of discontinued operations (see Note 2)
991


17,844

Total current assets
160,965

 
121,129

Land
25,020


25,022

Plant and equipment, net
52,516


60,675

Mineral rights, net
924,181


984,522

Intangible assets, net
3,239


3,930

Intangible assets, net—affiliate
50,668

 
52,997

Equity in unconsolidated investment
257,661


261,942

Long-term contracts receivable—affiliate
44,224


47,359

Other assets
1,898


1,173

Other assets—affiliate
1,034


1,124

Non-current assets of discontinued operations (see Note 2)
—


110,162

Total assets
$
1,521,406

 
$
1,670,035

LIABILITIES AND CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
6,223


$
5,022

Accounts payable—affiliates
829


801

Accrued liabilities
44,816


44,997

Accrued liabilities—affiliates
—

 
456

Current portion of long-term debt, net
158,597


80,745

Current liabilities of discontinued operations (see Note 2)
835


4,388

Total current liabilities
211,300


136,409

Deferred revenue
40,050


80,812

Deferred revenue—affiliates
74,663


82,853

Long-term debt, net
1,041,984


1,186,681

Long-term debt, net—affiliate
—


19,930

Other non-current liabilities
4,404


5,171

Non-current liabilities of discontinued operations (see Note 2)
—


85,237

Commitments and contingencies (see Note 11)



Partners’ capital:



Common unitholders’ interest (12,232,006 units outstanding)
154,315


79,094

General partner’s interest
928


(606
)
Accumulated other comprehensive loss
(2,844
)

(2,152
)
Total partners’ capital
152,399

 
76,336

Non-controlling interest
(3,394
)
 
(3,394
)
Total capital
149,005

 
72,942

Total liabilities and capital
$
1,521,406

 
$
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
 
Nine Months Ended
 
September 30,
 
September 30,
 
2016
 
2015
 
2016
 
2015
Revenues and other income:
 
 
 
 
 
 
 
Coal royalty and other
$
27,504


$
40,431


$
116,336


$
112,139

Coal royalty and other—affiliates
21,434


19,535


49,508


70,938

VantaCore
31,757


39,616


88,081


107,058

Equity in earnings of Ciner Wyoming
10,753


12,617


30,742


36,739

Gain on asset sales, net
6,426


1,833


27,280


6,903

Total revenues and other income
97,874

 
114,032

 
311,947

 
333,777


 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Operating and maintenance expenses
31,242


37,746


87,824


106,338

Operating and maintenance expenses—affiliates, net
4,062


1,744


9,948


8,090

Depreciation, depletion and amortization
11,929


15,666


32,181


44,512

Amortization expense—affiliate
902


771


2,328


2,516

General and administrative
4,268


1,809


10,676


6,014

General and administrative—affiliates
867


2,424


2,670


3,809

Asset impairments
5,697


361,703


7,681


365,506

Total operating expenses
58,967

 
421,863

 
153,308

 
536,785


 
 
 
 
 
 
 
Income (loss) from operations
38,907


(307,831
)

158,639


(203,008
)

 
 
 
 
 
 
 
Other income (expense)
 
 
 
 
 
 
 
Interest expense
(22,491
)

(22,441
)

(66,742
)

(65,588
)
Interest expense—affiliate
—

 
(464
)
 
(523
)
 
(1,388
)
Interest income
3


—


29


16

Other expense, net
(22,488
)
 
(22,905
)
 
(67,236
)
 
(66,960
)

 
 
 
 
 
 
 
Net income (loss) from continuing operations
16,419

 
(330,736
)
 
91,403

 
(269,968
)
Income (loss) from discontinued operations (see Note 2)
7,112

 
(269,265
)
 
2,001

 
(279,966
)
Net income (loss)
23,531

 
(600,001
)
 
93,404

 
(549,934
)
Less: net loss attributable to non-controlling interest
—

 
1,244

 
—

 
—

Net income (loss) attributable to NRP
$
23,531

 
$
(598,757
)
 
$
93,404


$
(549,934
)

 
 
 
 

 
 
Net income (loss) attributable to limited partners:
 
 
 
 
 
 
 
Continuing operations
$
16,155


$
(322,133
)

$
89,771


$
(263,799
)
Discontinued operations
6,970


(263,880
)

1,961


(274,367
)
Total
$
23,125


$
(586,013
)

$
91,732


$
(538,166
)

 
 
 
 
 
 
 
Net income (loss) attributable to the general partner:
 
 
 
 
 
 
 
Continuing operations
$
264


$
(7,359
)

$
1,632


$
(6,169
)
Discontinued operations
142


(5,385
)

40


(5,599
)
Total
$
406

 
$
(12,744
)
 
$
1,672

 
$
(11,768
)

 
 
 
 
 
 
 
Basic and diluted net income (loss) per common unit:
 
 
 
 
 
 
 
Continuing operations
$
1.32

 
$
(26.34
)
 
$
7.34

 
$
(21.57
)
Discontinued operations
0.57


(21.57
)

0.16


(22.43
)
Total
$
1.89

 
$
(47.91
)
 
$
7.50

 
$
(44.00
)

 
 
 
 
 
 
 
Weighted average number of common units outstanding
12,232


12,232


12,232


12,232


 
 
 
 
 
 
 
Net income (loss)
$
23,531

 
$
(600,001
)
 
$
93,404

 
$
(549,934
)
Add: comprehensive loss from unconsolidated investment and other
(609
)

(1,136
)

(692
)

(1,891
)
Less: comprehensive loss attributable to non-controlling interest
—

 
1,244

 
—

 
—

Comprehensive income (loss) attributable to NRP
$
22,922

 
$
(599,893
)
 
$
92,712

 
$
(551,825
)
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
12,232

 
$
79,094

 
$
(606
)
 
$
(2,152
)
 
$
76,336

 
$
(3,394
)
 
$
72,942

Distributions to unitholders
—

 
(16,511
)
 
(338
)
 
—

 
(16,849
)
 
—

 
(16,849
)
Net income
—

 
91,732

 
1,672

 
—

 
93,404

 
—

 
93,404

Non-cash contributions
—

 
—

 
200

 
—

 
200

 
—

 
200

Comprehensive loss from unconsolidated investment and other
—

 
—

 
—

 
(692
)
 
(692
)
 
—

 
(692
)
Balance at September 30, 2016
12,232

 
$
154,315

 
$
928

 
$
(2,844
)
 
$
152,399

 
$
(3,394
)
 
$
149,005


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)
 
Nine Months Ended
 
September 30,
 
2016
 
2015
Cash flows from operating activities:
 
 
 
Net income (loss)
$
93,404

 
$
(549,934
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities of continuing operations:
 
 
 
Depreciation, depletion and amortization
32,181

 
44,512

Amortization expense—affiliates
2,328

 
2,516

Distributions from equity earnings from unconsolidated investment
34,300


34,545

Equity earnings from unconsolidated investment
(30,742
)
 
(36,739
)
Gain on asset sales, net
(27,280
)
 
(6,903
)
(Income) loss from discontinued operations
(2,001
)
 
279,966

Asset impairments
7,681

 
365,506

Gain on reserve swap
—


(9,290
)
Other, net
6,694


(7,774
)
Other, net—affiliates
848


(2,139
)
Change in assets and liabilities:


 
Accounts receivable
(341
)

3,503

Accounts receivable—affiliates
(712
)

2,044

Accounts payable
635


(2,163
)
Accounts payable—affiliates
29


1,563

Accrued liabilities
7,287


8,485

Accrued liabilities—affiliates
(456
)
 
457

Deferred revenue
(40,762
)

6,035

Deferred revenue—affiliates
(8,190
)

(3,399
)
Other items, net
(356
)

1,400

Net cash provided by operating activities of continuing operations
74,547


132,191

Net cash provided by operating activities of discontinued operations
8,173

 
29,159

Net cash provided by operating activities
82,720


161,350

Cash flows from investing activities:
 
 
 
Proceeds from sale of oil and gas royalty properties
35,964


—

Proceeds from sale of coal and hard mineral royalty properties
18,214


3,505

Return of long-term contract receivables—affiliate
2,577


2,121

Proceeds from sale of plant and equipment and other
1,186


11,484

Acquisition of plant and equipment and other
(4,431
)

(8,581
)
Acquisition of mineral rights
—


(400
)
Net cash provided by investing activities of continuing operations
53,510


8,129

Net cash provided by (used in) investing activities of discontinued operations
106,821

 
(32,581
)
Net cash provided by (used in) investing activities
160,331


(24,452
)
Cash flows from financing activities:
 
 
 
Proceeds from loans
20,000


100,000

Repayments of loans
(106,174
)

(141,175
)
Distributions to partners
(16,849
)

(66,142
)
Distributions to non-controlling interest
—


(2,744
)
Proceeds from (contributions to) discontinued operations
40,226

 
(23,725
)
Debt issue costs and other
(14,072
)

(5,840
)
Net cash used in financing activities of continuing operations
(76,869
)
 
(139,626
)
Net cash provided by (used in) financing activities of discontinued operations
(125,564
)
 
13,808

Net cash used in financing activities
(202,433
)

(125,818
)
Net increase in cash and cash equivalents
40,618

 
11,080

Cash and cash equivalents of continuing operations at beginning of period
41,204

 
48,971

Cash and cash equivalents of discontinued operations at beginning of period
10,569

 
1,105

Cash and cash equivalents at beginning of period
51,773


50,076

Cash and cash equivalents at end of period
92,391


61,156

Less: cash and cash equivalents of discontinued operations at end of period
—

 
11,491

Cash and cash equivalents of continuing operations at end of period
$
92,391


$
49,665


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, construction aggregates 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. Discontinued Operations, the Partnership has classified the assets and liabilities, operating results and cash flows of its non-operated oil and gas working interest assets as discontinued operations in its consolidated financial statements for all periods presented.

As described in Note 3. Segment Information, the Partnership has reclassified certain prior period amounts to conform to the way it internally manages and monitors 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.

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

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

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


5

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



Management’s Forecast, Strategic Plan and Going Concern Analysis
    
While NRP has a diversified portfolio of assets and a history and continued forecast of profitable operations with positive operating cash flows, its operating results and credit metrics have been impacted by challenges in coal and other commodity markets. The following going concern analysis includes an evaluation of relevant conditions and events, including the Partnership's business performance and forecast, and its ability to meet its obligations and remain in compliance with its debt covenants over the next twelve months.

As described in Note 8. Debt and Debt—Affiliate, NRP Operating LLC ("Opco"), a wholly owned subsidiary of the Partnership, has debt agreements that contain customary financial covenants, including maintenance covenants, and other covenants. In addition, the Partnership has issued $425 million of 9.125% Senior Notes due October 2018 (the "NRP Senior Notes") that are governed by an indenture (the "Indenture") containing customary incurrence-based financial covenants and other covenants, but not maintenance covenants. As of September 30, 2016, Opco had $260.0 million of indebtedness outstanding under its revolving credit facility (the "Opco Credit Facility") with scheduled commitment reductions of $50.0 million on December 31, 2016, $30.0 million on June 30, 2017, $30.0 million on December 31, 2017, with the remaining balance of $150 million maturing on June 30, 2018. In addition, as of September 30, 2016 Opco had $529.9 million outstanding under several series of Private Placement Notes with scheduled principal payments of $80.8 million through September 30, 2017 (the "Opco Private Placement Notes") (collectively referred to as the "Opco Debt agreements"). The maximum leverage ratio under the Opco Debt agreements is required not to exceed 4.0x. In addition, the Opco Debt agreements contain certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations. Opco's leverage ratio was 2.95x at September 30, 2016.

The Partnership currently forecasts that it will meet its obligations, including scheduled principal and interest payments, that it will remain in compliance with its debt covenants, and that it will continue as a going concern. However, the forecast is sensitive to commodity demand, pricing and counterparty credit and operating risk. In addition, the scheduled debt principal payments in 2017 under Opco's Debt agreements will strain the Partnership's liquidity. Inability to make these payments would result in an event of default and could result in Opco’s lenders accelerating Opco’s debt. Breaches of the Opco debt covenants that are not waived or cured would have a similar effect. Any such acceleration by the Opco lenders would result in a cross-default under the NRP Indenture.

The Partnership has been and is currently pursuing or considering a number of actions in order to manage its liquidity and mitigate the effects of adverse market developments that could affect its ability to repay debt and remain in compliance with the covenants under its debt agreements. On a cumulative basis since January 1, 2015, the Partnership has reduced debt by $262.2 million and completed asset sales for $192 million in gross sales proceeds. In addition, the Partnership is continuing to take proactive steps with a long-term view to address its 2018 debt maturities and has engaged Greenhill & Co., LLC to advise in connection with these efforts. The Partnership is currently in active discussions with several institutional investors that may provide new equity capital to it. In addition, the Partnership has begun discussions with representatives of several holders of the NRP Senior Notes, and it may determine to pursue a refinancing or an exchange of some or all those notes.
 
As the Partnership pursues these capital markets transactions, it will continue to manage its business with a focus on debt reduction, cost management, and maximizing opportunities within its current asset base, including additional asset sales. The coal markets have shown improvement during the third quarter of 2016, particularly with respect to metallurgical coal, and the Partnership expects its coal royalty business to benefit from the higher pricing environment. However, to the extent that the Partnership is unable to execute on opportunistic capital raising and/or debt refinancing efforts on favorable terms and the coal markets do not show a sustained improvement, the Partnership’s liquidity may be adversely affected. Accordingly, the Partnership may consider other alternatives over the next several months to manage its liquidity and address its debt maturities.


6

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



Recently Issued Accounting Standards Not Yet Adopted

The Financial Accounting Standards Board ("FASB") amended its guidance on revenue recognition. The core principle of this amendment is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The guidance will also require enhanced disclosures, provide more comprehensive guidance for transactions such as service revenue and contract modifications, and enhance guidance for multiple-element arrangements. The Partnership is required to adopt this guidance in the first quarter of 2018 using one of two retrospective application methods. The Partnership is currently evaluating the provisions of this guidance and has not determined the impact this guidance may have on its consolidated financial statements and related disclosure or decided upon the method of adoption.

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

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

The FASB issued authoritative lease guidance that requires lessees to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The guidance also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The guidance is effective for annual and interim periods ending after December 31, 2018. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.

The FASB issued authoritative guidance that replaces the incurred loss impairment methodology in the current standard with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The guidance is effective for annual and interim periods ending after December 31, 2019. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.

The FASB issued authoritative guidance to clarify how certain cash receipts and cash payments are presented and classified in the statement of cash flows in order to reduce current and potential future diversity in practice. The guidance is effective for annual and interim periods ending after December 31, 2017. The Partnership is currently evaluating the impact of the provisions of this guidance on its consolidated financial statements.

2.    Discontinued Operations

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

The Partnership's exit from its non-operated oil and gas working interest business represents a strategic shift to reduce debt and focus on its aggregates, soda ash and coal royalty and other business segments. As a result, the Partnership has classified the operating results and cash flows of its non-operated oil and gas working interest assets as discontinued operations in its consolidated statements of comprehensive income and consolidated statements of cash flows for all periods presented.


7

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



Prior to this exit, the Partnership's non-operated oil and gas working interest assets were included along with its oil and gas royalty assets as a separate reportable segment. During the third quarter of 2016, the Partnership transitioned management responsibilities and reporting of its oil and gas royalty assets into its Coal Royalty and Other operating segment and eliminated its Oil and Gas segment. See Note 3. Segment Information for further segment information.

The following table (in thousands) presents summarized financial results of the Partnership's discontinued operations in the Consolidated Statements of Comprehensive Income:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2016
 
2015
 
2016
 
2015
 
(Unaudited)
 
(Unaudited)
Revenues and other income:
 
 
 
 
 
 
 
Oil and gas
$
41

 
$
11,447

 
$
16,476

 
$
38,558

Gain on asset sales
8,468

 
—

 
8,284

 
451

Total revenues and other income
8,509


11,447


24,760


39,009

 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Operating and maintenance expenses (including affiliates)
928

 
4,584

 
11,180

 
15,171

Depreciation, depletion and amortization
—

 
10,187

 
7,527

 
35,648

Asset impairments
—

 
265,135

 
564

 
265,135

Total operating expenses
928


279,906


19,271


315,954

 
 
 
 
 
 
 
 
Interest expense
(469
)
 
(806
)
 
(3,488
)
 
(3,021
)
Income (loss) from discontinued operations
$
7,112

 
$
(269,265
)
 
$
2,001

 
$
(279,966
)

The following table (in thousands) presents the carrying amounts of the Partnership's assets and liabilities of discontinued operations in the Consolidated Balance Sheets:
 
September 30,
2016
 
December 31,
2015
 
(Unaudited)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
—

 
$
10,569

Accounts receivable, net
991

 
7,053

Other
—

 
222

Total current assets
991


17,844

Mineral rights, net
—

 
109,505

Other non-current assets
—

 
657

     Total assets of discontinued operations
$
991

 
$
128,006

 
 
 
 
LIABILITIES
 
 
 
Current liabilities:
 
 
 
Other (including affiliates) (1)
$
835

 
$
4,388

Total current liabilities
835

 
4,388

Long-term debt, net (2)
—

 
83,600

Other non-current liabilities
—

 
1,637

     Total liabilities of discontinued operations
$
835

 
$
89,625

 
 
 
 
 
(1)
See Note 10. Related Party Transactions for additional information on the Partnership's related party assets and liabilities.
(2)
The Partnership identified the NRP Oil and Gas reserve based lending facility (the "RBL Facility") as specifically attributed to its non-operated oil and gas working interest assets and included the interest from this debt in discontinued operations. See Note 8. Debt and Debt—Affiliate for additional information on the Partnership's debt related to discontinued operations.

8

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



    
The following table (in thousands) presents supplemental cash flow information of the Partnership's discontinued operations:
 
Nine Months Ended
 
September 30,
 
2016
 
2015
 
(Unaudited)
Cash paid for interest
$
1,906

 
$
2,156

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

 
3,336


Capital expenditures related to the Partnership's discontinued operations were $3.1 million and $36.0 million during the nine months ended September 30, 2016 and 2015, respectively.

3.    Segment Information

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 three operating segments:

Coal Royalty and Other—consists primarily of coal royalty and coal related transportation and processing assets. Other assets include aggregate royalty, industrial mineral royalty, oil and gas royalty and timber. The Partnership's coal reserves are primarily located in Appalachia, the Illinois Basin and the Western United States. Its aggregates and industrial minerals are located in a number of states across the United States. As a result of the sale of its non-operated oil and gas working interest assets and exit from this oil and gas business in the third quarter of 2016, the Partnership transitioned management responsibilities and reporting of its oil and gas royalty assets into the Coal Royalty and Other operating segment. The Partnership has adjusted the corresponding items of segment information for prior periods to reflect this change. In February 2016, the Partnership sold reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee. In February 2016, the Partnership also sold royalty and overriding royalty interests in several oil and gas producing properties located in the Appalachian Basin.

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, the Partnership's 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. The Partnership receive regular quarterly distributions from this business.

VantaCore—consists of the Partnership's construction materials business 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.

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 of $4.8 million and $15.1 million for the three and nine months ended September 30, 2015, respectively, were allocated to the operating segments and 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.


9

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



The following table summarizes certain financial information for each of the Partnership's operating segments (in thousands):
 
 
Operating Segments
 
 
 
 
 
Coal Royalty and Other
 
Soda Ash
 
VantaCore
 
Corporate and Financing
 
Total
 
 
 
 
 
 
 
 
 
 
 
For the Three Months Ended September 30, 2016
Revenues (including affiliates)
 
$
48,938

 
$
10,753

 
$
31,757

 
$
—

 
$
91,448

Intersegment revenues (expenses)
 
45

 
—

 
(45
)
 
—

 
—

Gain on asset sales
 
6,425

 
—

 
1

 
—

 
6,426

Operating and maintenance expenses (including affiliates)
 
8,391

 
—

 
26,913

 
—

 
35,304

Depreciation, depletion and amortization (including affiliates)
 
9,070

 
—

 
3,761

 
—

 
12,831

Asset impairment
 
5,697

 
—

 
—

 
—

 
5,697

Other expense, net
 
—

 
—

 
—

 
22,488

 
22,488

Net income (loss) from continuing operations
 
32,250

 
10,753

 
1,039

 
(27,623
)
 
16,419

Net income (loss) from discontinued operations
 
—

 
—

 
—

 
—

 
7,112

For the Three Months Ended September 30, 2015
Revenues (including affiliates)
 
$
59,966

 
$
12,617

 
$
39,616

 
$
—

 
$
112,199

Gain (loss) on asset sales
 
2,256

 
—

 
(423
)
 
—

 
1,833

Operating and maintenance expenses (including affiliates)
 
6,832

 
—

 
32,658

 
—

 
39,490

Depreciation, depletion and amortization (including affiliates)
 
12,659

 
—

 
3,778

 
—

 
16,437

Asset impairment
 
361,703

 
—

 
—

 
—

 
361,703

Other expense, net
 
—

 
—

 
—

 
22,905

 
22,905

Net income (loss) from continuing operations
 
(318,972
)
 
12,617

 
2,757

 
(27,138
)
 
(330,736
)
Net loss from discontinued operations
 
—

 
—

 
—

 
—

 
(269,265
)
For the Nine Months Ended September 30, 2016
Revenues (including affiliates)
 
$
165,844

 
30,742

 
88,081

 
—

 
284,667

Intersegment revenues (expenses)
 
97

 
—

 
(97
)
 
—

 
—

Gain on asset sales
 
27,270

 
—

 
10

 
—

 
27,280

Operating and maintenance expenses (including affiliates)
 
24,232

 
—

 
73,540

 
—

 
97,772

Depreciation, depletion and amortization (including affiliates)
 
23,496

 
—

 
11,013

 
—

 
34,509

Asset impairment
 
7,681

 
—

 
—

 
—

 
7,681

Other expense, net
 
—

 
—

 
—

 
67,236

 
67,236

Net income (loss) from continuing operations
 
137,802

 
30,742

 
3,441

 
(80,582
)
 
91,403

Net income (loss) from discontinued operations
 
—

 
—

 
—

 
—

 
2,001

For the Nine Months Ended September 30, 2015
Revenues (including affiliates)
 
183,077

 
36,739

 
107,058

 
—

 
326,874

Gain (loss) on asset sales
 
6,927

 
—

 
(24
)
 
—

 
6,903

Operating and maintenance expenses (including affiliates)
 
23,772

 
—

 
90,656

 
—

 
114,428

Depreciation, depletion and amortization (including affiliates)
 
34,529

 
—

 
12,499

 
—

 
47,028

Asset impairment
 
365,506

 
—

 
—

 
—

 
365,506

Other expense, net
 
—

 
—

 
—

 
66,960

 
66,960

Net income (loss) from continuing operations
 
(233,803
)
 
36,739

 
3,879

 
(76,783
)
 
(269,968
)
Net loss from discontinued operations
 
—

 
—

 
—

 
—

 
(279,996
)
Total Assets of Continuing Operations
September 30, 2016
 
1,007,034

 
257,661

 
195,617

 
60,103

 
1,520,415

December 31, 2015
 
1,078,778

 
261,942

 
200,348

 
961

 
1,542,029



10

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



4.    Equity Investment

The Partnership accounts for its 49% investment in Ciner Wyoming LLC ("Ciner Wyoming") using the equity method of accounting. Ciner Wyoming distributed $34.3 million and $34.5 million to us in the nine months ended September 30, 2016 and 2015, respectively.

The difference between the amount at which the investment in Ciner Wyoming is carried and the amount of underlying equity in Ciner Wyoming's net assets was $150.9 million and $154.8 million as of September 30, 2016 and December 31, 2015, respectively. This excess basis relates to plant, property and equipment and right to mine assets. The excess basis difference that relates to property, plant and equipment is being amortized into income using the straight-line method over a weighted average of 28 years. The excess basis difference that relates to right to mine assets is being amortized into income using the units of production method. The Partnership's equity in the earnings of Ciner Wyoming is summarized as follows (in thousands):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2016
 
2015
 
2016
 
2015
 
(Unaudited)
 
(Unaudited)
Income allocation to NRP’s equity interests
$
11,973

 
$
13,806

 
$
34,357

 
$
40,319

Amortization of basis difference
(1,220
)
 
(1,189
)
 
(3,615
)
 
(3,580
)
Equity in earnings of unconsolidated investment
$
10,753

 
$
12,617

 
$
30,742

 
$
36,739


The results of Ciner Wyoming’s operations are summarized as follows (in thousands):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2016
 
2015
 
2016
 
2015
 
(Unaudited)
 
(Unaudited)
Sales
$
121,003

 
$
117,340

 
$
352,085

 
$
359,970

Gross profit
30,673

 
32,750

 
87,656

 
96,565

Net Income
24,436

 
28,175

 
70,118

 
82,283


The financial position of Ciner Wyoming is summarized as follows (in thousands):
 
September 30,
2016
 
December 31,
2015
 
(Unaudited)
 
 
Current assets
$
142,549

 
$
144,695

Noncurrent assets
232,462

 
233,845

Current liabilities
57,071

 
43,018

Noncurrent liabilities
100,000

 
116,808


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


11

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



5.    Plant and Equipment

The Partnership’s plant and equipment consist of the following (in thousands):
 
September 30,
2016
 
December 31,
2015
 
(Unaudited)
 
 
Plant and equipment at cost
$
77,377

 
$
92,049

Construction in process
1,717

 
646

Less accumulated depreciation
(26,578
)
 
(32,020
)
Total plant and equipment, net
$
52,516


$
60,675


Depreciation expense related to the Partnership's plant and equipment totaled $3.1 million and $3.9 million for the three months ended September 30, 2016 and 2015, respectively. Depreciation expense related to the Partnership's plant and equipment totaled $9.5 million and $12.9 million for the nine months ended September 30, 2016 and 2015, respectively.

6.    Mineral Rights

The Partnership’s mineral rights consist of the following (in thousands):
 
September 30, 2016
 
(Unaudited)
 
Carrying Value
 
Accumulated Depletion
 
Net Book Value
Coal Royalty and Other
$
1,270,295

 
$
(454,261
)
 
$
816,034

VantaCore
112,700

 
(4,553
)
 
108,147

Total
$
1,382,995

 
$
(458,814
)
 
$
924,181

 
December 31, 2015
 
Carrying Value
 
Accumulated Depletion
 
Net Book Value
Coal Royalty and Other
$
1,317,158

 
$
(442,254
)
 
$
874,904

VantaCore
112,700

 
(3,082
)
 
109,618

Total
$
1,429,858

 
$
(445,336
)
 
$
984,522


Depletion expense related to the Partnership’s mineral rights totaled $8.6 million and $11.6 million for the three months ended September 30, 2016 and 2015, respectively. Depletion expense related to the Partnership's mineral rights totaled $21.9 million and $30.9 million for the nine months ended September 30, 2016 and 2015, respectively.

Sales of Royalty Properties

As discussed in Note 1. "Basis of Presentation," the Partnership is currently pursuing or considering a number of actions, including dispositions of assets, in order to mitigate the effects of adverse market developments which could otherwise cause the Partnership to breach financial covenants under its debt agreements. As part of this plan, the Partnership executed a definitive agreement to sell all its mineral fee interests in Grant County, Oklahoma. As a result, approximately $5.5 million in the Partnership's oil and gas royalty mineral rights are classified as Current assets held for sale on the Consolidated Balance Sheets at September 30, 2016. In addition, the Partnership completed the sale of the following assets during the nine months ended September 30, 2016:
1)Oil and gas royalty and overriding royalty interests in several producing properties located in the Appalachian Basin for $36.4 million. The effective date of the sale was January 1, 2016, and the Partnership recorded an $18.6 million gain from this sale included in Gain on asset sales, net 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 $1.5 million gain from this sale included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income.
In addition to the two asset sales described above, during the nine months ended September 30, 2016, the Partnership sold mineral reserves in multiple sale transactions for cumulative $9.8 million of gross sales proceeds and recorded $6.8 million of cumulative gain from these sale transactions that are included in Gain on asset sales, net on its Consolidated Statement of

12

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



Comprehensive Income. The substantial majority of these amounts relate to eminent domain transactions with governmental agencies.

During the nine months ended September 30, 2015, the Partnership sold mineral reserves for $3.7 million in gross sales proceeds and recorded a $3.3 million gain on asset sales included in Gain on asset sales, net on its Consolidated Statement of Comprehensive Income.

Impairment of Mineral Rights

The Partnership has developed procedures to periodically evaluate its long-lived assets for possible impairment. These procedures are performed throughout the year and consider both quantitative and qualitative information based on historic, current and future performance and are designed to identify impairment indicators. If an impairment indicator is identified, additional evaluation is performed for that asset that considers both quantitative and qualitative information. A long-lived asset is deemed impaired when the future expected undiscounted cash flows from its use and disposition are less than the assets’ carrying value. Impairment is measured based on the estimated fair value, which is primarily determined based upon the present value of the projected future cash flow compared to the assets’ carrying value. The inputs used by management for fair value measurements include significant inputs that are not observable in the market and thus represent a Level 3 fair value measurement for these types of assets. In addition to the evaluations discussed above, specific events such as a reduction in economically recoverable reserves or production ceasing on a property for an extended period may require that a separate impairment evaluation be completed on a significant property. The Partnership believes the discount rates used in estimating fair value were representative of what market participants would use in valuing the impacted assets.

During the three and nine months ended September 30, 2016 and 2015, the Partnership identified facts and circumstances that indicated that the carrying value of certain of its mineral rights exceed future cash flows from those assets and recorded non-cash impairment expense as follows (in thousands):
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
Impaired Asset Description
 
2016
 
2015
 
2016
 
2015
 
 
(Unaudited)
Coal properties (1)
 
$
3,817

 
$
247,815

 
$
3,908

 
$
249,362

Oil and gas royalty properties (2)
 
36

 
70,527

 
36

 
70,527

Aggregates royalty properties (3)
 
1,411

 
43,361

 
1,677

 
43,361

Total
 
$
5,264

 
$
361,703


$
5,621

 
$
363,250

 
 
 
 
 
(1)
The Partnership recorded $3.8 million and $3.9 million of coal property impairments during the three and nine months ended September 30, 2016, respectively. Total coal property impairment expense for the nine months ended September 30, 2015 was $249.4 million. The Partnership recorded $1.5 million of coal property impairment during the three months ended June 30, 2015 and the fair value measurement of these impaired assets recorded at fair value was $0.0 million at June 30, 2015. The Partnership recorded the remaining $247.8 million of coal property impairment during the three months ended September 30, 2015 and the fair value measurement of these impaired assets recorded at fair value was $28.4 million at September 30, 2015. These impairments primarily resulted from the continued deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry. NRP compared net capitalized costs of its coal properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows.

13

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



(2)
The Partnership recorded $70.5 million of oil and gas royalty property impairment during the three and nine months ended September 30, 2015. The fair value measurement of these impaired assets recorded at fair value were $13.0 million at September 30, 2015. This impairment primarily resulted from declines in future expected realized commodity prices and reduced expected drilling activity on its acreage. NRP compared net capitalized costs of its oil and gas royalty properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted future net cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow method was used to estimate fair value. Significant inputs used to determine the fair value include estimates of: (i) oil and gas reserves and risk-adjusted probable and possible reserves; (ii) future commodity prices; (iii) production costs, (iv) capital expenditures, (v) production and (vi) discount rates. The underlying commodity prices embedded in the Partnership's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing as of the measurement date, adjusted for estimated location and quality differentials.
(3)
The Partnership recorded $1.4 million and $1.7 million of aggregates royalty property impairments during the three and nine months ended September 30, 2016, respectively. The Partnership recorded $43.4 million of aggregates royalty property impairments during the three and nine months ended September 30, 2015. The fair value measurement of these impaired assets recorded at fair value was $13.1 million at September 30, 2015. This impairment primarily resulted from greenfield development projects that have not performed as projected, leading to recent lease concessions on minimums and royalties combined with the continued regional market decline for certain properties. NRP compared net capitalized costs of its aggregates properties to estimated undiscounted future net cash flows. If the net capitalized cost exceeded the undiscounted cash flows, the Partnership recorded an impairment for the excess of net capitalized cost over fair value. A discounted cash flow model was used to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flow, discount rate and useful economic life. Estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the future realization of cash flows.

7.    Intangible Assets (Including Affiliate)

The Partnership's intangible assets—affiliate relate to above market coal transportation contracts with subsidiaries of Foresight Energy LP ("Foresight Energy"), pursuant to which it receives throughput fees for the handling and transportation of coal.
 
September 30,
2016
 
December 31,
2015
 
(Unaudited)
 
 
Intangible assets—affiliate
$
81,109

 
$
81,109

Less accumulated amortization—affiliate
(30,441
)
 
(28,112
)
Total intangible assets, net—affiliate
$
50,668

 
$
52,997


Amortization expense related to the Partnership's intangible assets—affiliate totaled $0.9 million and $0.7 million for the three months ended September 30, 2016 and 2015, respectively. Amortization expense related to the Partnership's intangible assets—affiliate totaled $2.3 million and $2.5 million for the nine months ended September 30, 2016 and 2015, respectively.

The Partnership's intangible assets consist of permits, aggregate-related trade names and other agreements as follows (in thousands):
 
September 30,
2016
 
December 31,
2015
 
(Unaudited)
 
 
Intangible assets
$
5,077

 
$
5,076

Less accumulated amortization
(1,838
)
 
(1,146
)
Total intangible assets, net
$
3,239

 
$
3,930


Amortization expense related to the Partnership's intangible assets totaled $0.2 million and $0.7 million for both the three and nine months ended September 30, 2016 and 2015, respectively.


14

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



8. Debt and Debt—Affiliate

As of September 30, 2016 and December 31, 2015, debt and debt—affiliate consisted of the following (in thousands):
 
September 30,
2016
 
December 31,
2015
 
(Unaudited)
 
 
NRP LP debt:
 
 
 
9.125% senior notes, with semi-annual interest payments in April and October, due October 2018, $300 million issued at 99.007% and $125 million issued at 99.5%
$
425,000

 
$
425,000

Opco debt (1):
 
 
 
Revolving credit facility, due June 2018
260,000

 
290,000

Senior notes
 
 
 
4.91% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2018
9,233

 
13,850

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

 
85,714

5.05% with semi-annual interest payments in January and July, with annual principal payments in July, due July 2020
30,769

 
38,462

5.55% with semi-annual interest payments in June and December, with annual principal payments in June, due June 2023
18,900

 
21,600

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

 
60,000

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

 
135,000

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

 
40,909

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

 
148,077

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

 
42,308

5.31% utility local improvement obligation, with annual principal and interest payments in February, due March 2021
$
961

 
$
1,153

NRP Oil and Gas debt:
 
 
 
Revolving credit facility
—

 
85,000

Total debt at face value
$
1,215,898

 
$
1,387,073

Net unamortized debt discount
(1,511
)
 
(2,077
)
Net unamortized debt issuance costs (1)
(13,806
)
 
(14,040
)
Total debt, net
$
1,200,581


$
1,370,956

Less: current portion of long-term debt
158,597

 
80,745

Less: debt classified as non-current liabilities of discontinued operations
—

 
83,600

Total long-term debt
$
1,041,984

 
$
1,206,611

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

15

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




NRP LP Debt

NRP Senior Notes    

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

In October 2014, the Partnership, 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.

The Partnership 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 the Partnership and certain of its subsidiaries to incur or guarantee additional indebtedness. Under the Indenture, the Partnership 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 the Partnership and certain of its subsidiaries to incur additional indebtedness is further limited in the event the amount of indebtedness of the Partnership and certain of its subsidiaries that is senior to the Partnership's unsecured indebtedness exceeds certain thresholds.

Opco Debt

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

Opco Credit Facility

In June 2016, Opco entered into an amendment (the "First Amendment") to its Amended and Restated Credit Agreement (the "Opco Credit Facility") that is guaranteed by all of Opco’s wholly owned subsidiaries, and is secured by liens on certain of the assets of Opco and its subsidiaries, as further described below. Under the First Amendment:
•
The maturity date of the Opco Credit Facility was extended from October 1, 2017 to June 30, 2018;
•
The maximum leverage ratio of consolidated indebtedness to consolidated EBITDDA (as defined in the Opco Credit Facility) has been amended to remain at 4.0x for the remaining term of the Opco Credit Facility, including for the period ending June 30, 2016; and
•
The asset sale covenant was amended to allow asset sales of up to $300.0 million from and after the effective date of the First Amendment; provided, however, that 75% of the net cash proceeds of any such asset sales must be used to repay the Opco Credit Facility (without any corresponding commitment reduction) and/or NRP Opco’s Senior Notes described below.
  
On the effective date of the First Amendment, the total commitment under the Opco Credit Facility was reduced from $300.0 million to $260.0 million. In addition, Opco and the lenders agreed to further reduce commitments under the Opco Credit Facility to (a) $210.0 million on December 31, 2016, (b) $180.0 million on June 30, 2017 and (c) $150.0 million on December 31, 2017. Opco will have the right to delay any of these commitment reductions by up to 90 days each upon the agreement of the lenders holding 66.7% of the then-existing commitments. To the extent any such commitment reduction is extended under the terms of the A&R Revolving Credit Facility, Opco's ability to make distributions to the Partnership will be limited to amounts necessary for the Partnership to pay taxes and other general partnership expenses and make interest payments on its 9.125% Senior Notes due 2018.


16

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



In addition to the 4.0x leverage ratio described above, the Opco Credit Facility requires Opco to maintain a ratio of consolidated EBITDDA to consolidated fixed charges (consisting of consolidated interest expense and consolidated lease expense) of not less than 3.5 to 1.0. As of September 30, 2016, Opco's leverage ratio was 2.95x, and fixed charge coverage ratio was 5.46x.

Effective on the date of the First Amendment, indebtedness under the Opco Credit Facility bears interest, at Opco's option, at:
•
the higher of (i) the prime rate as announced by the agent bank; (ii) the federal funds rate plus 0.50%; or (iii) LIBOR plus 1%, in each case plus an applicable margin ranging from 2.50% to 3.50%; or
•
a rate equal to LIBOR plus an applicable margin ranging from 3.50% to 4.50%.

The weighted average interest rates for the borrowings outstanding under the Opco Credit Facility for the three months ended September 30, 2016 and 2015 were 4.87% and 3.05%, respectively. The weighted average interest rates for the borrowings outstanding under the Opco Credit Facility for the nine months ended September 30, 2016 and 2015 were 4.24% and 2.41%, respectively.

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

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

The Opco Credit Facility is collateralized and secured by liens on certain of Opco’s assets with carrying values of $680.5 million and $709.9 million classified as Land, Plant and equipment and Mineral rights on the Partnership’s Consolidated Balance Sheet as of September 30, 2016 and December 31, 2015, respectively. The collateral includes (1) the equity interests in all of Opco’s wholly owned subsidiaries, other than NRP Trona LLC (which owns a 49% non-controlling equity interest in Ciner Wyoming), (2) the personal property and fixtures owned by Opco’s wholly owned subsidiaries, other than NRP Trona LLC, (3) Opco’s material coal royalty revenue producing properties, (4) real property associated with certain of VantaCore’s construction aggregates mining operations, and (5) certain of Opco’s coal-related infrastructure assets.

Opco Senior Notes   

Opco has issued several series of private placement senior notes (the "Opco Senior Notes") with various interest rates and principal due dates. As of September 30, 2016, and December 31, 2015, the Opco Senior Notes had cumulative principal balances of $529.9 million and $585.9 million, respectively. Opco made principal payments of $56.0 million on the Opco Senior Notes during both the nine months ended September 30, 2016 and 2015.

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

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


17

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



In September 2016, Opco amended the Opco Senior Notes. Under this amendment, Opco agreed to use certain asset sale proceeds to make mandatory prepayment offers on the Opco Senior Notes as follows:
•
Until the earlier of the time that (1) Opco has sold $300 million of assets and (2) June 30, 2020, Opco will be required to make prepayment offers to the holders of the Opco Senior Notes using 25% of the net cash proceeds from certain asset sales; and
•
After the earlier to occur of the dates above, Opco will be required to make prepayment offers to the holders of the Opco Senior Notes using an amount of net cash proceeds from certain asset sales that will be calculated pro-rata based on the amount of Opco Senior Notes then outstanding compared to the other total Opco senior debt outstanding that is being prepaid.

The mandatory prepayment offers described above will be made pro-rata across each series of outstanding Opco Senior Notes and will not require any make-whole payment by Opco. In addition, the remaining principal and interest payments on the Opco Senior Notes will be adjusted accordingly based on the amount of Opco Senior Notes actually prepaid. The prepayments do not affect the maturity dates of any series of the Opco Senior Notes.
NRP Oil and Gas Debt Classified as Liabilities of Discontinued Operations

RBL Facility    

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

At December 31, 2015, there was $85.0 million respectively, outstanding under the RBL Facility. As described in Note 2. Discontinued Operations, the Partnership included this debt and its related interest expense in discontinued operations. In July 2016, NRP Oil and Gas LLC closed the sale of its non-operated oil and gas working interest assets and used a portion of the proceeds to repay the RBL Facility in full.

9.    Fair Value Measurements

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



18

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



The following table (in thousands) shows the carrying value and estimated fair value of the Partnership's debt, debt—affiliate and contracts receivable—affiliate:
 
September 30, 2016
 
December 31, 2015
 
Carrying
Value
 
Estimated
Fair Value
 
Carrying
Value
 
Estimated
Fair Value
 
(Unaudited)
 
 
 
 
Debt and debt—affiliate:
 
 
 
 
 
 
 
NRP Senior Notes (1)
$
419,397

 
$
391,531

 
$
417,296

 
$
277,313

Opco Senior Notes and utility local improvement obligation (2)
527,016

 
489,090

 
584,890

 
383,065

Opco Revolving Credit Facility (3)
254,168

 
260,000

 
285,170

 
290,000

NRP Oil and Gas RBL Facility (3)
—

 
—

 
83,600

 
85,000

 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Contracts receivable—affiliate, current and long-term (2)
$
47,542

 
$
32,861

 
$
49,948

 
$
34,498

 
 
 
 
 
(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 outstanding borrowing amount because the interest rates are variable and reflective of market rates and the terms of the credit facility allow the Partnership to repay this debt at any time without penalty.

10.    Related Party Transactions

Reimbursements to Affiliates of NRP's 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 Partnership's business. QMC and WPPLP charge the Partnership the portion of their employee salary and benefits costs related to their employee services provided to NRP. In addition, the Partnership receives non-cash equity contributions from its general partner related to compensation paid directly by the general partner and not reimbursed by the Partnership. These amounts are presented as non-cash equity contributions on the Partnership's Consolidated Statements of Partners' Capital and were $0.2 million during the nine months ended September 30, 2016. These QMC and WPPLP employee management service costs and non-cash equity compensation expenses are presented as Operating and maintenance expenses—affiliates, net and General and administrative—affiliates on the Consolidated Statements of Comprehensive Income. NRP also reimburses overhead costs incurred by its affiliates to manage the Partnership's business. These overhead costs include certain legal, accounting, treasury, information technology, insurance, administration of employee benefits and other corporate services incurred by the Partnership’s general partner and its affiliates and are presented as Operating and maintenance expenses—affiliates, net and General and administrative—affiliates on the Consolidated Statements of Comprehensive Income.

The Partnership had Accounts payable—affiliates to Quintana Minerals Corporation of $0.5 million and $1.1 million, including $0.1 million and $0.7 million related to discontinued operations at September 30, 2016 and December 31, 2015, respectively, for services provided by Quintana Minerals Corporation to the Partnership. The Partnership had Accounts payable—affiliates to WPPLP of $0.5 million and $0.3 million at September 30, 2016 and December 31, 2015, respectively.


19

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



Direct general and administrative expenses charged to the Partnership by WPPLP and Quintana Minerals Corporation are as follows (in thousands):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2016
 
2015
 
2016
 
2015
 
(Unaudited)
 
(Unaudited)
Operating and maintenance expenses—affiliates, net
$
1,980

 
$
1,540

 
$
6,591

 
$
7,068

General and administrative—affiliates
867

 
2,424

 
2,670

 
3,809


Included in income (loss) from discontinued operations are $0.4 million and $1.2 million and $0.2 million and $0.6 million of operating and maintenance expenses charged by Quintana Minerals Corporation for the three and nine months ended September 30, 2016 and 2015, respectively.

Cline Affiliates

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

Coal related revenues from Foresight Energy totaled $20.6 million and $18.7 million for the three months ended September 30, 2016 and 2015, respectively. Coal related revenues from Foresight Energy totaled $47.6 million and $68.6 million for the nine months ended September 30, 2016 and 2015, respectively. As of September 30, 2016 and December 31, 2015, the Partnership had Accounts receivable—affiliates from Foresight Energy of $6.9 million and $6.4 million, respectively. The Partnership had recorded $74.7 million and $82.6 million in minimum royalty payments as Deferred revenue—affiliates at September 30, 2016 and December 31, 2015, respectively.

NRP owns and leases rail load out and associated facilities to a subsidiary of 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 September 30, 2016 were $77.7 million, with unearned income of $32.7 million, and the net amount receivable was $45.0 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 $35.3 million and the net amount receivable was $45.9 million, of which $2.0 million is included in Accounts receivable—affiliates while the remaining is included in Long-term contracts receivable—affiliates on the accompanying Consolidated Balance Sheets.

NRP 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 September 30, 2016 was $2.7 million, of which $1.4 million is included in Accounts receivable—affiliates, while the remaining is included in Long-term contracts receivable—affiliate. The net amount receivable under the agreement as of December 31, 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.

NRP owns rail load out transportation assets and subcontracts out the operating responsibilities to an affiliate of Foresight Energy at Foresight's Williamson mine. During the three and nine months ended September 30, 2016, the Partnership recorded operating and maintenance expenses—affiliates of $0.4 million and $1.0 million, respectively, to operate these assets. During the three and nine months ended September 30, 2015, the Partnership recorded operating and maintenance expenses—affiliates of $0.3 million and $1.0 million, respectively, to the operate these assets.




20

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



Long-Term Debt—Affiliate

Donald R. Holcomb, one of the Partnership’s former directors, was a manager of Cline Trust Company, LLC (the "Cline Trust Company") as of December 31, 2015, that owned approximately 0.5 million of the Partnership’s common units and $20.0 million in principal amount of the Partnership’s 9.125% Senior Notes due 2018. As of December 31, 2015, the members of the Cline Trust Company were four trusts for the benefit of the children of Chris Cline, each of which owned an approximately equal membership interest in the Cline Trust Company. As of December 31, 2015, Mr. Holcomb also served as trustee of each of the four trusts. The balance on this portion of the Partnership’s 9.125% Senior Notes due 2018 was $19.9 million as of December 31, 2015 and was included in Long-term debt, net—affiliate on the accompanying Consolidated Balance Sheet. In April 2016, Mr. Holcomb resigned from the Partnership's board of directors and as a result the $19.9 million debt balance held by Cline Trust Company was subsequently reclassified as Long-term debt, net on the Partnership's accompanying Consolidated Balance Sheet.

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 September 30, 2016, a fund controlled by Quintana Capital owned a majority interest in Corsa Coal Corp. ("Corsa"), a coal mining company traded on the TSX Venture Exchange that is one of the Partnership’s lessees in Tennessee. Corbin J. Robertson III, one of the Partnership’s directors, is Chairman of the Board of Corsa. Coal related revenues from Corsa totaled $0.8 million and $0.9 million for the three months ended September 30, 2016 and 2015, respectively and $1.9 million and $2.4 million for the nine months ended September 30, 2016 and 2015, respectively. The Partnership had recorded $0.3 million in minimum royalty payments as Deferred revenue—affiliates at both September 30, 2016 and December 31, 2015. The Partnership also had Accounts receivable—affiliates totaling $0.2 million from Corsa at both September 30, 2016 and December 31, 2015.

WPPLP Production Royalty and Overriding Royalty

The Partnership recorded $0.0 million and $0.7 million in operating and maintenance expenses—affiliates related to a non-participating production royalty payable to WPPLP pursuant to a conveyance agreement entered into in 2007 for the three and nine months ended September 30, 2016, respectively. The Partnership recorded ($0.1 million) and $0.0 million in operating and maintenance expenses—affiliates related to this non-participating production royalty payable to WPPLP for the three and nine months ended September 30, 2015. The Partnership had Other assets—affiliate from WPPLP of $1.0 million and $1.1 million at September 30, 2016 and December 31, 2015, respectively related to a non-production royalty receivable from WPPLP for overriding royalty interest on a mine.

11.    Commitments and Contingencies

Legal

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

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


21

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



Foresight Energy Disputes

In November 2015, a subsidiary of the Partnership 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, the Partnership 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 in arrears of $7.5 million per quarter, or $30.0 million per year. Foresight Energy's failure to make the deficiency payment with respect to the second, third and fourth quarters of 2015 and the first, second and third quarters of 2016 resulted in a cumulative $38.5 million negative cash impact to us. Such amount will increase for each quarter during which mining operations continue to be idled. The Partnership does 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, the Partnership's financial condition and future cash flows will be adversely affected.

In April 2016, a subsidiary of the Partnership 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 certain periods resulted in a cumulative $5.8 million negative cash impact to us. While the Partnership plans to pursue its claim, a valuation allowance for the receivable amount has been recorded. It is possible that the Partnership’s current estimate of the valuation allowance related to this matter could change, perhaps materially, in the future.

12.    Major Customers

Revenues from customers that exceeded ten percent of total revenues and other income for either the three or nine months ended September 30, 2016 and 2015 are as follows (in thousands except for percentages):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2016
 
2015
 
2016
 
2015
 
(Unaudited)
 
(Unaudited)
 
Revenues
 
Percent
 
Revenues
 
Percent
 
Revenues
 
Percent
 
Revenues
 
Percent
Foresight Energy
$
20,635

 
21%
 
$
18,677

 
16%
 
$
47,648

 
15%
 
$
68,556

 
21%
Alpha Natural Resources
$
3,829

 
4%
 
$
15,429

 
14%
 
$
14,420

 
5%
 
$
33,201

 
10%

During the three and nine months ended September 30, 2015, total revenues and other income from Alpha Natural Resources included a $6.0 million non-recurring lease assignment fee.

13.    Unit-Based Compensation

At the time of the Partnership's 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.


22

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



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 the Partnership's 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
(10
)
Outstanding grants at September 30, 2016
88


Grants typically vest at the end of a four-year period and are paid in cash upon vesting. The Partnership recorded expenses related to its Long-Term Incentive Plan of $0.7 million and $0.8 million for the three and nine months ended September 30, 2016, respectively. The Partnership also recorded a credit to expenses related to its Long-Term Incentive plan of $0.2 million and $1.7 million for the three and nine months ended September 30, 2015, respectively due to the decline in the market price of the Partnership's common units during the period.

In connection with the Long-Term Incentive Plan, payments are typically made during the first quarter of the year. Payments of $1.5 million and $4.4 million were made during the nine months ended September 30, 2016 and 2015, respectively. The unaccrued cost associated with unvested outstanding grants and related DERs at September 30, 2016 and December 31, 2015, was $0.8 million and $0.7 million, respectively.

14.    Cash Distributions

The following table shows the distributions paid by the Partnership during the nine months ended September 30, 2016 and 2015:
 
 
 
 
 
 
Total Distributions (In thousands)
Date Paid
 
Period Covered by Distribution
 
Distribution per Common Unit
 
Common Units
 
GP Interest
 
Total
2016
 
 
 
 
 
 
 
 
 
 
February 12, 2016
 
October 1 - December 31, 2015
 
$
0.45

 
$
5,503

 
$
113

 
$
5,616

May 13, 2016
 
January 1 - March 31, 2016
 
0.45

 
5,503

 
113

 
5,616

August 12, 2016
 
April 1 - June 30, 2016
 
0.45

 
5,505

 
112

 
5,617

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

 
$
42,804

 
$
874

 
$
43,678

May 14, 2015
 
January 1 - March 31, 2015
 
0.90

 
11,007

 
225

 
11,232

August 14, 2015
 
April 1 - June 30, 2015
 
0.90

 
11,009

 
223

 
11,232


23

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




15.  Supplemental Cash Flow Information

The Partnership's supplemental cash flow information of continuing operations is summarized as follows (in thousands):
 
Nine Months Ended
September 30,
 
2016
 
2015
 
(Unaudited)
Cash paid for interest
$
54,749

 
$
55,761

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

 
4,465


16. 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):
 
September 30,
2016
 
December 31,
2015
 
(Unaudited)
 
 
Deferred revenue
$
40,050

 
$
80,812

Deferred revenue—affiliate
74,663

 
82,853

Total deferred revenue (including affiliate)
$
114,713

 
$
163,665


The Partnership recognized the following amounts of deferred revenue (including affiliate) attributable to previously paid minimums as Coal royalty and other revenue (in thousands):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2016
 
2015
 
2016
 
2015
 
(Unaudited)
 
(Unaudited)
Coal royalty and other
$
3,662

 
$
539

 
$
48,705

 
$
2,308

Coal royalty and other—affiliates
6,093

 
2,695

 
11,750

 
10,172

Total coal royalty and other (including affiliates)
$
9,755

 
$
3,234

 
$
60,455

 
$
12,480


Lease Modifications, Termination and Forfeitures of Minimum Royalty Balances

During the nine months ended September 30, 2016, the Partnership entered into agreements with certain lessees to either modify or terminate existing coal related leases that resulted in the Partnership recognizing $40.4 million of deferred revenue as follows:
•An agreement that terminated a central Appalachia coal royalty lease and resulted in the lessee forfeiting the right to recoup $26.2 million of minimum royalties previously paid to the Partnership. The Partnership agreed to transfer its coal mineral rights that were subject to this former lease to the lessee. This terminated lease had no current or planned production and the mineral rights transferred had zero net book value on the Partnership's consolidated Balance Sheets as of March 31, 2016. As a result of this transaction, in April 2016 the Partnership recognized $26.2 million of revenue.
•Lease modifications of existing coal royalty leases resulted in lessee forfeiture of rights to recoup previously paid minimum royalties and the reduction in lessee recoupment time. As a result of these modifications, in the first and second quarters of 2016 the Partnership recognized $10.7 million of revenue.
•The Partnership recognized $3.5 million of revenue from various other coal and aggregates lease modifications, terminations and forfeitures during the nine months ended September 30, 2016.
During the nine months ended September 30, 2015, there was less than $0.1 million of revenue recognized from coal and aggregate lease modifications, terminations or forfeitures.

24

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




17.    Subsequent Events

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

Distribution Declared

On October 26, 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 November 14, 2016 to unitholders of record on November 7, 2016.

Closing of Oil and Gas Royalty Sale

In November 2016, the Partnership sold its mineral fee interests in Grant County, Oklahoma for $7.5 million and recorded a gain of approximately $1.8 million.



25

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL 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 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 and VantaCore Partners LLC ("VantaCore")
•
Ciner Wyoming LLC’s ("Ciner Wyoming") trona mining and soda ash refinery operations;
•
the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us, and of scheduled or potential regulatory or legal changes; and
•
global and U.S. economic conditions.

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

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

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

Introduction

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


26

Executive Overview

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

Coal Royalty and Other—consists primarily of coal royalty and coal related transportation and processing assets. Other assets include aggregate royalty, industrial mineral royalty, oil and gas royalty 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. As a result of the sale of our non-operated oil and gas working interest assets and exit from this oil and gas business in the third quarter of 2016, we transitioned management responsibilities and reporting of our oil and gas royalty assets into the Coal Royalty and Other operating segment. We have adjusted the corresponding items of segment information for prior periods to reflect this change. In February 2016, we sold reserves and related royalty rights at three aggregates operations located in Texas, Georgia and Tennessee. In February 2016, we also sold royalty and overriding royalty interests in several oil and gas producing properties located in the Appalachian Basin.

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 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.
 
For the nine months ended September 30, 2016, our financial results included (in thousands):
Revenues and other income
$
311,947

Net income from continuing operations
$
91,403

Adjusted EBITDA (1)
$
204,416

 
 
Operating cash flow provided by continuing operations
$
74,547

Investing cash flow provided by continuing operations
$
53,510

Financing cash flow (used in) continuing operations
$
(76,869
)
Distributable Cash Flow ("DCF") (1)
$
238,701

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

We continue to take proactive steps with a long-term view to address our debt maturities, and we have engaged Greenhill & Co., LLC to advise us in connection with these efforts. We are currently in active discussions with several institutional investors that may provide new equity capital to us. In addition, we have begun discussions with representatives of several holders of the NRP Senior Notes, and we may determine to pursue a refinancing or an exchange of some or all those notes.

As we pursue these capital markets transactions, we will continue to manage our business with a focus on debt reduction, cost management, and maximizing opportunities within our current asset base, including additional asset sales. The coal markets have shown improvement during the third quarter of 2016, particularly with respect to metallurgical coal, and we expect our coal royalty business to benefit from the higher pricing environment. However, to the extent that we are unable to execute on our opportunistic capital raising and/or debt refinancing efforts on favorable terms and the coal markets do not show a sustained improvement, our liquidity may be adversely affected. Accordingly, we may consider other alternatives over the next several months to manage our liquidity and address our 2018 debt maturities.


27

Current Liquidity, Management’s Forecast and Going Concern Analysis

As of September 30, 2016, we had a total of $92.4 million of cash and cash equivalents. During the nine months ended September 30, 2016, we reduced our debt by approximately $171.2 million by repaying $85.0 million of the NRP Oil and Gas reserve based lending facility (the "RBL Facility"), $56.0 of the Opco Private Placement Notes (as defined below), $30.0 million of the Opco Credit Facility (as defined below) and $0.2 million of our Opco utility local improvement obligation

While we have a diversified portfolio of assets and a history and continued forecast of profitable operations with positive operating cash flows, our operating results and credit metrics have been impacted by challenges in coal and other commodity markets. The following going concern analysis includes an evaluation of relevant conditions and events, including our business performance and forecast, and our ability to meet our obligations and remain in compliance with our debt covenants over the next twelve months.

The Partnership has $425.0 million in 9.125% Senior Notes maturing in October 2018 (the "NRP Senior Notes"). As of September 30, 2016, Opco had $260.0 million of indebtedness outstanding under its revolving credit facility (the "Opco Credit Facility") with scheduled commitment reductions of $50.0 million on December 31, 2016, $30.0 million on June 30, 2017, $30.0 million on December 31, 2017 and the remaining $150 million on June 30, 2018. In addition, as of September 30, 2016 Opco had $529.9 million outstanding under several series of Private Placement Notes with scheduled principal payments of $80.8 million through September 30, 2017 (the "Opco Private Placement Notes") (collectively referred to as the "Opco Debt agreements"). The maximum leverage ratio under the Opco Debt agreements is required not to exceed 4.0x. In addition, the Opco Debt agreements contain certain additional customary negative covenants that, among other items, restrict Opco’s ability to incur additional debt, grant liens on its assets, make investments, sell assets and engage in business combinations.

We currently forecast that we will meet our obligations, including scheduled principal and interest payments, that we will remain in compliance with our debt covenants, and that we will continue as a going concern. However, our forecast is sensitive to commodity demand and pricing and counterparty risk. In addition, the debt principal payments scheduled in 2017 will strain our liquidity. Inability to make these payments would result in an event of default and could result in Opco’s lenders accelerating Opco’s debt. Breaches of the Opco debt covenants that are not waived or cured, to the extent possible, would have a similar effect. Any such acceleration by the Opco lenders would result in a cross-default under the NRP Indenture. We are currently pursuing or considering a number of actions in order to manage our liquidity and mitigate the effects of adverse market developments that could affect our ability to repay debt and comply with the covenants under our debt agreements.

Current Results/Market Outlook

Coal Royalty and Other Business Segment

For the nine months ended September 30, 2016, our Coal Royalty and Other business segment financial results included the following (in thousands):
Revenues and other income
$
193,114

Net income from continuing operations
$
137,802

Adjusted EBITDA (1)
$
168,979

 
 
Operating cash flow provided by continuing operations
$
91,372

Investing cash flow provided by continuing operations
$
57,834

DCF (1)
$
149,206

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

We stands to benefit from recent improvements in both the thermal and metallurgical coal markets. The metallurgical coal markets in particular have improved significantly over the last few months, with global contract and spot prices in excess of $200 per ton due to supply shortages caused by China’s recent production cutbacks, operational disruptions in Australia, and the significant number of mine closures in the United States. As a result of the increased pricing, some of the higher-quality coal from our properties that is typically sold by our lessees into the thermal market is now being sold by our lessees into the metallurgical markets, which command a higher price per ton than the thermal markets. We expect this trend to continue to the extent the metallurgical markets

28

show sustained improvements. We derived approximately 32% of our coal royalty revenues and approximately 37% of the related production from metallurgical coal during the nine months ended September 30, 2016. The domestic thermal coal markets have also shown modest improvements, as production cuts over the last year have rationalized coal stockpiles. Higher recent natural gas prices have also caused thermal coal to be more competitive for electricity generation. Despite these improvements, U.S. coal producers remain under pressure as a result of a strong U.S. Dollar, continued excessive governmental regulation of coal-fired power generation facilities, and an oversupply of natural gas. In particular, producers of Central Appalachian thermal coal continue to face challenges, as their production costs remain high relative to sales prices. We have successfully navigated the bankruptcies of several of our lessees, including Alpha Natural Resources, and have had substantially all of our leases assumed or assigned and received substantially all past-due amounts in these bankruptcies.

Production from our Illinois Basin properties decreased by 27% in the first nine months of 2016 as compared to the same period in 2015. Substantially all of the decrease 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, second and third quarters of 2016 resulted in a cumulative negative cash impact to us of $38.5 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.

Soda Ash Business Segment

For the nine months ended September 30, 2016, our Soda Ash business segment financial results included the following (in thousands):
Revenues and other income
$
30,742

Net income from continuing operations
$
30,742

Adjusted EBITDA (1)
$
34,300

 
 
Operating cash flow provided by continuing operations
$
34,300

Financing cash flow used by continuing operations
$
(7,229
)
DCF (1)
$
34,300

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

Income from our trona mining and soda ash refinery investment was lower year-over-year for the nine months ended September 30, 2016. This decrease is primarily related to lower international prices compared to the prior year, in addition to higher royalty and G&A costs. These decreases were partially offset by higher production compared to the prior year. Ciner Resources LP, our partner that controls and operates Ciner Wyoming, is a publicly traded master limited partnership that depends on distributions from Ciner Wyoming in order to make distributions to its public unitholders.


29

VantaCore Business Segment

For the nine months ended September 30, 2016, our VantaCore business segment financial results included the following (in thousands):
Revenues and other income
$
88,091

Net income from continuing operations
$
3,441

Adjusted EBITDA (1)
$
14,454

 
 
Operating cash flow provided by continuing operations
$
16,680

Investing cash flow used by continuing operations
$
(4,324
)
Financing cash flow used by continuing operations
$
(1,593
)
DCF (1)
$
13,111

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

VantaCore’s construction aggregates mining and production business is largely dependent on the strength of the local markets that it serves. 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 nine months 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 nine months ended September 30, 2016, but we expect that Laurel’s business will continue to be impacted by decreased natural gas development activities. While VantaCore's production and revenues have declined in 2016 compared to 2015, it's cost management efforts have enabled the business to maintain its profitability.

Discontinued Operations

In July 2016, NRP Oil and Gas closed on the sale of its non-operated oil and gas working interest assets in the Williston Basin for $116.1 million, subject to customary closing conditions and purchase price adjustments. The Partnership's exit from its non-operated oil and gas working interest business represented a strategic shift to reduce debt and focus on its soda ash, coal royalty and construction aggregates business segments. As a result, we have classified the assets and liabilities, operating results and cash flows of our non-operated oil and gas working interest assets as discontinued operations in our consolidated financial statements for all periods presented.


30

Results of Operations

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

Revenues and Other Income

Revenues and other income decreased $16.1 million, or 14%, from $114.0 million in the three months ended September 30, 2015 to $97.9 million in the three months ended September 30, 2016. The following table shows our diversified sources of revenues and other income by business segment for the three months ended September 30, 2016 and 2015 (in thousands except for percentages):
 
 
Coal Royalty and Other
 
Soda Ash
 
VantaCore
 
Total
2016
 
 
 
 
 
 
 
 
Revenues and other income
 
$
55,363


$
10,753


$
31,758


$
97,874

Percentage of total
 
57
%
 
11
%
 
32
%
 
 
2015
 
 
 
 
 
 
 
 
Revenues and other income
 
$
62,222


$
12,617


$
39,193


$
114,032

Percentage of total
 
55
%
 
11
%
 
34
%
 
 

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


31

Coal Royalty and Other

Revenues and other income related to our Coal Royalty and Other segment decreased $6.8 million, or 11%, from $62.2 million in the three months ended September 30, 2015 to $55.4 million in the three months ended September 30, 2016.

The table below presents coal production and coal royalty revenues (including affiliates) derived from our major coal producing regions and the significant categories of other coal royalty and other revenues:
 
For the Three Months Ended September 30,
 
Increase
(Decrease)
 
Percentage
Change
 
2016
 
2015
 
 
(In thousands, except percent and per ton data)
(Unaudited)
Coal production (tons)
 
 
 
 
 
 
 
Appalachia
 
 
 
 
 
 
 
Northern (1)
(356
)

1,518

 
(1,874
)
 
(123
)%
Central
3,348


4,642

 
(1,294
)
 
(28
)%
Southern
683


851

 
(168
)
 
(20
)%
Total Appalachia
3,675


7,011

 
(3,336
)
 
(48
)%
Illinois Basin
2,411


2,722

 
(311
)
 
(11
)%
Northern Powder River Basin
1,318


1,301

 
17

 
1
 %
Gulf Coast
—


361

 
(361
)
 
(100
)%
Total coal production
7,404

 
11,395

 
(3,991
)
 
(35
)%

 
 
 
 
 
 
 
Coal royalty revenue per ton
 
 
 
 
 
 
 
Appalachia
 
 
 
 
 
 
 
Northern
N/A (1)


$
0.50

 
N/A (1)

 
N/A (1)

Central
3.28


3.76

 
(0.48
)
 
(13
)%
Southern
3.83


4.18

 
(0.35
)
 
(8
)%
Illinois Basin
3.63


4.05

 
(0.42
)
 
(10
)%
Northern Powder River Basin
3.27


2.80

 
0.47

 
17
 %
Gulf Coast
—


4.26

 
(4.26
)
 
(100
)%

 
 
 
 
 
 
 
Coal royalty revenues
 
 
 
 
 
 
 
Appalachia
 
 
 
 
 
 
 
Northern (1)
$
370

 
$
763

 
$
(393
)
 
(52
)%
Central
10,994

 
17,440

 
(6,446
)
 
(37
)%
Southern
2,618

 
3,561

 
(943
)
 
(26
)%
Total Appalachia
13,982

 
21,764

 
(7,782
)
 
(36
)%
Illinois Basin
8,745


11,015

 
(2,270
)
 
(21
)%
Northern Powder River Basin
4,314


3,641

 
673

 
18
 %
Gulf Coast
—


1,537

 
(1,537
)
 
(100
)%
Total coal royalty revenue
$
27,041

 
$
37,957

 
$
(10,916
)
 
(29
)%

 
 
 
 
 
 
 
Other revenues
 
 
 
 
 
 
 
Override revenue
$
615


$
433

 
$
182

 
42
 %
Transportation and processing fees
6,127


5,338

 
789

 
15
 %
Minimums recognized as revenue
9,755


3,234

 
6,521

 
202
 %
Lease assignment fee
—


6,000

 
(6,000
)
 
(100
)%
Wheelage
919


401

 
518

 
129
 %
Hard mineral royalty revenues
700


3,118

 
(2,418
)
 
(78
)%
Oil and gas royalty revenues
1,283

 
969

 
314

 
32
 %
Property tax revenue
2,567


2,528

 
39

 
2
 %
Other
(69
)

(12
)
 
(57
)
 
(475
)%
Total other revenues
$
21,897

 
$
22,009

 
$
(112
)
 
(1
)%
Coal royalty and other income
48,938

 
59,966

 
(11,028
)
 
(18
)%
Gain on coal royalty and other segment asset sales
6,425


2,256

 
4,169

 
185
 %
Total coal royalty and other segment revenues and other income
$
55,363

 
$
62,222

 
$
(6,859
)
 
(11
)%
 
 
 
 
 
(1) Northern Appalachia was impacted by a prior period adjustment of 0.5 million tons and less than $0.1 million in royalty revenue primarily related to the Hibbs Run mine that ceased production during 2016. Absent this adjustment, production in the Northern Appalachia region was 0.2 million tons, average revenue per ton was $1.97 and revenue was $0.4 million.



32

Total coal production decreased 4.0 million tons, or 35%, from 11.4 million tons in the three months ended September 30, 2015 to 7.4 million tons in the three months ended September 30, 2016. Total coal royalty revenues decreased $11 million, or 29%, from $38.0 million in the three months ended September 30, 2015 to $27.0 million in the three months ended September 30, 2016. Total production and revenue decreased driven by downward pressure in the coal markets as described above, with Central Appalachian thermal coal producers in particular continuing to face challenges, as their production costs remain high relative to sales prices.

Soda Ash

Revenues and other income related to our equity investment in Ciner Wyoming decreased $1.8 million, or 14%, from $12.6 million in the three months ended September 30, 2015 to $10.8 million in the three months ended September 30, 2016. This decrease is primarily related to (i) higher royalty rates for certain leases, (ii) higher G&A costs from increased investment in information technology and (iii) higher variable costs and DD&A resulting from greater soda ash production quarter-over-quarter. These decreases at Ciner Wyoming were partially offset by increased sale revenue resulting from higher soda ash production quarter-over-quarter.

VantaCore

Revenues and other income related to our VantaCore segment decreased $7.4 million, or 19%, from $39.2 million in the three months ended September 30, 2015 to $31.8 million in the three months ended September 30, 2016. This decrease is primarily due to a decrease in construction aggregates and brokered stone revenue as well as reduced delivery and fuel income quarter-over-quarter. Tonnage sold by the VantaCore segment decreased 0.3 million tons, or 14% from 2.1 million tons in the three months ended September 30, 2015 to 1.8 million tons in the three months ended September 30, 2016 primarily as a result of decreased construction aggregates demand in the oil and gas services sector that was partially offset by increased construction aggregates sales into the construction market.

Operating and Maintenance Expenses (including affiliates)

Operating and maintenance expenses (including affiliates) decreased $4.2 million, or 11%, from $39.5 million in the three months ended September 30, 2015 to $35.3 million in the three months ended September 30, 2016. This decrease is primarily related to the following:

VantaCore

Operating and maintenance expenses (including affiliates) in our VantaCore segment decreased $5.8 million, or 18% from $32.7 million in the three months ended September 30, 2015 to $26.9 million in the three months ended September 30, 2016. This decrease is primarily due to the decline in materials cost as a result of the decrease in construction aggregates and brokered stone sales volume quarter-over-quarter due to reduced demand in the oil and gas sector, a decrease in delivery and fuel costs due to the lower construction aggregates production and brokered stone purchases quarter over quarter and effective variable cost management.

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

DD&A expense decreased $3.6 million, or 22%, from $16.4 million in the three months ended September 30, 2015 to $12.8 million in the three months ended September 30, 2016. This decrease is primarily related to the reduction of the cost basis of our coal and aggregates royalty mineral rights due to the asset impairments recorded in the third and fourth quarters of 2015 and the decline in coal royalty production quarter-over-quarter.

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

Corporate and financing G&A expense (including affiliates) includes corporate headquarters, financing and centralized treasury and accounting. These costs increased $0.9 million, or 21%, from $4.2 million in the three months ended September 30, 2015 to $5.1 million in the three months ended September 30, 2016. This increase is primarily related to increased legal and advisory fees related to the implementation of our long-term plan to strengthen our balance sheet, reduce debt and enhance liquidity.


33

Asset Impairments

Asset impairments decreased $356.0 million, or 98%, from $361.7 million in the three months ended September 30, 2015 to $5.7 million in the three months ended September 30, 2016. This decrease is primarily related to $247.8 million in coal property impairment, $70.5 million in oil and gas property impairment and $43.4 million in hard mineral property impairment recorded during the third quarter of 2015 as compared to $3.8 million in coal property impairment and $1.4 million in hard mineral property impairment recorded during the third quarter of 2016. The impairments in 2015 primarily resulted from the continued deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry.

Income (Loss) from Discontinued Operations

Income from discontinued operations increased $276.4 million, from a loss of $269.3 million in the three months ended September 30, 2015 to income of $7.1 million in the three months ended September 30, 2016. The change in income (loss) from discontinued operations is primarily related to the $265.1 million asset impairment recorded in the third quarter of 2015, the sale of our non-operated oil and gas working interest assets that was completed in July 2016 with an effective date of April 1, 2016 and the $8.5 million gain recorded in the third quarter of 2016.

Adjusted EBITDA (a Non-GAAP Financial Measure)

Adjusted EBITDA is a non-GAAP financial measure that we define as net income (loss) from continuing operations less equity earnings from unconsolidated investment, gain on reserve swaps and income to non-controlling interest; plus distributions from equity earnings in unconsolidated investment, interest expense, depreciation, depletion and amortization and asset impairments.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring items that materially affect our net income (loss), the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by different companies.

Adjusted EBITDA is a supplemental performance measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis.

Adjusted EBITDA decreased $11.5 million, or 16%, from $70.4 million in the three months ended September 30, 2015 to $58.9 million in the three months ended September 30, 2016. The decrease is primarily a result of decreased coal production and coal royalty revenue per ton quarter-over-quarter driven by the continued pressure on U.S. coal producers as described above.


34

The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment for the three months ended September 30, 2016 and 2015:
 
 
Operating Segments
 
 
 
 
For the Three Months Ended
 
Coal Royalty and Other
 
Soda Ash
 
VantaCore
 
Corporate and Financing
 
Total
September 30, 2016
 
 
 
 
 
 
 
 
 
 
Net income (loss) from continuing operations
 
$
32,250

 
$
10,753

 
$
1,039

 
$
(27,623
)

$
16,419

Less: equity earnings from unconsolidated investment
 
—

 
(10,753
)
 
—

 
—


(10,753
)
Add: distributions from unconsolidated investment
 
—

 
12,250

 
—

 
—


12,250

Add: depreciation, depletion and amortization
 
9,070

 
—

 
3,761

 
—


12,831

Add: asset impairments
 
5,697

 
—

 
—

 
—


5,697

Add: interest expense
 
—

 
—

 
—

 
22,491


22,491

Adjusted EBITDA
 
$
47,017

 
$
12,250

 
$
4,800

 
$
(5,132
)
 
$
58,935

 
 
 
 
 
 
 
 
 
 
 
September 30, 2015
 
 
 
 
 
 
 
 
 
 
Net income (loss) from continuing operations
 
$
(318,972
)
 
$
12,617

 
$
2,757

 
$
(27,138
)

$
(330,736
)
Less: equity earnings from unconsolidated investment
 
—

 
(12,617
)
 
—

 
—


(12,617
)
Add: distributions from unconsolidated investment
 
—

 
12,740

 
—

 
—


12,740

Add: depreciation, depletion and amortization
 
12,659

 
—

 
3,778

 
—


16,437

Add: asset impairments
 
361,703

 
—

 
—

 
—


361,703

Add: interest expense
 
—

 
—

 
—

 
22,905


22,905

Adjusted EBITDA
 
$
55,390

 
$
12,740

 
$
6,535

 
$
(4,233
)

$
70,432


35

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

DCF is a non-GAAP financial measure that we define as net cash provided by operating activities of continuing operations, plus returns of unconsolidated equity investments, proceeds from sales of assets, including those included in discontinued operations, and returns of long-term contract receivables—affiliate, less maintenance capital expenditures and distributions to non-controlling interest.

DCF is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities. DCF may not be calculated the same for us as for other companies.

DCF is a supplemental liquidity measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess the Partnership's ability to make cash distributions to our unitholders and our general partner and repay debt.

DCF increased $102.0 million, or 188%, from $54.2 million in the three months ended September 30, 2015 to $156.2 million in the three months ended September 30, 2016. This increase is due primarily to the $109.9 million net cash proceeds from the sale of our discontinued operation, partially offset by lower coal production, lower coal royalty revenue per ton and lower minimum royalty payments received from our coal leases. These decreases are driven by the continued pressure on U.S. coal producers as described above.

The following table (in thousands) presents the three major categories of the statement of cash flows by business segment for the three months ended September 30, 2016 and 2015:
 
 
Operating Segments
 
 
 
 
For the Three Months Ended
 
Coal Royalty and Other
 
Soda Ash
 
VantaCore
 
Corporate and Financing
 
Total
September 30, 2016
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities of continuing operations
 
$
34,997

 
$
12,250

 
$
4,357

 
$
(15,703
)
 
$
35,901

Net cash provided by (used in) investing activities of continuing operations
 
$
10,691

 
$
—

 
$
(434
)
 
$
—

 
$
10,257

Net cash provided by (used in) financing activities of continuing operations
 
$
—

 
$
—

 
$
—

 
$
24,843

 
$
24,843

 
 
 
 
 
 
 
 
 
 
 
September 30, 2015
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities of continuing operations
 
$
40,389

 
$
12,762

 
$
5,841

 
$
(11,818
)
 
$
47,174

Net cash provided by (used in) investing activities of continuing operations
 
$
8,422

 
$
—

 
$
(3,057
)
 
$
—

 
$
5,365

Net cash provided by (used in) financing activities of continuing operations
 
$
—

 
$
—

 
$
—

 
$
(11,678
)
 
$
(11,678
)


36

The following table (in thousands) reconciles net cash provided by operating activities of continuing operations (the most comparable GAAP financial measure) by business segment to DCF for the three months ended September 30, 2016 and 2015:
 
 
Operating Segments
 
 
 
 
For the Three Months Ended
 
Coal Royalty and Other
 
Soda Ash
 
VantaCore
 
Corporate and Financing
 
Total
September 30, 2016
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities of continuing operations
 
$
34,997

 
$
12,250

 
$
4,357

 
$
(15,703
)

$
35,901

Add: return on long-term contract receivables—affiliate
 
397

 
—

 
—

 
—


397

Add: proceeds from sale of PP&E
 
265

 
—

 
78

 
—


343

Add: proceeds from sale of mineral rights
 
10,029

 
—

 
—

 
—


10,029

Add: proceeds from sale of assets included in discontinued operations
 
—

 
—

 
—

 
—

 
109,889

Less: maintenance capital expenditures
 
(5
)
 
—

 
(342
)
 
—


(347
)
DCF
 
$
45,683

 
$
12,250

 
$
4,093

 
$
(15,703
)
 
$
156,212

 
 
 
 
 
 
 
 
 
 
 
September 30, 2015
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities of continuing operations
 
$
40,389

 
$
12,762

 
$
5,841

 
$
(11,818
)

$
47,174

Add: return on long-term contract receivables—affiliate
 
984

 
—

 
—

 
—


984

Add: proceeds from sale of PP&E
 
6,228

 
—

 
1

 
—


6,229

Add: proceeds from sale of mineral rights
 
1,660

 
—

 
—

 
—


1,660

Less: maintenance capital expenditures
 
(329
)
 
—

 
(1,511
)
 
—


(1,840
)
DCF
 
$
48,932

 
$
12,762

 
$
4,331

 
$
(11,818
)
 
$
54,207


Results of Operations

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

Revenues and Other Income

Revenues and other income decreased $21.9 million, or 7%, from $333.8 million in the nine months ended September 30, 2015 to $311.9 million in the nine months ended September 30, 2016. The following table shows our diversified sources of revenues and other income by business segment for the nine months ended September 30, 2016 and 2015 (in thousands except for percentages):
 
 
Coal Royalty and Other
 
Soda Ash
 
VantaCore
 
Total
2016
 
 
 
 
 
 
 
 
Revenues and other income
 
$
193,114

 
$
30,742

 
$
88,091

 
$
311,947

Percentage of total
 
62
%
 
10
%
 
28
%
 
 
2015
 
 
 
 
 
 
 
 
Revenues and other income
 
$
190,004

 
$
36,739

 
$
107,034

 
$
333,777

Percentage of total
 
57
%
 
11
%
 
32
%
 
 

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


37

Coal Royalty and Other

Revenues and other income related to our Coal Royalty and Other segment increased $3.1 million, or 2%, from $190.0 million in the nine months ended September 30, 2015 to $193.1 million in the nine months ended September 30, 2016.

The table below presents coal production and coal royalty revenues (including affiliates) derived from our major coal producing regions and the significant categories of other coal royalty and other revenues:
 
For the Nine Months Ended
September 30,
 
Increase
(Decrease)
 
Percentage
Change
 
2016
 
2015
 
 
(In thousands, except percent and per ton data)
(Unaudited)
Coal production (tons)
 
 
 
 
 
 
 
Appalachia
 
 
 
 
 
 
 
Northern
479


7,581

 
(7,102
)
 
(94
)%
Central
10,046


13,402

 
(3,356
)
 
(25
)%
Southern
2,201


3,000

 
(799
)
 
(27
)%
Total Appalachia
12,726

 
23,983

 
(11,257
)
 
(47
)%
Illinois Basin
6,056


8,265

 
(2,209
)
 
(27
)%
Northern Powder River Basin
2,734


3,497

 
(763
)
 
(22
)%
Gulf Coast
—


778

 
(778
)
 
(100
)%
Total coal production
21,516

 
36,523

 
(15,007
)
 
(41
)%
 
 
 
 
 
 
 
 
Coal royalty revenue per ton
 
 
 
 
 
 
 
Appalachia
 
 
 
 
 
 
 
Northern
$
4.19


$
0.28

 
$
3.91

 
1,396
 %
Central
3.22


3.93

 
(0.71
)
 
(18
)%
Southern
3.37


4.55

 
(1.18
)
 
(26
)%
Illinois Basin
3.57


4.00

 
(0.43
)
 
(11
)%
Northern Powder River Basin
3.04


2.64

 
0.40

 
15
 %
Gulf Coast
—


3.85

 
(3.85
)
 
(100
)%
 
 
 
 
 
 
 
 
Coal royalty revenues
 
 
 
 
 
 
 
Appalachia
 
 
 
 
 
 
 
Northern
$
2,005


$
2,105

 
$
(100
)
 
(5
)%
Central
32,331


52,616

 
(20,285
)
 
(39
)%
Southern
7,419


13,646

 
(6,227
)
 
(46
)%
Total Appalachia
41,755

 
68,367

 
(26,612
)
 
(39
)%
Illinois Basin
21,611


33,020

 
(11,409
)
 
(35
)%
Northern Powder River Basin
8,314


9,219

 
(905
)
 
(10
)%
Gulf Coast
—


2,996

 
(2,996
)
 
(100
)%
Total coal royalty revenue
$
71,680

 
$
113,602

 
$
(41,922
)
 
(37
)%
 
 
 
 
 
 
 
 
Other revenues
—

 
 
 
 
 
 
Override revenue
$
1,482


$
2,195

 
$
(713
)
 
(32
)%
Transportation and processing fees
15,663


16,400

 
(737
)
 
(4
)%
Minimums recognized as revenue
60,455


12,480

 
47,975

 
384
 %
Lease assignment fee
—


6,000

 
(6,000
)
 
(100
)%
Gain on reserve swap
—


9,290

 
(9,290
)
 
(100
)%
Wheelage
1,797


2,117

 
(320
)
 
(15
)%
Hard mineral royalty revenues
2,194


7,552

 
(5,358
)
 
(71
)%
Oil and gas royalty revenues
2,538

 
3,476

 
(938
)
 
(27
)%
Property tax revenue
8,899


8,602

 
297

 
3
 %
Other
1,136


1,363

 
(227
)
 
(17
)%
Total other revenues
$
94,164

 
$
69,475

 
$
24,689

 
36
 %
Coal royalty and other income
165,844

 
183,077

 
(17,233
)
 
(9
)%
Gain on coal royalty and other segment asset sales
27,270


6,927

 
20,343

 
294
 %
Total coal royalty and other segment revenues and other income
$
193,114

 
$
190,004

 
$
3,110

 
2
 %

Total coal production decreased 15.0 million tons, or 41%, from 36.5 million tons in the nine months ended September 30, 2015 to 21.5 million tons in the nine months ended September 30, 2016. Total coal royalty revenues decreased $41.9 million, or 37%, from $113.6 million in the nine months ended September 30, 2015 to $71.7 million in the nine months ended September 30, 2016. Total production and royalty revenue decreased in all of our regions. These decreases are driven by downward pressure in

38

the coal markets, with producers of Central Appalachian thermal coal in particular continuing to face challenges, as their production costs remain high relative to sales prices.

The decrease in coal royalty revenues was partially offset by a $48.0 million increase in minimums recognized as revenues due to several lease modifications and terminations in the second quarter of 2016 as well as a $20.3 million increase in gains on asset sales due to the sales of our oil and gas royalty and aggregates royalty businesses in the first quarter of 2016.

Soda Ash

Revenues and other income related to our equity investment in Ciner Wyoming decreased $6.0 million, or 16%, from $36.7 million in the nine months ended September 30, 2015 to $30.7 million in the nine months ended September 30, 2016. This decrease is primarily related to lower international prices compared to the prior year, in addition to higher royalty and G&A costs. These decreases were partially offset by higher production compared to the prior year.

VantaCore

Revenues and other income related to our VantaCore segment decreased $18.9 million, or 18%, from $107.0 million in the nine months ended September 30, 2015 to $88.1 million in the nine months ended September 30, 2016. This decrease is primarily due to a decrease in construction aggregates and brokered stone revenue as well as lower delivery and fuel income year-over-year. Tonnage sold by the VantaCore segment decreased 0.7 million tons, or 12% from 5.7 million tons in the nine months ended September 30, 2015 to 5.0 million tons in the nine months ended September 30, 2016 as a result of decreased construction aggregates demand in the oil and gas services sector that was partially offset by increased aggregates sales into the construction market.

Operating and Maintenance Expenses (including affiliates)

Operating and maintenance expenses (including affiliates) decreased $16.6 million, or 15%, from $114.4 million in the nine months ended September 30, 2015 to $97.8 million in the nine months ended September 30, 2016. This decrease is primarily related to the following:

VantaCore

Operating and maintenance expenses (including affiliates) in our VantaCore segment decreased $17.2 million, or 19% from $90.7 million in the nine months ended September 30, 2015 to $73.5 million in the nine months ended September 30, 2016. This decrease is primarily due to the decline in materials cost as a result of the decrease in construction aggregates and brokered stone volume year-over-year due to reduced demand in the oil and gas sector and a decrease in delivery and fuel costs due to the lower construction aggregates production and brokered stone purchases year-over-year partially and effective variable cost management.

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

DD&A expense decreased $12.5 million, or 27%, from $47.0 million in the nine months ended September 30, 2015 to $34.5 million in the nine months ended September 30, 2016. This decrease is primarily related to the reduction in the cost basis of our coal and aggregates royalty mineral rights due to the asset impairments recorded in the third and fourth quarters of 2015 and the decline in coal royalty production year-over-year.
General and Administrative (including affiliates) ("G&A") Expense

Corporate and financing G&A expense (including affiliates) includes corporate headquarters, financing and centralized treasury and accounting. These costs increased $3.5 million, or 36%, from $9.8 million in the nine months ended September 30, 2015 to $13.3 million in the nine months ended September 30, 2016. This increase is primarily related to increased legal and consulting fees related to the implementation of our long-term plan to strengthen our balance sheet, reduce debt and enhance liquidity.


39

Asset Impairments

Asset impairments decreased $357.8 million, or 98%, from $365.5 million in the nine months ended September 30, 2015 to $7.7 million in the nine months ended September 30, 2016. This decrease is primarily related to $249.4 million in coal property impairment, $70.5 million in oil and gas property impairment and $43.4 million in hard mineral property impairment recorded during the first nine months 2015 as compared to $3.9 million in coal property impairment and $1.7 million in hard mineral property impairment recorded during the first nine months of 2016. The impairments in 2015 primarily resulted from the continued deterioration and expectations of further reductions in global and domestic coal demand due to reduced global steel demand, sustained low natural gas prices, and continued regulatory pressure on the electric power generation industry.

Income (Loss) from Discontinued Operations

Income from discontinued operations increased $282.0 million, from a loss of $280.0 million in the nine months ended September 30, 2015 to income of $2.0 million in the nine months ended September 30, 2016. The change in income (loss) from discontinued operations is primarily related to the $265.1 million asset impairment recorded in the third quarter of 2015, the sale of our non-operated oil and gas working interest assets that was completed in July 2016 with an effective date of April 1, 2016 and the $8.3 million gain on sale for the nine months ended September 30, 2016.

Adjusted EBITDA (a Non-GAAP Financial Measure)

Adjusted EBITDA increased $6.3 million, or 3%, from $198.1 million in the nine months ended September 30, 2015 to $204.4 million in the nine months ended September 30, 2016. The increase is primarily a result of $48.0 million increase in minimums recognized as revenue primarily as a result of coal lease modifications or terminations that resulted in our lessee forfeiting their minimum royalty balances. Adjusted EBITDA also increased due to $20.4 million of additional gains on asset sales as compared to the same period in 2015. These increases were partially offset $41.9 million in reduced coal royalty revenue resulting from decreased in coal production and coal royalty revenue per ton driven by the continued pressure on U.S. coal producers as described above, a $6.0 million non-recurring 2015 lease assignment fee and $5.4 million of reduced aggregates royalty revenue in 2016 due to decreased 2016 aggregates production and sales. In addition, this increase was partially offset by $3.5 million of additional G&A expense in the first nine months of 2016 compared to 2015 as described above.


40

The following table (in thousands) reconciles net income (loss) from continuing operations (the most comparable GAAP financial measure) to Adjusted EBITDA by business segment for the nine months ended September 30, 2016 and 2015:
 
 
Operating Segments
 
 
 
 
For the Nine Months Ended
 
Coal Royalty and Other
 
Soda Ash
 
VantaCore
 
Corporate and Financing
 
Total
September 30, 2016
 
 
 
 
 
 
 
 
 
 
Net income (loss) from continuing operations
 
$
137,802

 
$
30,742

 
$
3,441

 
$
(80,582
)

$
91,403

Less: equity earnings from unconsolidated investment
 
—

 
(30,742
)
 
—

 
—


(30,742
)
Add: distributions from unconsolidated investment
 
—

 
34,300

 
—

 
—


34,300

Add: depreciation, depletion and amortization
 
23,496

 
—

 
11,013

 
—


34,509

Add: asset impairments
 
7,681

 
—

 
—

 
—


7,681

Add: interest expense
 
—

 
—

 
—

 
67,265


67,265

Adjusted EBITDA
 
$
168,979

 
$
34,300

 
$
14,454

 
$
(13,317
)
 
$
204,416

 
 
 
 
 
 
 
 
 
 
 
September 30, 2015
 
 
 
 
 
 
 
 
 
 
Net income (loss) from continuing operations
 
$
(233,803
)

$
36,739


$
3,879


$
(76,783
)

$
(269,968
)
Less: equity earnings from unconsolidated investment
 
—


(36,739
)

—


—


(36,739
)
Less: gain on reserve swap
 
(9,290
)

—


—


—


(9,290
)
Add: distributions from unconsolidated investment
 
—


34,545


—


—


34,545

Add: depreciation, depletion and amortization
 
34,529


—


12,499


—


47,028

Add: asset impairments
 
365,506


—


—


—


365,506

Add: interest expense
 
—


—


—


66,976


66,976

Adjusted EBITDA
 
$
156,942

 
$
34,545

 
$
16,378

 
$
(9,807
)
 
$
198,058


41

DCF (a Non-GAAP Financial Measure)

DCF increased $96.2 million, or 68%, from $142.5 million in the nine months ended September 30, 2015 to $238.7 million in the nine months ended September 30, 2016. This increase is due primarily to the $109.9 million net cash proceeds from the sale of our discontinued operation in addition to $54.2 million in net cash proceeds from sales of mineral rights in 2016. These increases were partially offset by lower coal royalty production, lower coal royalty revenue per ton and less minimum payments received from our coal leases. These decreases are driven by the continued pressure on U.S. coal producers as described above.

The following table (in thousands) presents the three major categories of the statement of cash flows by business segment for the nine months ended September 30, 2016 and 2015:
 
 
Operating Segments
 
 
 
 
For the Nine Months Ended
 
Coal Royalty and Other
 
Soda Ash
 
VantaCore
 
Corporate and Financing
 
Total
September 30, 2016
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities of continuing operations
 
$
91,372

 
$
34,300

 
$
16,680

 
$
(67,805
)
 
$
74,547

Net cash provided by (used in) investing activities of continuing operations
 
$
57,834

 
$
—

 
$
(4,324
)
 
$
—

 
$
53,510

Net cash provided by (used in) financing activities of continuing operations
 
$
—

 
$
(7,229
)
 
$
(1,593
)
 
$
(68,047
)
 
$
(76,869
)
 
 
 
 
 
 
 
 
 
 
 
September 30, 2015
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities of continuing operations
 
$
149,841

 
$
30,778

 
$
19,783

 
$
(68,211
)
 
$
132,191

Net cash provided by (used in) investing activities of continuing operations
 
$
15,546

 
$
—

 
$
(7,417
)
 
$
—

 
$
8,129

Net cash provided by (used in) financing activities of continuing operations
 
$
(2,744
)
 
$
—

 
$
—

 
$
(136,882
)
 
$
(139,626
)


42

The following table (in thousands) reconciles net cash provided by operating activities (the most comparable GAAP financial measure) by business segment to DCF for the nine months ended September 30, 2016 and 2015:
 
 
Operating Segments
 
 
 
 
For the Nine Months Ended
 
Coal Royalty and Other
 
Soda Ash
 
VantaCore
 
Corporate and Financing
 
Total
September 30, 2016
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities of continuing operations
 
$
91,372


$
34,300


$
16,680


$
(67,805
)

$
74,547

Add: return on long-term contract receivables—affiliate
 
2,577


—


—


—


2,577

Add: proceeds from sale of PP&E
 
1,084


—


102


—


1,186

Add: proceeds from sale of mineral rights
 
54,178


—


—


—


54,178

Add: proceeds from sale of assets included in discontinued operations
 
—

 
—

 
—

 
—

 
109,889

Less: maintenance capital expenditures
 
(5
)

—


(3,671
)

—


(3,676
)
DCF
 
$
149,206


$
34,300


$
13,111


$
(67,805
)

$
238,701

 
 
 
 
 
 
 
 
 
 
 
September 30, 2015
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities of continuing operations
 
$
149,841

 
$
30,778

 
$
19,783

 
$
(68,211
)

$
132,191

Add: return on long-term contract receivables—affiliate
 
2,121

 
—

 
—

 
—


2,121

Add: proceeds from sale of PP&E
 
10,578

 
—

 
906

 
—


11,484

Add: proceeds from sale of mineral rights
 
3,505

 
—

 
—

 
—


3,505

Less: maintenance capital expenditures
 
(329
)
 
—

 
(3,749
)
 
—


(4,078
)
Less: distributions to non-controlling interest
 
(2,744
)
 
—

 
—

 
—


(2,744
)
DCF
 
$
162,972

 
$
30,778

 
$
16,940

 
$
(68,211
)
 
$
142,479


Liquidity and Capital Resources

Overview

For an overview of our liquidity and related matters, see "—Executive Overview—Current Liquidity, Management's Forecast and Going Concern Analysis." Generally, we satisfy our working capital requirements with cash generated from operations. Our current liabilities exceeded our current assets by approximately $50.3 million as of September 30, 2016, primarily due to $81.0 million in total principal payments on the Opco Senior Notes and $80.0 million of payments on the Opco Credit Facility. Excluding these payments, net of their unamortized debt issue costs, our current assets exceeded our current liabilities by approximately $108.3 million as of September 30, 2016.

Capital Expenditures

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


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Cash Flows

Cash flow provided by operating activities decreased $78.7 million, from $161.4 million in the nine months ended September 30, 2015 to $82.7 million in the nine months ended September 30, 2016. Operating cash flow from continuing operations decreased $58.5 million in our Coal Royalty and Other segment year-over-year primarily as a result of the reduction in coal royalty revenue and reduction of coal royalty minimum cash payments received on certain leases. Cash flow provided by operating activities of discontinued operations decreased $21.0 million, from $29.2 million in the nine months ended September 30, 2015 to $8.2 million in the nine months ended September 30, 2016 primarily as a result of completing the sale of our non-operated oil and gas working interest assets in July 2016 that had an effective date of April 1, 2016.

Cash flow provided by investing activities increased $184.8 million, from $24.5 million cash used in investing activities in the nine months ended September 30, 2015 to $160.3 million cash provided by investing activities in the nine months ended September 30, 2016. Investing cash flows from discontinued operations increased $139.4 million primarily as a result of the sale of our non-operated oil and gas working interest assets in July 2016 for $109.9 million in net cash proceeds. Investing cash flows from continuing operations increased $45.4 million primarily as a result of 2016 sales of royalty properties as described in Note 6. Mineral Rights to the consolidated financial statements.

Cash flow used in financing activities increased $76.6 million, from $125.8 million cash used in financing activities in the nine months ended September 30, 2015, to $202.4 million cash used in financing activities in the nine months ended September 30, 2016. Cash used in financing activities of discontinued operations increased $139.4 million primarily as a result of using $85.0 million to repay the RBL Credit Facility and contributing the $40.2 million of discontinued asset sales proceeds that remained after repayment of the RBL Facility in full to continuing operations. This $139.4 million increase in cash flow used in financing activities was partially offset by a $62.8 million decrease in cash flow used in financing activities from continuing operations. This decrease is primarily a result of distributing $49.3 million less cash to partners and receiving the remaining net proceeds from discontinuing operations after repayment as described above.

Capital Resources and Obligations

Indebtedness

As of September 30, 2016 and December 31, 2015 we had the following indebtedness (in thousands):
 
September 30,
2016
 
December 31,
2015
Current portion of long-term debt, net
$
158,597

 
$
80,745

Long-term debt, net (including affiliate)
1,041,984

 
1,206,611

Total debt, net (including affiliate)
$
1,200,581

 
$
1,287,356


We were and continue to be in compliance with the terms of the financial covenants contained in our debt agreements. For additional information regarding our debt and the agreements governing our debt, including the covenants contained therein, see Note 8. Debt and Debt—Affiliate to the consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q.

Shelf Registration Statement

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

Off-Balance Sheet Transactions

We do not have any off-balance sheet arrangements with unconsolidated entities or related parties and accordingly, there are no off-balance sheet risks to our liquidity and capital resources from unconsolidated entities.


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Related Party Transactions

The information required set forth under Note 10. Related Party Transactions to the consolidated financial statements under the caption "Related Party Transactions" is incorporated herein by reference.

Summary of Critical Accounting Estimates

The preparation of consolidated financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. There have been no significant changes to our critical accounting estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015.

Recent Accounting Standards

The information set forth under Note 1. Basis of Presentation to the consolidated financial statements under the caption "Basis of Presentation" is incorporated herein by reference.


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, which includes adverse changes in commodity prices and interest rates as discussed below:

Commodity Price Risk

We are dependent upon the effective marketing of the coal mined by our lessees. Our lessees sell the coal under various long-term and short-term contracts as well as on the spot market. Current conditions in the coal industry may make it difficult for our lessees to extend existing contracts or enter into supply contracts with terms of one year or more. Our lessees’ failure to negotiate long-term contracts could adversely affect the stability and profitability of our lessees’ operations and adversely affect our coal royalty revenues. If more coal is sold on the spot market, coal royalty revenues may become more volatile due to fluctuations in spot coal prices.
We have market risk related to prices for our aggregates products. Aggregates prices are primarily driven by economic conditions in the local markets in which the products are sold.
The market price of soda ash directly affects the profitability of Ciner Wyoming’s operations. If the market price for soda ash declines, Ciner Wyoming’s sales will decrease. Historically, the global market and, to a lesser extent, the domestic market for soda ash have been volatile, and those markets are likely to remain volatile in the future.

Interest Rate Risk

Our exposure to changes in interest rates results from our borrowings under our revolving credit facility and term loan, which are subject to variable interest rates based upon LIBOR. At September 30, 2016, we had $260.0 million outstanding in variable interest rate debt. If interest rates were to increase by 1%, annual interest expense would increase approximately $2.6 million, assuming the same principal amount remained outstanding during the year.


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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Changes in the Partnership’s Internal Control Over Financial Reporting

There were no changes in the Partnership’s internal control over financial reporting during the first nine months of 2016 that materially affected, or were reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

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PART II
 
ITEM 1. LEGAL PROCEEDINGS

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, we believe these claims will not have a material effect on our financial position, liquidity or operations.

For more information regarding certain other legal proceedings involving the Partnership, see Note 11. "Commitments and Contingencies" to the consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q, which is incorporated herein by reference.

ITEM 1A. RISK FACTORS

During the period covered by this report there were no material changes from the risk factors previously disclosed in Natural Resource Partners L.P.’s Annual Report on Form 10-K for the year ended December 31, 2015.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None. 

ITEM 4. MINE SAFETY DISCLOSURES

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

ITEM 5. OTHER INFORMATION

None.


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ITEM 6. EXHIBITS
Exhibit
Number
 
Description
2.1
 
Purchase Agreement, dated as of January 23, 2013, by and among Anadarko Holding Company, Big Island Trona Company, NRP Trona LLC and NRP (Operating) LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on January 25, 2013).
2.2
 
Purchase and Sale Agreement dated as of June 13, 2016 by and between NRP Oil and Gas LLC and Lime Rock Resources IV-A, L.P (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on June 15, 2016).
3.1
 
Certificate of Limited Partnership of Natural Resource Partners L.P.(incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 filed April 19, 2002, File No. 333-86582).
3.2
 
Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P., dated as of September 20, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on September 21, 2010).
3.3
 
Fifth Amended and Restated Limited Liability Company Agreement of GP Natural Resource Partners LLC dated as of October 31, 2013 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed on October 31, 2013).
4.1
 
First Amendment, dated March 6, 2012, to the Fourth Amended and Restated Agreement of Limited Partnership of Natural Resource Partners L.P. (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q filed on August 7, 2012).
4.2
 
Fourth Amendment, dated as of September 9, 2016, to Note Purchase Agreements, dated as of June 19, 2003, among NRP (Operating) LLC and the holders named therein (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on September 12, 2016).
31.1*
 
Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley.
31.2*
 
Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.
32.1**
 
Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.
32.2**
 
Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.
95.1*
 
Mine Safety Disclosure.
101.INS*
 
XBRL Instance Document
101.SCH*
 
XBRL Taxonomy Extension Schema Document
101.CAL*
 
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*
 
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*
 
XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*
 
XBRL Taxonomy Extension Presentation Linkbase Document
 
 
 
*
 
Filed herewith
**
 
Furnished herewith



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

 
NATURAL RESOURCE PARTNERS L.P.
 
By:
 
NRP (GP) LP, its general partner
 
By:
 
GP NATURAL RESOURCE
 
 
 
PARTNERS LLC, its general partner
 
 
 
 
Date: November 7, 2016
By:
 
/s/ CORBIN J. ROBERTSON, JR.      
 
 
 
Corbin J. Robertson, Jr.
 
 
 
Chairman of the Board and
 
 
 
Chief Executive Officer
 
 
 
(Principal Executive Officer)
Date: November 7, 2016
By:
 
/s/ CRAIG W. NUNEZ      
 
 
 
Craig W. Nunez
 
 
 
Chief Financial Officer and
 
 
 
Treasurer
 
 
 
(Principal Financial Officer)
Date: November 7, 2016
By:
 
/s/ CHRISTOPHER J. ZOLAS
 
 
 
Christopher J. Zolas
 
 
 
Chief Accounting Officer
 
 
 
(Principal Accounting Officer)


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